Aramco_journal Of Technology 381716

Winter 2010

Saudi Aramco

A quarterly publication of the Saudi Arabian Oil Company

Contents

Wireline Well Tractor Technology Experience in Extended Reach Horizontal Wells

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Alaa S. Shawly, Muhammad H. Al-Buali, Mohammed R. Al-Omran, Walid K. Al-Guraini, Alla A. Dashash, Nawawi A. Ahmad, Haider Al-Khamees, Nasser Al-Awami and Juan Torne

Use of Gyro-MWD Technology Offshore, a Step Change in Drilling Performance in Saudi Aramco 12 Bashaar A. Al-Idi, Hasan F. Al-Sarrani, Jeff Stewart, Abhijeet Sarka and Geoff Smith

Stimulation with Innovative Fluid-Placement Methodology and the World’s First Production Logging with Fiber Optic Enabled Coiled Tubing (CT) 17 Mubarak A. Al-Dhufairi, Khalid Al-Omairen, Saleh Al-Ghamdi, Vidal Noya, Jan Jacobsen, Samer Al-Sarakbi, Adnan Ghani Abdulkarim and Abdul Wahab Azrak

Successful Exploitation of the Khuff-B Low Permeability Gas Condensate Reservoir through Optimized Development Strategy 26 Dr. Zillur Rahim, Dr. Hamoud A. Al-Anazi, Adnan A. Al-Kanaan and Ahmad Azly Abdul Aziz

Detection of Drag Reducing Agents (DRAs) in Fuels Using Laser Induced Fingerprints 34 Dr. Ezzat M. Hegazi

Application of an Innovative Ceramic Centralizer for a Solid Expandable Liner 38 Dr. Shaohua Zhou, Syed Mohammed Mansoor Kamal and Tom Sanders

Production Enhancement of Hilly Terrain Onshore Remote Fields 45 Shadi M. Hanbzazah, Mohammed N. Merwat and Dr. Mohammed N. Al-Khamis

Use of XRD and XRF Techniques to Determine the Chemical Composition and Crystallite Size of Metal Matrix Composite Materials 50 Dr. Shouwen Shen, Dr. Husin Sitepu, Saud A. Al-Hamoud, Dr. Ihsan M. Al-Taie, Dr. Gasan Alabedi, Dr. Abdullah A. Al-Sharani and Bander F. Al-Daajani

Effective Strategies in Development of Heterogeneous Gas Condensate Carbonate Reservoirs 56 Dr. Hamoud A. Al-Anazi, Ahmad M. Al-Baqawi, Ahmad Azly Abdul Aziz and Adnan A. Al-Kanaan

Who Is an Inventor and What Is an Invention? Dr. Rashid Khan

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Journal of Technology

THE SAUDI ARAMCO JOURNAL OF TECHNOLOGY

Wireline Well Tractor Technology Experience in Extended Reach Horizontal Wells Authors: Alaa S. Shawly, Muhammad H. Al-Buali, Mohammed R. Al-Omran, Walid K. Al-Guraini, Alla A. Dashash, Nawawi A. Ahmad, Haider Al-Khamees, Nasser Al-Awami and Juan Torne

ABSTRACT Horizontal wells drilled with extended reach in Ghawar field have significantly improved hydrocarbon production. Over the life of such wells, intervention work is necessary to maintain hydrocarbon production by conducting remedial action, such as acid stimulation or water shut-off. Necessary data for decision making can be obtained through running surveillance tools, which has proven to be a challenge, considering that these sensors have to be deployed to total depth (TD). Many well intervention methods have been developed over time to overcome these challenges, such as coiled tubing (CT) and several types of wireline tractors. Wireline tractor technology has evolved to reduce time and cost, improve data quality and increase wellbore coverage. The use of a wireline tractor requires fewer personnel on the job, much less equipment and less lifting of heavy loads, resulting in a smaller footprint impacting the environment. In addition, the fast rig up of the wireline tractor and the greater running in hole (RIH) and pulling out of hole (POOH) speeds cut down on operating time. This article will describe horizontal logging experience gained from trial testing a new deployment solution for the production logging tool (PLT). A new generation of wireline tractors was utilized successfully to deploy the PLT for the first time in a Saudi Arabian field. The tractor showed exceptional performance and proved its capability to overcome different challenging wellbore conditions, such as rugosity, washouts and high dogleg severity (DLS). Moreover, the tractor was able to efficiently through very short sections with large changes in inclination and azimuth. This article also covers the whole cycle of candidate selection, job design, execution challenges, post job evaluation, lessons learned and experience gained to optimize similar future jobs.

INTRODUCTION In highly deviated and horizontal wells, the rigless operation to deploy production logging tools (PLTs) in the horizontal section has long been challenging. In the early 1990s, the only deployment technique was limited to the use of coiled tubing

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(CT) with an inserted logging cable technology1, 2. The expansion of drilling horizontal wells increased the need for new technology development to perform cost-effective well services and deploy logging tools. At the beginning of this century, an important development of technology led to deploying the tools using a mechanical robotic device (electromechanical) powered by the logging cable. Later, electro- hydraulic (wireline wheel tractor) technology was developed to meet the demands of operators worldwide. This wheel tractor has been further developed to deploy tools in a wide range of hole diameters for distinct purposes, such as open hole applications3-6. Anti-spin valves, equal distribution of arm forces against the formation and fixable wheels opened the window for the wireline tractoring operations in Ghawar field to deploy the PLT in extended reach open hole horizontal wells7. Several factors should be taken into consideration before choosing the proper deployment technique for a PLT in extended reach and open hole horizontal wells. Those factors are coverage, operation time, health, safety, environment and data quality. In our case, the CT deployment technique had several limitations, mainly in open hole coverage and logging data quality, due to the restriction caused by the CT size. These limitations made it necessary to search for an alternative solution to perform rigless logging operations in a more effective way. To find this solution, a multidisciplinary team was formed from Production Engineering, Reservoir Description Engineering, the Well Intervention group and service providers. The team decided to try the new generation of wireline tractors to deploy the multiphase production logging tool (MPLT) for the first time in a Saudi Arabian field in an open hole, extended reach horizontal completion.

ACTUAL CASE: WELL COMPLETION AND HISTORY Well X is an oil producer with a horizontal section of around 5,000 ft. It was completed with 4½” tubing in a 7” casing tailed with 3,500 ft of 61⁄8” open hole to a total depth (TD) of 11,720 ft with a maximum deviation of 93°. Initially, the well was producing at 0% water cut. After a year, the water cut started to increase gradually, up to 34% over a period of time. Therefore, it was decided to run a MPLT to evaluate the well performance, detect the water

entry zones and plan for proper remedial action to minimize water cut and maintain production.

JOB PLANNING To plan this job, model simulations were carried out using a dedicated software package that considers several pieces of wellbore and production data. This data includes inclination survey, azimuth, minimum restriction, friction and drag forces. Accordingly, the software can calculate the pickup/slack-off weights, the dogleg severity (DLS) profile and the recommended weak point selection for the wireline cable. The simulations indicated that only 80% of the horizontal interval can be covered utilizing 2.375” CT before lockup occurs. The CT simulator considers the well parameters and downhole conditions as well as friction forces exerted on the CT while deploying the PLT string into and out of the wellbore. Normally, standard friction coefficients (average 0.38) and standard deployment conditions are used for simulation. Moreover, the possible lockup point can be determined when the CT weight falls below the minimum safe limits (avg. 5,000 lbf - 6,000 lbf) while tripped in, Fig. 1. Wireline tractor simulations, on the other hand, showed that the well tractor would be able to run the PLT in hole, all the way from hang up depth to TD, and pull out of hole (POOH) safely with no force issues. Knowing the type and weight of the tool and cable is also important to produce accurate predictions. With this data, the model can estimate the force required by the tractor to convey the tool string all the way to TD. For this particular well, the simulator calculated that the force required by the tractor to deploy the MPLT to TD was 400 lbs. Maximum pull tension required at TD was also within the limit of the 5/16” cable used for this operation, Fig. 2.

FACTORS LED TO WIRELINE TRACTOR UTILIZATION For this particular well, several factors led to the choice of using a wireline tractor rather than the conventional means of PLT deployment normally used in Saudi Arabia. Those factors are:

Fig. 2. Well intervention simulation for 3.125” wireline tractor.

Coverage

The well intervention simulator showed that the wireline tractor is able to achieve 100% open hole coverage by deploying the PLT to TD, while the maximum coverage of the 23⁄8” CT (the largest size available in Saudi Arabia) is 80%. Time

Saving time in the deployment of the PLT using a tractor was an advantage throughout the entire operation. This was clear in the simple and fast mobilization, and reduced rig up and rig down time compared to CT time. Another benefit was the ability to RIH and POOH with wireline speeds, which is a bonus in the event of any failure of downhole equipment. Health, Safety and Environment (HSE)

HSE is the first priority when executing any type of operation (including personnel and equipment). Therefore, many key factors should be considered during the job execution to ensure safety compliance. Risk associated with similar operations has been reduced extensively as a result of optimizing the required equipment, field personnel, and heavy lifting activities. Consequently, the environmental impact has been effectively reduced through the more efficient operating time, the lighter equipment needed and the zero disposal requirement for contaminated fluid. Data Quality

Wireline deployment minimizes the disturbance of the downhole flowing conditions, which leads to better data quality. When acquiring data, logging speed plays a big role in the data quality. The controlled speed of the wireline is an advantage while logging the well. In addition, the tool movement is more uniform/smooth and less force is applied over the tool, resulting in improved data acquisition quality. Challenges

Fig. 1. Well intervention simulation for 2.375” CT.

Generally, there are several challenges to the successful implementation of horizontal logging jobs using the wireline tractor SAUDI ARAMCO JOURNAL OF TECHNOLOGY

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method. The challenge is greater in the open hole logging than cased hole logging. This is due to the open hole conditions, such as geometrical variety and extended washouts and restrictions. In this particular case, several challenges emerged during the preparation phase of the job. Following are the main challenges encountered, along with their technical solutions: • X-Y caliper and image log quality. One of the main challenges associated with the planning of this logging job was the lack of recent X-Y caliper data. The caliper data was essential to identifing wellbore geometry and understanding the severity of the existing washout. This data was required to determine the effective number of tractor wheel sections that would be sufficient to convey the logging tool to TD with the shortest possible tool length. To obtain a representative wellbore geometry, the ultrasonic reading from an open hole image log conducted during the drilling operation was reviewed. Another challenge then appeared: the low quality of the image log (no useful information could be obtained) because of hole rugosity effects, Fig. 3a, (before processing). Therefore, post-acquisition processing (applying speed, sticking and/or dead-button corrections) was utilized to enhance the image log, Fig. 3a, (after processing). Based on that, three wheel sections were utilized. • Open hole irregularity. In this particular case, it was observed from the processed ultrasonic image log that the horizontal open hole section was noticeably irregular. Irregularity in the cross section of the wellbore will exert extra torque force on the well tractor arms while tractoring. The tractor tool used for this operation was designed to adjust itself to ensure an equal torque distribution on each arm. The equalization of force minimizes the effect of the wellbore shape. This important technical feature was added for open hole applications.

Fig. 3b. Well X trajectory profile.

Fig. 3c. Well inclination profile.

• High DLS. Deviation surveys of the well indicated high DLS in the wellbore, as can be seen in Figs. 3b, 3c and 3d. The presence of high DLS and a complex well trajectory is considered to be a challenge for tool deployment since they restrict the tool string’s rigid length and diameter. This challenge was overcome by adding flexible accessories,

Fig. 3d. DLS.

such as swivel and knuckle ts, to the tool string to improve its rotational and axial movement capability. All modifications in the tool string were clearly integrated into a simulation program to simulate the actual job, using all available wellbore data, to ensure the tool’s capability to through all high DLS sections in the wellbore.

Fig. 3a. Image log.

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• Multiple logging runs. The objective of the job was to acquire well production data at two different surface choke settings during flowing es, in addition to one

logging during shut-in conditions. Given the 4,000 ft horizontal interval, more than 12,000 ft of open hole tractoring was required to complete the job. These multiple runs could affect the performance of the tractor because of the long traveling distance under bad wellbore conditions. As a precaution, an extensive test was performed at the yard to accurately simulate the actual job and ensure the tractor’s technical capability to perform the job without any operational problems or on-the-job maintenance requirements.

DESCRIPTION AND APPLICATION OF EQUIPMENT AND PROCESSES The Multiphase Production Tool

The MPLT consists of multiple conventional sensors, including an X-Y caliper and special sensors to determine the flow profile in inclined and horizontal wells, arranged in an array of capacitance hold up sensors and an array of miniature spinners. Capacitance and spinner array PLTs are being used worldwide for horizontal production logging applications. The design of those tools enables cross-sectional radial measurements that overcome the problem of partial analysis of the fluid volume and fluid entries in horizontal undulating wellbores. The fluid hold up is measured using an array of up to 13 capacitance sensors in the string (12 organized around the borehole and one in the center of the pipe) with bow springs that open outward from the tool body to the casing. Sensors attached to the bow springs and provide capacitance measurements to determine the fluid surrounding each sensor (oil, gas and water), Fig. 4.

The spinner array tool incorporates six miniature spinners, which are deployed toward the inside diameter (ID) of the tubing via bow springs. The spinner bodies, which are clipped onto the bow springs, are used to obtain a distributed crosssectional velocity profile in highly deviated wells, leading to the determined fluid flow rate, Fig. 5. All measurements are combined using special software to provide a flow profile map, Fig. 6. Tractor Mechanism

The wireline tractor has an electrical wireline device that can deploy any wireline tool string from a certain hang up depth (usually between 60° and 65° for wireline) all the way to TD across the horizontal section. The wireline tractor uses the electrical wireline to power up, then drives itself using a hydraulic system. A motor section powers the hydraulic pump section, which in turn starts extending the tractor’s arms out of the tool’s body and rotating the wheels for forward movement. As soon as the tractor arms start touching the walls of the casing or the open hole, the tractor tool centers itself by distributing the forces of the arms accordingly on the wellbore. Each wheel is ed by a built-in spring that acts as a fail-safe option to retract the tractor’s arms in case of emergency and to provide the ability to pull the tool string out freely with no restriction from the tractor side. The wheels of the tractor start rotating as soon as the arms start extending. This provides a huge advantage in negotiating washouts and restrictions or when the tool string gets stuck in the open hole. The process of ing restrictions is performed by simply powering the tool down and then up while applying proper cable tension. Anti-spin valves prevent the wheels from free spinning when tractoring is lost in large

Fig. 4. Capacitance array tool.

Fig. 5. Spinner array tool.

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Fig. 6. Software flow profile map.

washouts. Because of these valves, the overall hydraulic force of the system is not dissipated when a wheel loses with the wellbore. A standard wireline well tractor tool string in normal operations consists of the following segments, Fig. 7. 1. Top connector provides the mechanical and electrical connection between the cable head and the tractor. 2. Electronic section provides control and power as well as switching power between the tractor and the tool below. 3. Electronic motor powers the hydraulic pump section, which in turn extends and retracts the arms and rotates the wheels for forward movement of the tractor. 4. Wheel sections. The tractor can have up to five wheel sections. The configuration is decided depending on hole size, DLS, power and speed requirements. Each wheel section is phased (rotated) 90° in relation to the adjacent section. Every wheel section has two integrated wheels to propel the tractor. 5. Compensator equalizes the pressure between downhole hydrostatic pressure and inside housing tool pressure. 6. Bottom connector provides the mechanical and electrical connection to the tools (if any) below the tractor. The tractor tool string configuration varies from job to job. Deciding on the configuration of the tractor for a certain operation will depend mainly on certain information, such as the well parameters, DLS and type of cable and tool string to

Fig. 7. Eight basic segemnts for three wheel section 3.125” OD tractor configuration.

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be deployed. That information is important for determining the maximum pull force required by the tractor to successfully reach TD. The type and size of the well tractor will be decided by the maximum pull required by the tractor, minimum restriction and X-Y caliper data of the well, if available. Taking into consideration previously mentioned inputs and outputs, simulation results in this case showed that both a 2.125” and a 3.125” well tractor were capable of doing the job. With a minimum restriction of 3.725” and DLS of 7.23°/100 ft, the decision was made that the 3.125” tractor (including proper accessories: i.e., knuckle and swivel) was more desirable to do the job. It would assure proper expansion of the tractor’s arm in case big washouts were encountered.

SURFACE PULL AND INTEGRITY TESTS A routine surface pull test of a basic 3.125” tractor with a three wheel section configuration showed it capabile of providing up to 1,200 lbs (four times greater than required pull) at about 2,400 ft/hr tractoring speed. A surface integrity test was performed prior to the job to ensure the tractor/PLT tools compatibility and perform any proper tool modifications, if required. The surface integrity test is a mandatory pre-job requirement for any operation. Tractor/PLT main and backup tool strings were checked, including all necessary accessories, i.e., knuckles and swivels. It is important to detect and eliminate any issue that might arise with any part of the tool string during the operation.

JOB EXECUTION AND FINDINGS Dummy Run

This was the first intervention into the well. The objective of this run was to ensure wellbore accessibility and assess the wireline tractor’s ability to reach the required depth. For this purpose, a dummy tool equivalent to the actual MPLT in of dimension and weight was run with a 3¼” outside diameter (OD) tractor. The dummy run indicated that the wireline tractor could deploy the MPLT tool string into the open hole section and

reach TD. Moreover, the post dummy run simulation result for wireline tension vs. depth was almost identical to the prejob simulation, Fig. 8. Flowing es

The main purpose of running the MPLT is to identify oil and water entry zones and cross flow (if any) across the entire open hole interval. At the beginning, the well was flowed at a 90/64” restricted choke setting, but it couldn’t sustain flow to the plant. Well production was restored by increasing the choke setting to 102/64”. Two flowing es were performed at the same choke setting. This is one advantage of using a wireline tractor instead of a CT deployment; the latter eliminates any wellbore restriction that leads to killing the well in case of high water cut production. More than 8,500 ft of traveling distance was achieved successfully using the wireline tractor with an average speed of 35 ft/min (maximum recorded speed was 40 ft/min). The

X-Y caliper data, Fig. 9, acquired during PLT logging showed irregularity in most intervals of the open hole section. This data explained the washout intervals faced while tractoring. The fact that the wheels of the tractor start rotating as soon as the tool is powered up helped in negotiating washout intervals due to the bore condition or downhole tool string positioning. This capability allows the tractor to move forward, ing the restriction before the arms are fully extended and the tool is centered. Surface monitoring of the tractor’s performance downhole is another advantage of utilizing a well tractor. The tractor tool records its current consumption and voltage applied while tractoring and sends the data to the surface. On the surface, dedicated software processes this data and displays it in real time. This helps the engineer avoid getting stuck when tractoring into an open hole obstruction. Both the wheel driving mechanism and the current vs. voltage real time monitoring helped in driving the tractor past obstructions while deploying the tool

Fig. 8. Well intervention simulation for 3.125” wireline tractor post dummy run.

Fig. 9. X-Y caliper data.

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string. The current spikes when the tractor encounters an obstruction, after which the power supply is cut. The tractor is then re-powered up for obstruction negotiation, as indicated in Fig. 10. Measurements were done at 50 ft/min and at 30 ft/min in

Fig. 10. Voltage and current vs. time.

Fig. 11. Water entry zones as indicated by the PLT.

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upward es. All six spinners were turning, measuring the water and oil velocity. All capacitance array tool probes were working, indicating water and oil holdup along the entire wellbore logged depth. The MPLT total rate result was in agreement with the reported well production.

Shut-In es

The main purpose of acquiring data in shut-in conditions is to identify any cross flow between production zones or to the surface, if any, by deploying the PLT to TD while the well is in shut-in condition. The shut-in es did not show any cross flow in the well, which was also ed by other data. Operational Efficiency

The wireline tractor was able to through the complex well trajectory and irregular wellbore geometry, and carry the MPLT to TD three times, however, the MPLT got stuck three times while POOH. Each time the tool string gets stuck, the wireline tractor is operated to move the tool string 20 ft - 30 ft and then try to pull the tool string again. The tractor was able to release the stuck tool string three times, at different depths, successfully.

INFORMATION ACQUIRED The information acquired allowed the determination of the flow profile in the well and water entry points. It was important in this particular well to observe the effect of the well profile on the flow and well performance, since the complex well trajectory plays a significant role in limiting the production of the well (9,500 ft and 10,600 ft depth, of the hole). The stratified nature of the flow profile was confirmed, as well as the production of the well that comes from a section below the shoe at around 9,000 ft, Figs. 11 and 12. At least 60% of the water is coming from the lower section while 40% is coming comingled with the upper zone. The integration of the production log with the image log, Fig. 13, confirmed the production more from secondary fractures than from matrix production in this particular well. The data suggests it is important to clean the well and try to overcome the static fluid deposited in the sump areas at 9,500 ft and 10,600 ft, which act like a plug on the production of the well.

Fig. 13. Image log vs. production log processing.

CONCLUSIONS AND RECOMMENDATIONS Experience acquired in this operation through pre-job integrity tests and modifications can help in planning for future jobs. Comparing the simulation to actual pull forces recorded downhole provide a local coefficient correction that can be used in future simulations in the same field. Applying the final correction gave results close to the real time recorded on job tensions. Installing proper accessories, such as knuckle ts and swivels, helped in ing doglegs, and in preventing the cable from getting torqued due to the tool rotation downhole. Negotiation of any open hole washouts while deploying the PLT proved the necessity of proper downhole accessories when executing similar operations. The wireline tractor is a good deployment tool in open hole, extended reach horizontal wells, especially when the well rate is critical and might be affected by restrictions, as in the case of using CT. Proper planning is a key for success in this type of operation. The technique of logging at a dual flow rate is very useful for the interpretation and understanding of the well performance.

ACKNOWLEDGMENTS

Fig. 12. Station at 8,159 ft – Total flow rate – Stratified flow.

The authors would like to thank the management of Saudi Aramco for permission to publish this article. Also, we would like to extend our sincere appreciation to service companies for their engineering and consultant during job design, execution and evaluation.

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REFERENCES 1. Joly, E.L., Dormigny, A.L., Catala, G.N., Pincon, F.P. and Louis, A.J.P.: “New Production Logging Technique for Horizontal Wells,” SPE paper 14463, SPE Production Engineering Journal, Vol. 3, No. 3, August 1988, pp. 328332. 2. Copoulus, A.E., Costall, D. and Nice, S.B.: “Planning a Coiled Tubing Conveyed Production Logging Job in a Horizontal Well,” SPE paper 26090, presented at the SPE Western Regional Meeting, Anchorage, Alaska, May 2628, 1993. 3. Hallundbaek, J.: “Reducing Costs with Well Tractors for Horizontal Wells,” OTC paper 7875, presented at the 27th Annual Offshore Technology Conference, Houston, Texas, May 1-4, 1995. 4. Hallundbaek, J., Ostvang, K., Haukvik, J. and Steie, T.: “Wireline Well Tractor: Case Histories,” OTC paper 8535, presented at the Offshore Technology Conference, Houston, Texas, May 1-5, 1997. 5. McInally, G. and Hallundbaek, J.: “The Application of New Wireline Well Tractor® Technology to Horizontal Well Logging and Intervention: A Review of Field Experience in the North Sea,” SPE paper 38757, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, October 5-8, 1997. 6. Local, E. and Searight, T.: “Wireline Tractor Production Logging Experience in Australian Horizontal Wells,” SPE paper 51612, presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, October 1214, 1998. 7. Oilfield Technology Magazine, April 2010.

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BIOGRAPHIES Alaa S. Shawly is a Production Engineer in the Southern Area Production Engineering Department (SAPED). Prior to ing Saudi Aramco in 2006, he worked as a summer trainee with the Ain Dar and Shedgum Unit of the Reservoir Management Department from July through August 2004. Alaa has 4 years of experience, mainly in acid stimulation and well intervention. He received his B.S. degree in Petroleum Engineering from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia, in 2006. Muhammad H. Al-Buali ed Saudi Aramco in 2002. He is a Petroleum Engineer working in the Southern Area Production Engineering Department (SAPED). Muhammad has 8 years of experience, mainly in production optimization and well intervention. In 2002, he received his B.S. degree in Applied Chemical Engineering from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia. Mohammed R. Al-Omran ed Saudi Aramco in 2006 as a Production Engineer in the Southern Area Production Engineering Department (SAPED). His experience includes well intervention, water shut-off and production optimization of single and multilateral smart completion wells. Currently, Mohammed is very involved in the commissioning phase of the intelligent field infrastructure as part of the company’s goal to improve well surveillance and increase ultimate recovery through intelligent field utilization. Mohammed’s interest includes staying up-to-date on new technologies related to well intervention and production optimization. He received his B.S. degree in Petroleum Engineering from King Saud University, Riyadh, Saudi Arabia, in 2006.

Walid K. Al-Guraini is a Petroleum Engineer working in the Southern Area Production Engineering Department (SAPED). He ed Saudi Aramco in February 1997, working in the Development Drilling Department. Walid has 13 years of experience, mainly in drilling operations, production optimization and well intervention. In 1996 he received his B.S. degree in Chemical Engineering from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia. Alla A. Dashash is a Supervisor in the Southern Area Production Engineering Department (SAPED). He ed SAPED as a Production Engineer in 2003 where he worked in several areas of the giant Ghawar field. In 2008 he ed the ‘Udhailiyah Reservoir Management Division for a 1 year developmental assignment. Alla is an active member of the Society of Petroleum Engineers (SPE) and has several published technical papers. He is also a member of the Young Professionals SPE team in Saudi Arabia. In 2003 Alla received his B.S. degree in Petroleum Engineering from Louisiana State University, Baton Rouge, LA. Nawawi A. Ahmad is a Senior Petrophysicist and is currently the Lead Engineer for day-to-day evaluation of production logs for all fields in Saudi Aramco. He started his oil field career in 1989 with Shell in Southeast Asia as a Well Site Petroleum Engineer, Operational Petrophysicist and Field Study Petrophysicist in new and mature oil and gas fields. Nawawi then worked as a Senior Petrophysicist and Field Study Leader for PDO in the Middle East. His last position before ing Saudi Aramco was as a Division Head of one of the petrophysic units in a Shell operating company in Southeast Asia. Nawawi received his B.Eng. degree in Mining and Petroleum Engineering from Strathclyde University, Glasgow, U.K. in 1989 and an MBA from Brunei University, Brunei in 2005. He has been a member of the Society of Petroleum Engineers (SPE) since 1989.

Haider Al-Khamees ed Welltec® in 2009 as a Technical Sales Manager in Saudi Arabia with the responsibility of introducing Welltec Solutions to the field. He is now the Gulf Region Sales Manager. Haider’s previous experience includes work as a Field Engineer in various locations in Asia and Africa. In 2003, he received his B.S. degree in Petroleum Engineering from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia. Nasser Al-Awami ed Welltec® in 2009 and is the Operations Manager in Saudi Arabia. His previous experience includes 7 years as a Field Engineer and several managerial positions in the Gulf area and Southeast Asia region for a major service provider. Nasser is now responsible for the implementation of Well Tractor services in Saudi Arabia in conjunction with introducing the associated mechanical services and completion products. In 2001, he received his B.S. degree in Applied Electrical Engineering from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia. Juan P. Torne is a Technical Manager for Halliburton Energy Services, Wireline and Perforating Product Service Line in Saudi Arabia, and has been with Gearhart and Halliburton for over 26 years. He has worked in Venezuela, Indonesia, Egypt and Mexico in various positions, from field operations to technical and interpretation , operations management and technical marketing. Juan has presented several technical papers oriented to logging and perforating technical applications. He received his B.Eng. degree in Engineering from the Universidad del Cauca, Cauca, Colombia. Juan is a member of the Society of Petrophysicists and Well Log Analysts (SPWLA) and the Society of Petroleum Engineers (SPE).

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Use of Gyro-MWD Technology Offshore, a Step Change in Drilling Performance in Saudi Aramco Authors: Bashaar A. Al-Idi, Hasan F. Al-Sarrani, Jeff Stewart, Abhijeet Sarka and Geoff Smith

ABSTRACT Over the past few years, Saudi Aramco has achieved major efficiency improvements while drilling and completing smaller diameter hole sections. Such improvements provided significant reductions in rig time, and consequently reduced the overall operational cost. Less attention was paid to the upper hole sections due to less exposure to third party rental tools used in them. Offshore oil wells in Saudi Arabia recently experienced major savings in the 28”/22” hole section after the successful utilization of the new gyro measurement while drilling (Gyro-MWD) technology coupled with powerful performance drilling mud motors. The normal process was to drill the 22” hole section, of +/- 1,050 ft, by running gyro single-shot surveys every 50 ft 100 ft drilled until the well was in a safe path away from other wells within its vicinity. After adopting the Gyro-MWD system, along with a modified 22” bit and 11¼” performance mud motor, the rate of penetration (ROP) increased by 82%, thereby reducing the cost per foot. The increase in the ROP resulted in an average savings of 0.9 days per well (6 to 12 wells per platform) at this stage of drilling. In addition, the reliability of the gyro tool face from vertical, even when inside the casing, provided confidence in drilling operations, which facilitated an increase of the weight on bit (WOB) leading to faster drilling, thereby improving the overall ROP. Furthermore, eliminating the use of a wireline to run surveys increased the safety of the operation. The success of these 22” hole sections was substantial across the board, since it was one of the challenging areas where major improvements had not taken place before in several years. This article will evaluate the new drilling practice in more detail. It will also cover the conventional drilling and operational practices, and the thorough planning stages that resulted in these fruitful savings.

Nevertheless, with the recent surge in oil prices and drilling operations, coupled with the limited supply of rigs worldwide, it has caused rig rates to increase exponentially. All operating companies are now looking to improve operation time and reduce nonproductive time to optimize drilling.

BACKGROUND Saudi Aramco’s increased offshore drilling activities have given rise to collision concerns. Offshore fields in the Kingdom are congested, and new wells on the platform are planned within close proximity of existing wells. Therefore, it has become essential to practice good wellbore placement and management. Historically, multi-well platform directional drilling has presented unique challenges, especially in the initial drilling phase. New wells must be carefully navigated around existing wells and eventually steered clear of all magnetic interference to the desired target. Figure 1 shows the well spacing between each well on an offshore platform. Because of the proximity of other wells, it is impossible to use any magnetic based survey system in the top hole part of the well. Therefore, gyro survey tools are normally used to give the directional driller the azimuth and tool face data required to orient the motor and steer it through this interval.

INTRODUCTION Gyro measurement while drilling (Gyro-MWD) technology was first introduced and utilized in early 2001 to replace the gyro single-shot survey system for certain applications. Due to the high equipment cost at the time, the Gyro-MWD technology was not economical to run and the gyro singleshot survey still dominated the market. 12

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Fig. 1. Well spacing and layout of offshore platform.

GYRO SINGLE-SHOT SURVEY Gyro single-shot orientation tools, Fig. 2, are typically run on the wireline into the well; the tool is seated above the motor or a standard MWD system in an orienting sub to provide orientation data. Normally, the gyro single-shot orientation tool is run every 50 ft to 100 ft. This continues until the wellbore clears the magnetic interference, which can take up to 10 or more runs during a complex kick off. Run time usually averages 30 to 60 minutes per run, depending on depth. This is

Fig. 2. Gyro single-shot survey tool.

in addition to the 30 minute average circulating time that it takes to clean the hole prior to holding the string still and running in with a wireline and the gyro single-shot tools.

GYRO-MWD TECHNOLOGY The Gyro-MWD, Fig. 3, was developed so that the directional driller could benefit from having the gyro sensor as close to the bit as possible and have the ability to get fast gyro orientation survey data real-time in minutes rather than the average 30 to

Fig. 3. Gyro-MWD tool. SAUDI ARAMCO JOURNAL OF TECHNOLOGY

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60 minutes in the gyro single-shot survey case, saving considerable rig time. The Gyro-MWD tool face in real-time, while full survey data can be pumped to the surface after 3 minutes still time. Both gyro and magnetic readings can be obtained, which can clearly indicate the clearance from any magnetic interference existing in the wellbore.

GYRO-MWD SYSTEM VS. GYRO SINGLE-SHOT SURVEY As the Gyro-MWD technology emerged, it was essential to understand what this technology can bring that makes it more competitive and what the main applications are where it would have advantages over the gyro single-shot survey. The best way to introduce this technology is by taking an in-depth look at the nature of both systems. A recent evaluation of each survey tool was conducted in five main categories: safety, wellbore geometry, rate of penetration (ROP), time savings and other applications.

The rigging up and rigging down for wireline operations can sometimes be dangerous as many incidents on the rig are associated with wireline operations. Another area of safety where Gyro-MWD has a major advantage over the conventional gyro single-shot survey is the avoidance of collisions. This new technology drastically reduces the chance of a collision with existing wells in the platform, and enables drillers to achieve an accurate and smooth wellbore adhering closely to the well plan due to the continuous survey information being obtained while drilling. The directional driller does not have to drill 50 ft or so to get a survey. The Gyro-MWD system is placed directly above the motor in the bottom-hole assembly (BHA), which is approximately 40 ft away from the bit. In contrast, the conventional wireline gyro single-shot system is placed on a universal borehole orientation (UBHO) sub above an MWD tool, taking it 70 ft more or less away from the bit, leading to less accuracy of reading and bit projection compared to the Gyro-MWD technology.

SAFETY Safety of the platform, wells, rigs and the people operating on the platform is without doubt the one concern that no one can ignore. Gyro-MWD facilitates a much safer operation over the conventional wireline gyro single-shot survey system. The gyro single-shot survey necessitates wireline operations, which in turn requires additional personnel and equipment on the rig, including a wireline unit and the tools that operate with it.

WELLBORE GEOMETRY Gyro-MWD technology also provides a better wellbore geometer as the directional driller is not drilling 50 ft to 100 ft “blind” as in the case of the gyro single-shot survey. The realtime inclination and azimuthal readings result in drilling a smoother wellbore profile with no unexpected left/right turns or severe doglegs, Fig. 4.

Fig. 4. Spider plot of a surface section planned vs. the section actually drilled using Gyro-MWD technology on a 10 well platform.

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Fig. 5. Spider plot of a surface section planned vs. the section actually drilled using a wireline gyro single-shot survey.

The smoother well profile obtained by utilizing the GyroMWD technology reduces problems in running casing freely to the bottom, with more ts per hour being run. The smoother profile with Gyro-MWD is evident when compared to wells drilled with a conventional gyro single-shot system, Fig. 5.

RATE OF PENETRATION The gyro single-shot survey requires stopping and circulating at regular intervals prior to running the gyro in hole to obtain survey information. In these conventional operations, it is essential to control the weight on bit (WOB) to avoid excessive torque from the motor so that the wellbore does not deviate unknowingly from the planned direction, thereby limiting the optimum ROP that can be achieved. With the Gyro-MWD system’s ability to pump up continuous survey data, these limitations are eradicated.

TIME SAVINGS The Gyro-MWD technology has significantly contributed to increased rig time savings. These savings are attributed to:

OTHER APPLICATIONS Other applications for running the Gyro-MWD technology, where the economics are better, include orienting and setting whipstocks for sidetracking wells where regular MWD tools are affected due to magnetic interference.

CONCLUSION The initiative to utilize the Gyro-MWD technology produced expected results. Gyro-MWD proved not only to be efficient, but also to be beneficial in increasing the ROP performance and improving the wellbore geometry. Also, the Gyro-MWD system proved to be a much safer piece of equipment to operate for both the wells on the platform and the simultaneous operations on the rig. It eliminated the need for any wireline equipment, extra personnel and riging up/down wireline operations. As a result of less standby time for surveys, the Gyro-MWD technology clearly achieved a smooth penetrated hole. In conclusion, Gyro-MWD met Saudi Aramco’s goal and objectives to reduce rig time and optimize operations in Saudi Arabia offshore fields.

• High ROP performance.

ACKNOWLEDGMENTS

• Negligible time spent obtaining surveys.

The authors would like to thank the management of Saudi Aramco for permission to publish this article. Also, the authors wish to thank the Saudi Aramco Offshore Drilling Department, Halliburton Sperry Drilling and Scientific Drilling for actively ing this work and granting permission to publish this article.

• Elimination of standby time between connections. • Less time needed for reaming the hole and circulating. • Faster times for running casing and tripping in/out of hole.

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BIOGRAPHIES Bashaar A. Al-Idi has been with Saudi Aramco since 1998. He worked in various operational field assignments before being appointed a Drilling Foreman in 2005. In 2009, Bashaar moved to the Offshore Engineering division to work as an Offshore Drilling Engineer. He received his B.S. degree in Mechanical Engineering from Vanderbilt University, Nashville, TN. Bashaar is a current member of the Society of Petroleum Engineers (SPE). Hasan F. Al-Sarrani ed Saudi Aramco in 1997, working as a Drilling Engineer for both onshore and offshore operations. In 2008, he became acting Supervisor for the Offshore Exploration Drilling Department, and then in 2010, Hasan became an Offshore Drilling Supervisor. Jeff Stewart has been working for Sperry Drilling since 1998. He began working in 1978 in the offshore drilling industry in various positions, ultimately as a Night Tool Pusher. Jeff has worked in the field, principally in Saudi Arabia and previously in Oman. He is currently a Directional Drilling Coordinator with the primary responsibility for offshore operations with Saudi Aramco.

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Abhijeet Sarkar works for Scientific Drilling Controls Co. Ltd. in the Business Development Department where he is responsible for enhancing revenues within the region by evaluating new business opportunities and targeting new clientele. Abhijeet has 4 years of experience in the oil field industry. In the early part of his career, he was assigned as a Field Engineer to run conventional gyro services in the Saudi Arabia district. Abhijeet received his B.S. degree in istrative Studies from York University, Toronto, Canada, and his M.S. degree in International Business from the University of Wollongong, Dubai, U.A.E. Geoff Smith is Head of Operations for Scientific Drilling Controls Co. Ltd. in Saudi Arabia. He has over 30 years of experience in the oil field industry, working in the Middle East, North Sea and Far East. Geoff has vast knowledge of the directional surveying industry and is currently managing operations for the Saudi Arabia and Bahrain districts. Geoff studied Mechanical Engineering in the U.K. and first ed Sperry Sun Middle East in 1976.

Stimulation with Innovative Fluid-Placement Methodology and the World’s First Production Logging with Fiber Optic Enabled Coiled Tubing (CT) Authors: Mubarak A. Al-Dhufairi, Khalid Al-Omairen, Saleh Al-Ghamdi, Vidal Noya, Jan Jacobsen, Samer Al-Sarakbi, Adnan Ghani Abdulkarim and Abdul Wahab Azrak

ABSTRACT The coiled tubing (CT) e-line system is ideal for performing real time production logging (PL) in long horizontal wells; however, the wireline cable inside the CT can restrict the pump rate, while the large volumes of acid normally pumped could potentially damage the CT pipe’s integrity. Furthermore, using two different CT strings, one for pumping acid and another for performing the PL in real time, is neither practical nor economical. A common current approach is to use a memory PL tool (PLT), with the associated drawbacks of missing data or poor data quality and possible eventual misruns. To overcome these challenges, a new CT multipurpose system has been developed, allowing real time PL in conventional applications. Leveraging the telemetry offered by the fiber optic enabled CT (FOECT), already used for downhole measurements while treating wells in the Manifa field; the new downhole assembly enables the use of standard PLTs in real time mode. At the surface, the converted optical signal is transmitted wirelessly to the PL engineer’s portable computer, eliminating the need for conventional acquisition equipment and personnel. In the world’s first application, the system was used in a land water injection well after the stimulation job, obtaining an injection profile log with the same quality measurements as a conventional wireline conveyed log. Moreover, the data demonstrated a uniform injection profile. The new multipurpose FOECT reduces the mobilization and logistics otherwise required, as well as time and cost, compared to existing alternatives. This new capability can be extended to other scenarios like offshore or remote environments, where operational costs have a larger impact. Ultimately, the system opens the door to performing diagnosis, treatment and evaluation in a single well intervention – making CT operations more efficient and providing more data for production engineers.

INTRODUCTION The Manifa field is being developed using 27 man-made islands connected by 41 km of causeways, as the field is located in a shallow seawater area with 4 m to 6 m water

depth. These artificial islands require an extraordinary number of extended reach wells (ERWs) to reach the subsurface target depths of up to 31,000 ft1. Peripheral water injection is planned for reservoir pressure maintenance, efficient sweep of hydrocarbons and maximization of oil recovery. Many of the injection wells are power water injectors (PWIs) drilled from the coast of the mainland with 7” production tubing and 61⁄8” barefoot productive sections. In the drilling phase of these wells, drilling fluids are designed to cause minimum damage to the target zone. Typically, this is achieved by building a highly impermeable filter cake wall on the face of the formation (typical range is 0.1 millidarcy). Obviously, this filter cake should be removed later from the wellbore area; otherwise, it will adversely impact the performance of the well. To overcome this issue, acid stimulation with coiled tubing (CT) is required. This operation will improve the ERW’s performance and the CT has the inherent advantage of good conveyance of the stimulation fluids, resulting in effective open hole section coverage. In addition to the CT, chemical diversion systems were utilized to improve stimulation fluids placement and minimize acid movement to localized sections of high permeability, thereby helping to achieve a better acid distribution in the open hole. Further, a post-stimulation uniform production/ injection distribution profile log was utilized to gauge these special wells’ aptitude. The CT e-line system is ideal for performing real time production logging (PL); however, the wireline cable inside the CT can restrict the pump rate, and the massive volumes of acid pumped during typical stimulation jobs could potentially damage the CT pipe’s integrity. Furthermore, using two different CT strings, one for pumping acid and one for performing the PL in real time, is not practical or economical. The current approach is to use a memory PL tool (PLT), with the associated drawbacks of missing data or poor data quality and possible eventual misruns2. This article will address the ERW stimulation challenges, from CT operation to fluid placement and diversion, ending with the post job efficiency assessment. Furthermore, the solution and the introduction of new techniques to help achieve a better understanding of the stimulation effectiveness in the ERWs will be discussed throughout this article.

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CHALLENGES TO PERFORMING AN EFFECTIVE STIMULATION IN AN ERW ERWs are characterized by their long productive sections. In the case of the Manifa field, productive sections can be as long as 6,000 ft of open hole with a total depth (TD) of 31,000 ft measured depth (MD). Besides the challenge of reaching the TD with the CT, fluid placement in the wellbore can be affected by several factors: • Typical placement of stimulation fluids with CT has been limited to pump stages, delivering first the main acid followed by diverter systems and emulsified acid while the CT is being withdrawn or pulled out of the hole (POOH). This placement tactic has been the normal practice, without an understanding of where fluids are actually being injected. • The formation permeability and porosity across the length of the well can vary significantly. In the case where sections of predominantly higher permeabilities are present, these may induce unnecessary and significant losses of stimulation fluid. • High volumes of fluids are required to cover the entire wellbore; however, not all of the open hole length may need to be stimulated. If the formation heterogeneity is known, the sections of high production/injection potential could be identified and targeted first. In addition, whether enough fluids are used remains an uncertainty, only partially resolved by observing the well production or injection response. The same situation would apply to the pumping schedule. • Downhole parameters are traditionally extrapolated using surface readouts, such as wellhead pressure (WHP) and depth counters. These extrapolations have proven at numerous times to be incorrect. In the case of downhole pressures, these may not correlate to surface pressures, when pumping gases, for example. Therefore, using this analysis of downhole pressure to monitor the diversion or injection performance, or to maintain conditions above narrow fracture gradients is not reliable. • Fluids are normally designed to perform in an optimum manner at certain temperature ranges, but temperatures are not known while the treatment is in progress. Therefore, if a significant cooling effect is created downhole, the diverter system reaction may actually be delayed. In the absence of this variable, the treatment cannot be modified during the job to adapt to such changes in wellbore conditions.

DIVERSION The production or injection profile is controlled by: • The formation potential. • The ability of the stimulation intervention to reduce the damage created by the drilling fluids. • The skin improvement. 18

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The effectiveness of the stimulation in most cases relies on the performance of the diversion systems used. These are usually chemically based systems. The volume used, the placement sequence, the number of stages and the type of fluids used are some of the parameters that need to be managed to ensure that diversion systems achieve their role during stimulation. Consequently, without proper understanding of the actual conditions downhole (i.e., sections of high or low permeability, high or low porosity, existence of thief zones, etc.), it becomes more challenging to optimize the diversion and ensure acid placement to ensure optimum contribution from all productive sections.

CHALLENGES TO OBTAINING THE PRODUCTION AND INJECTION PROFILES The traditional way to record the production/injection profiles in oil and gas wells is by running a production log with wireline equipment. Such a setup allows real time data acquisition. A rapid quality check of the measurements can be performed to ensure that valid data is recorded. In ERWs, the conveyance of the PLT with wireline equipment into the horizontal path would require wireline tractors to pull the tools to TD; however, the industry experience with this technology in barefoot completions is limited. The conveyance of the PLT using a CT e-line configuration has been the most reliable option in such completions, though this greatly limits the pumping capability. In other words, performing the stimulation, pumping job, and the logging requires two dedicated CT reels for every operation, which is cumbersome and time consuming. The challenge for the Manita field development is this need for two different CT strings: • One to perform the massive stimulation jobs required by ERWs with very long open hole sections. • Another is to convey the PLT for profiling and to assure uniformity. Using a single string for both operations has raised service quality issues as per previous industry experiences. The cable is predisposed to damage due to the corrosion effect of the stimulation fluids, and the cable slack is difficult to manage, especially when high pump rates are required. All of this makes it highly likely for the occurrence of an operational incident. Furthermore, the ability to pump balls to actuate downhole tools, like tractors, is lost. The main drawback of using two different strings is that additional equipment and time to perform the operations is necessary; increasing the cost of the field development. It is for that reason that the use of memory PLTs was initially adopted as the preferable solution to obtaining the production and injection profiles. Although, the limitations of using memory PLTs include the possible loss of important data, as the es with the logging tool cannot be customized to the conditions measured in real time. In other cases, it has been necessary to

repeat the run due to a complete loss of data. Furthermore, logistics, footprint and safety management will, in this case, become extremely difficult to handle.

DOWNHOLE FIBER OPTIC ENABLED TELEMETRY SOLUTIONS Many of the challenges explained above are caused by the limited information available on downhole events during the stimulation treatments. Also, in the absence of smart functionalities that enable efficient use of resources for several applications, to perform the stimulation followed by the PL operation in real time can be costly. Two new solutions were proposed to address the challenges of this project: 1. First, to enable real time downhole measurements in standard CT operations to understand the behavior of the fluids (i.e., acid and diverter) and to optimize their placement on the formation face. The system is referred to in this document as fiber optic enabled CT (FOECT). 2. Second, a system was proposed that leverages the first one and simplifies the hardware required to enable the typical PL measurements commonly run with wireline services, referred to here as PL through FOECT.

FIBER OPTIC ENABLED COILED TUBING Optical fiber is widely used in communications due to the benefits it offers for data transmission. In an application to oil field services, a system based on fiber optics has been developed and adapted for use in CT operations to enable downhole measurements in real time. The FOECT, Fig. 1, is a system that allows real-time monitoring of downhole pressure and temperature without the limitations of conventional wireline enabled CT units. The FOECT system features include: • A fiber optic carrier (FOC) inside the CT string. • The FOECT bottom-hole assembly (BHA). • Surface acquisition. • A distributed temperature survey (DTS) system.

The downhole tool, which has a 21⁄2” outside diameter (OD), includes a CT head where the fiber optical connections are terminated, the electronic package that houses the downhole communication system, a battery and the sensors that record internal and external pressure and temperature, and a casing collar locator (CCL). The tool is flowed through and made of materials resistant to acid and hydrogen sulfide (H2S) resistant materials. The FOC, with an OD of 1.8 mm (0.071”), containing four fibers, is pre-installed in the CT string. The FOC is nonintrusive; therefore, standard operations normally done with conventional CT strings can be carried out, including pumping corrosive fluids and dropping balls. During a typical operation of the system, the downhole data is transmitted from the CT working reel, via wireless communication, to the CT control cabin, where the DTS monitoring system and specialized software are used to acquire, display, monitor and record real-time job parameters. The surface acquisition system can also communicate with the tool downhole and send commands3. As the fiber itself acts as a temperature sensor along the length of the CT string, a DTS monitoring system can also be used to capture reliable, accurate and real-time downhole distributed temperature profiles, along with data acquisition, analysis and interpretation. There is no need for calibration points along the fiber or for calibrating the fiber prior to installation in the wellbore. The system enables drillers to monitor the thermal profiles of injection at different times during the treatment.

INTERPRETATION To provide greater system integration, an interpretation specialist with a reservoir production background and measurements expertise identifies the downhole events, links them to the formation properties and performs an analysis of the combined data with specialized software to adjust the treatment as many times as needed. The interpretation specialist, who can be on the well site or in the office, interacts with the different players, including the stimulation and CT engineers, the reservoir evaluation experts and the

Fig. 1. FOECT system displaying, from left to right, the DTS system, surface acquisition at the working reel, the FOC and the FOECT BHA.

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well and reservoir engineers to set the next steps4. This methodology is captured in the typical FOECT system work flow, Fig. 2.

PL THROUGH FOECT The system uses the FOECT string for telemetry and a 11⁄16” BHA, which powers and communicates with the conventional PLTs. Data is sent wirelessly from the working reel acquisition hardware to the acquisition software on the surface; therefore, no conventional surface wireline logging unit is needed on location. The main components of the system are shown in Fig. 3. These include: • BHA: • Optical Logging Adapter (OLA). • PLT. • FOC inside the CT string. • Surface acquisition hardware and software. At the OLA, the FOC and fiber optics are terminated to the electric optical system. The optical signal is converted to an electrical signal through a specialized board that communicates with standard wireline PLTs using the same communication

protocol. The tool is powered by a battery, enabling operational times of up to 48 hours. The lower part of the OLA includes a wired multi-cycle disconnect tool for contingencies. Fluids can be circulated via the CT through the upper section of the BHA. On the surface, at the working reel, the FOC is terminated at the pressure bulkhead. The fiber optics are conducted to the surface acquisition system, which converts optical to electrical signals, again using a standard communication protocol of the PL systems. The data is transmitted wirelessly from there to a laptop computer, where customary software captures and displays the information, as in a conventional wireline job. This configuration eliminates the need for the normal wireline surface acquisition system, reducing the footprint at the location and reducing the number of people required. The system includes software that enables troubleshooting of the tools downhole as well as monitoring of critical operational parameters, like power supply and signal quality. A key feature of the PL FOECT system is that it enables the same CT string to be used for executing both the acid treatment and the logging operations. This is particularly advantageous compared to conventional CT e-line configurations given the affected integrity of the cable when exposed

Fig. 2. Workflow used to perform the stimulation with the FOECT system.

Fig. 3. The PL FOECT system is composed of the surface acquisition system (left), the FOC (center), and the OLA and PLT (right).

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to large amounts of acid, the cable slack management, the flow rate restrictions and the inability to pump of drop balls.

THE FIELD APPLICATION A field application where the technologies and methodologies described above were implemented is discussed here. The main objective was to acid stimulate Well A utilizing a 2” CT and to run a post stimulation injection PLT to obtain the well injection profile. The well TD was 12,560 ft MD with an open hole zone of 3,500 ft. The well was newly drilled as an open hole PWI and completed with 7” tubing. A short injection test performed by the rig had indicated an injection rate of 3.6 thousand barrels of water per day (MBWD) at 2,000 psi.

FLUIDS Three main acid systems were designed based on formation characteristics, suspected damage and previous experience in horizontal wells in Saudi Arabia. All systems fulfilled compatibility test requirements. The most appropriate acid concentration selected for all the systems was 20 wt% hydrochloric (HCl) acid. Due to the length of the treatment interval, the volumes of treatment fluids had to be optimized efficiently without compromising the desired results of the treatment. A significant volume of mutual solvent based preflush fluid was proposed to displace the suspected hydrocarbon deposits in the near wellbore area. The preflush was followed by a plain 20 wt% HCl system to break the filter cake created by the drilling fluids and to create wormholes. The main additives in the plain acid system included a corrosion inhibitor and surfactant. To create an efficient network of wormholes, an emulsified acid system was proposed. This was an oil external phase emulsion formed with a 70:30 ratio of 20 wt% HCl and diesel. The external phase of the fluid would allow deeper penetration into the formation before breaking. One of the main challenges of matrix acidizing in carbonate reservoirs is obtaining uniform coverage of the treatment across the zone(s) of interest. Chemical diversion is usually required to ensure stimulation throughout the interval. A selfdiverting acid system can simplify the process significantly by continuously injecting acid into the formation. The acid will viscosify in-situ and temporarily block the existing channels to divert itself into undissolved areas. The proposed system used a viscoelastic surfactant that gels as the acid spends. This gelling causes temporary plugging of the acid-etched channels to allow continuous acidizing of the unstimulated zone. This diversion system contains no polymer; therefore, it does not leave a solid residue that could cause damage to the rock. In addition, this diversion system was foamed with nitrogen to enhance its diversion capabilities in long horizontal intervals. The design proposed a total acid concentration of 15 gallons per feet (gpf). Below is the list of fluids recommended for the stimulation:

1. Preflush

6 gpf

2. 20 wt% HCl

6 gpf

3. Emulsified HCl

6 gpf

4. Foamed Diverter

3 gpf

5. Post flush

3 gpf

The fluid placement, contrary to previous jobs in the field where fluids where spotted (blindly) while POOH, would be done based on the DTS interpretations and methodology previously explained. Therefore, a diverter was placed in sections showing high injectivity and acid where no indications of acid reaction were observed.

JOB EXECUTION The acid stimulation treatment was executed in the following sequence: 1. Preflush (504 bbl): • Pumped at 1.8 barrels per minute (bpm) while run in hole (RIH) from 9,040 ft to 12,560 ft. 2. Warm back DTS analysis after preflush. As in Fig. 4, four significant cold spots were identified across the first 1,500 ft of open hole and were targeted for diversion for the first stimulation . 3. Bullhead injection test 1 with real time DTS (250 bbl, WHP increasing from 170 psi to 500 psi): • Pumped at 7 bpm surface injection rate down the CT/tubing annulus. • DTS real-time injection profile analysis: Tight 800 ft toe section, uneven fluid distribution across the remaining open hole. 4. First stimulation (196 bbl 20% HCl acid, 115 bbl viscoelastic diverting acid (VDA) diversion): • Pumped at 1.5 bpm while POOH from 12,560 ft to 9,040 ft. 5. Bullhead injection test 2 with real time DTS (250 bbl,

Fig. 4. Preflush warmback DTS profiles: The first and last temperature trace.

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WHP steady at ~500 psi):

• The post stimulation injectivity test indicated successful acid placement at the toe and significant improvement to the pre-stimulation injection profile.

• Pumped at 7 bpm down CT/tubing annulus. • DTS real time injection profile analysis: Increased injection to the toe of the open hole. 6. Second stimulation (308 bbl 20% HCl acid, 101 bbl VDA diversion): • Pumped at 1.5 bpm reciprocating from 12,560 ft to 9,040 ft to 12,560 ft. • Emulsified acid (500 bbl). • Pumped at 1.5 bpm while POOH from 12,560 ft to 9,040 ft. • Postflush (250 bbl). • Pumped while RIH from 9,040 ft to 12,560 ft. • Bullhead injection test 3 with real time DTS (500 bbl, WHP steady at ~500 psi). 7. Pumped at 7 bpm surface injection rate down the CT/tubing annulus: • DTS real time injection profile analysis, Fig. 5: Fluid flow to toe established, with relaxation to formation pressure observed after 250 bbl as inferred from temperature events occurring during last bullhead injection. 8. POOH. The following conclusions could be drawn from the processed data: • The preflush injection identified four potential thief zones that were targeted with a diverter. • Post-acid injectivity tests after the first treatment stage indicated positive development of the injection profile as a response to the VDA diversion.

THE PL OPERATION After the stimulation was performed and the last injection profiles were recorded with DTS, the CT was POOH. The OLA assembly was then installed at the end of the CT, together with the PL suite of tools, which included the housing without the telemetry system, and the different measurement modules: Gamma ray, CCL, pressure, temperature, tension/compression subs, a centralizer, an inline spinner, and the full bore spinner plus X-Y caliper. After confirming that the real time acquisition was working smoothly, the logging tools were then RIH, as normally done in a conventional CT e-line operation. In each well, one was performed from the casing shoe down to TD while injecting water at 10,000 barrels per day (BPD) through the CT-casing annulus. Another from TD to the casing shoe was done while injecting water at the same rate. A total of 12 calibration es were executed; six while shut-in and six while flowing, and station logs were recorded while coming up. The PLT operation lasted 24 hours. No problem was encountered during the hole logging operation with the new system. Running the PLT with the PL FOECT in real-time eliminated the need to stop every 1,000 ft to take stations for the time correlation required when doing memory PLT deployments. In addition, the real-time option allowed for es to be repeated, in case measurements needed to be verified, improving the data quality. In memory PLT deployments, misruns are not uncommon since the memory cartridge sometimes malfunctions and consequently looses the data, requiring repetition of the job. This is not the case with the new system.

Fig. 5. Temperature events occurring during last bullhead injection (open hole section only).

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RESULTS

CONCLUSIONS

A matrix stimulation treatment was designed and pumped in a carbonate water injection well in Manifa field, Saudi Arabia. Real time distributed temperature measurements from a FOECT string were used to understand the injection profiles before, during and after the treatment. On-site t interpretation of real time downhole data was provided, and a work flow for enhanced stimulation was applied to optimize fluid placement in two acid diverter stages followed by a full open hole treatment with emulsified acid. Heating associated with the exothermic reaction of acid and carbonate in each stage was confirmed with real time downhole temperatures. A clear indication of diversion with VDA was observed. The main outcome of the stimulation treatments was an increase of injection rate. Well A before the treatment was injecting 3,600 bpd with an injection pressure of 2,000 psi. The initial warm back DTS analysis confirmed that minimum injection was taking place on the last 800 ft of the hole before the stimulation. Post treatment injectivity changed to 10,000 bpd, with a pumping pressure of 500 psi. After the treatment, the injection profile was recorded using the conventional PLTs deployed with the new PL FOECT system previously described. The log confirmed a uniform injection pattern with even contribution from most of the open hole interval, Fig. 6. Analysis of the DTS profile taken after the stimulation and overlaid on the PL dicated an excellent match of both profiles, as demonstrated in Fig. 7. This experience represented the first time that a CT PL operation in the Manifa field was performed in real-time with very high accuracy and magnificent management of the stimulation treatment.

The main conclusions from the acid treatment experience are: 1. A new methodology for stimulating wells with CT was implemented in the Manifa field for the first time with positive results. 2. The methodology is based on modifying the fluid pumping schedule in response to the real time downhole injection profile, and monitoring was facilitated by the new FOECT system. 3. The measurements taken during the treatment provided a reliable indication of the fluids placement downhole, understanding at which depths the diversion or acid effects took place in each stage. 4. DTS measurement has proven to be a powerful asset for CT treatments. 5. The methodology not only assisted in improving the injection rates, but was also contributed to a more uniform injection profile, which is extremely important to optimize the oil sweeping pursued with water injection. The main conclusions from the logging operation include: 1. A new CT enabled fiber optics telemetry system was successfully tested for the first time in the world. 2. The new PL FOECT system enabled the acquisition of PL injection profiles in real-time, with the potential to replace the previous process using a memory PLT. 3. The new system has the same equipment, personnel and layout requirements of a typical memory PLT deployment on CT. 4. Due to the real-time functionality, more reliable data acquisition and better data quality, post stimulation treatments have been implemented in Manifa field. 5. By using the same CT string for both stimulation and logging, significant logistics efficiency (involving equipment and personnel) and operational improvements were delivered, reducing the field development costs. 6. The benefits of this application can be easily extended to other field developments and environments. In offshore operations, the reduction of the footprint and personnel, as well as actual cost, would be an advantage.

Fig. 6. Injection profile recorded with the PL FOECT.

The experience was the world’s first known PL operation using fiber optic telemetry through CT. In the future, this

Fig. 7. Injection profile recorded with the PL FOECT system and DTS.

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technology could be applied to remote and offshore environments requiring multipurpose CT strings (treatment and logging). It is also recommended that real-time transmission and sharing of the data be exercised between the field, client offices and interpretation domain experts, including stimulation and logging exports.

ACKNOWLEDGMENTS The authors would like to thank the management of Saudi Aramco and Schlumberger for permission to publish this article. The authors would also like to acknowledge the efforts and contributions of John Stuker, Kellen Wolf and Soon Seong Chee for their technical and operational .

REFERENCES 1. Nughaimish, F.N., Hamdan, M.R. and Shobaili, Y.M.: “Extended Reach Drilling and Causeway Utilization in the Development of a Shallow Water Oil Field,” OTC paper 20112-MS, presented at the Offshore Technology Conference, Houston, Texas, May 4-7, 2009. 2. Al Dhufairi, M., Al Ghamdi, S., Noya, V., et al.: “Expanding the Envelope of Coiled Tubing (CT) Reach for Stimulation of Ultradeep Open Hole Horizontal Wells,” SPE paper 130642, presented at the SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, March 23-24, 2010. 3. Garzon, F., Amorocho, J., Harbi, M., et al.: “Stimulating Khuff Gas Wells with Smart Fluid Placement,” SPE paper 131917, prepared for presentation at the SPE Deep Gas Conference and Exhibition, Manama, Bahrain, January 24-26, 2010. 4. Jacobsen, J., Kharrat, W., Weiss, A. and Noya, V.: “Changing the Game of Fluid Placement: Intelligent Well Intervention on a Tri-Lateral Horizontal Well,” SPE paper 130365, presented at the SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, March 23-24, 2010.

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BIOGRAPHIES Mubarak A. Al-Dhufairi is a Production Engineering Supervisor of the Manifa development. His experience includes working on several fields, including Safaniya, Shaybah and Berri fields, along with his experience in drilling engineering. Mubarak received his B.S. degree in Petroleum Engineering from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia. Khalid Al-Omairen’s first assignment as a PDP was a Production Engineer for Aindar field in 1986. Later on, he worked as a Foreman and a Superintendent for several offshore and onshore facilities, including Northern Area Oil Operations (NAOO) Well Services Division. Currently, Khalid is the General Supervisor of Safaniya Production Engineering. He has a unique ion to create a work culture attached to continuous simplification of the routine through adaptation of new technology and process improvement, a culture that is proactive and flexible enough to accept change and resist returning to old time thinking. Khalid received his B.S. degree in Petroleum Engineering from the University of Louisiana, Lafayette, LA. Saleh A. Al-Ghamdi is a Petroleum Engineer for the Safaniya Production Engineering Division of NAPE&WSD, working in the Manifa Production Engineering Unit. He ed Saudi Aramco in 2002 as a Production Engineer, working in several fields, including Berri, Shaybah, Safaniya and Marjan, before he ed the Manifa development team in 2008. Saleh received his B.S. degree in Petroleum Engineering from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia. Vidal Noya is a Coiled Tubing Services Technical Manager assigned to the region of Saudi Arabia, Kuwait and Bahrain. He has 19 years of experience in the oil field services. Since ing Schlumberger, he has worked on several projects related to operations and technology in the area of well intervention and production. Vidal’s experience includes assignments in South America, North Africa, the Middle East and Europe. He received his B.S. degree in Mechanical Engineering in 1991 from the Universidad Central de Venezuela, Caracas, Venezuela.

Jan Jacobsen is the ACTive Domain Champion for Schlumberger in the Middle East. He ed Schlumberger as a Coiled Tubing Field Engineer in 2004, working in and the Netherlands. In 2007, Jan ed Schlumberger Data Consulting Services with assignments in the U.K. and . He then ed Schlumberger Well Services and Data Consulting Services assuming his current position in Saudi Arabia in 2009. In 2004, Jan received his M.S. degree in Civil Engineering from the Technical University of Denmark, Copenhagen, Denmark, specializing in applied geophysics. Samer Al-Sarakbi is a Technical Manager at Schlumberger. He is involved in coiled tubing and stimulation operations and new technology implementation. Samer’s main interest is in coiled tubing equipped with fiber optic cable applications, extended reach coiled tubing applications, high-pressure/high temperature interventions, carbonate stimulation and water shut-off. He received his B.S. degree in Mechanical Engineering from Damascus University, Damascus, Syria. Adnan Ghani Abdulkarim is a Sales and Technical Engineer for coiled tubing services with Schlumberger, where he is involved in new technology implementation for stimulation, logging and conveyance. His main interest is in stimulation technologies, formation evaluation, production evaluation and coiled tubing mechanical services. Adnan’s experience includes assignments in Bahrain and Saudi Arabia. He received his B.S. degree in Chemical Engineering from the University of Bahrain, Manama, Bahrain. Abdul Wahab Azrak is the Location Manager for coiled tubing logging with Schlumberger, where he is involved in new technology implementation for logging and conveyance. His main interest is wireline logging (formation evaluation, production evaluation, perforation and mechanical services) plus related conveyance techniques like tractor and coiled tubing. Abdul’s experience includes assignments in the U.A.E., Bahrain, Syria, Jordan and Saudi Arabia. He received his B.S. degree in Electrical Engineering from Ajman University of Science and Technology (AUST), Ajman, U.A.E.

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Successful Exploitation of the Khuff-B Low Permeability Gas Condensate Reservoir through Optimized Development Strategy Authors: Dr. Zillur Rahim, Dr. Hamoud A. Al-Anazi, Adnan A. Al-Kanaan and Ahmad Azly Abdul Aziz

ABSTRACT Khuff-B and Khuff-C are the two carbonate reservoirs in the SA-1 field discovered in 1980 with the drilling of exploratory Well SA-A. Production from Khuff-B began in December 1983 when a second well was drilled, and both it and Well SA-A were put onstream. The development of Khuff-B was minimal until two years back; and only nine stand-alone wells were exclusively completed in this reservoir at that time. Three of these nine wells were actually tied-in to the gas plant. A few other wells were combined Khuff-B/Khuff-C producers. In these commingled producers, Khuff-B’s contribution was significant only in areas where Khuff-C was of relatively poorer quality. The dominant production today is generally from the Khuff-C reservoir. A large area currently within the Khuff-B reservoir boundaries with only a few producing wells will be discussed. The development of this vast area is required to meet the increased gas demand in the Kingdom. Accurate evaluation of Khuff-B to ascertain reservoir potential and deliverability is of the utmost importance. This article evaluates the Khuff-B reservoir in the SA-1 field and proposes an optimal development plan to effectively deplete its reserves. Based on detailed analyses, the Khuff-B area has been divided into three regions, namely, Area-1, Area-2 and Area-3 or the good, the moderate, and the challenging, low quality, tight reservoir, respectively. The average production rates from these areas vary between 5 thousand standard cubic feet (MMscfd) and 50 MMscfd. The optimal drilling plan in the low quality, low productivity area consists of identifying the productive layer through a slanted pilot hole followed by drilling an extended lateral to attain maximum reservoir . A second lateral can be drilled in special cases where more than one developed layer is encountered in the pilot hole. This development approach also allows for placement of the production lateral far above the gas-water (GWC) to avoid future water production or influx. The strategy is promising and has already been implemented in the field, and the results have confirmed a high production, water-free gas rate from the Khuff-B interval.

reservoirs were discovered in 1980 with the drilling of an exploratory well, Well SA-A1, 2. Production from Khuff-B began in December 1983. Shortly thereafter, another well producing initially from Khuff-C was brought onstream. Significant Khuff-B contribution is required to continuously meet the demand of the high-capacity gas processing plant, as well as the Kingdom’s requirements. Although some large Khuff-B producers exist, they are located in the high potential areas. The current completion method focuses on acid stimulating the reservoir3. The objective of this study and evaluation is to ensure improved gas recovery from the more heterogeneous Khuff-B areas. The initial reservoir pressure measured in Khuff-B was 7,600 psi. Current reservoir pressure has dropped due to normal production and depletion as per expectation, particularly in the areas where gas production is dominant. In most of the field, however, Khuff-B remains untapped, and therefore the pressure in those areas remains near the original pressure. This article evaluates Khuff-B in the SA-1 field using all available information and to propose an optimal development plan. The evaluation includes current well status, reservoir properties, future drilling, and development plans. The objective of this evaluation is to assess the Khuff-B boundaries, gaining an understanding of the heterogeneity and discontinuity of the reservoir, identify well potential and future drilling locations, and propose an optimal well plan for its development. The Khuff-B reservoir extent and potential are vital information for

INTRODUCTION Three gas bearing reservoirs exist in the SA-1 field: The carbonates of Khuff-B and Khuff-C, Fig. 1, a reservoir in the sandstone of pre-Khuff Jauf. The Khuff-B and Khuff-C 26

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Fig. 1. SA-1 field Khuff reservoir boundary.

proper planning of reservoir development with the goal of meeting target production rates. A major fault system identified initially by seismic and later confirmed by logs, tests, production data, and drilling events, runs N-S in the eastern portion of the field. Many of the Khuff-B wells near this fault have shown good potential. The vast majority of the Khuff-B area is in the west, which has remained less developed. The following review and analyses have been conducted to plan the Khuff-B development strategy. • Logs from all stand-alone Khuff-B producers as well as from Khuff-B/Khuff C commingled producers. • Khuff-B logs from wells producing from Khuff-C only. • Production logging tool (PLT) data to confirm rate contribution from Khuff-B reservoir in commingled wells. • Khuff-B cross sections to identify reservoir continuity and heterogeneity. • Review of current Khuff-B wells’ reservoir quality, well trajectory and production history. • Production decline in Khuff-B wells as a function of time and depletion. • Analysis using material balance computation (MBAL) and production forecast model (PROSPER) to assess individual well and reservoir potential. Rock Type Fluid Type CGR Number of Current Wells Average Porosity (%) Average kh (md-ft) Initial Reservoir Pressure Table 1. Reservoir properties

Carbonate (Khuff-B) Gas Condensate 40 bbls/MMscf 16 Vertical and 9 Horizontal 6.5 60 7,600 psi

The extensive evaluation targeted development of the relatively low-porosity, low-permeability areas where little well control data was available. The proposed strategy calls for drilling a highly slanted pilot hole to first identify a production interval. Subsequently, laterals will be drilled and correctly placed, based on log evaluation, to ensure maximum reservoir and avoid any water intervals. From initial production data and test result evaluations, it has been concluded that such wells will provide higher sustained rates compared to vertical wells.

KHUFF RESERVOIR CHARACTERISTICS Khuff formation Permian carbonate is one of the major nonassociated gas reservoirs in Ghawar field, Saudi Arabia. The formation is divided into four depositional cycles: A, B, C and D. Moderate to high quality reservoirs are found in the first three intervals. Both Khuff-B and Khuff-C reservoirs are of a continuous nature while Khuff-A is sporadic. Khuff-D is usually tight or water bearing4. The Khuff reservoir in general is highly heterogeneous and exhibits anomalous fluid and stress characteristics. The formation has limited preserved primary digenetic processes of dolomitization, selective dissolution of limestone, and anhydrite. Lithological studies show that the reservoir is composed of dolomite (high porosity) intermingled with limestone and has intermittent anhydrite stringers within the tighter section of the reservoir. The three types of porosity in the Khuff reservoir are inter-particle, inter-crystalline and moldic. The Khuff gas composition also varies widely with gas from the southern part of Ghawar field yielding the lowest acid gas and nitrogen concentrations. Hydrogen sulfide content decreases from north to south and from east to west. The gas condensate yield tends to increase from north to south. There is a wide variation in formation permeability (0.5 mD - 10 mD) and porosity (5% - 15%) within each of the Khuff intervals. The original pressure and temperature are 7,500 psi and 280 °F, respectively. 90 80

Gas Rate, MMscfd

70 60

HIGHPOTENTIAL

50 40

MEDIUM POTENTIAL 30

LOW POTENTIAL

20 10

0 Jan-84 Sept-86 Jun-89 Mar-92 Dec-94 Sept-97 Jun-00 Mar-03 Nov 05 Aug-08 May-11

Production Time, Years Fig. 2. SA-1 Khuff-B areas with example wells.

Fig. 3. Production profiles showing different potential trends. SAUDI ARAMCO JOURNAL OF TECHNOLOGY

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Khuff-B is a large heterogeneous and compartmentalized reservoir with multiple gas-water s (GWCs), faulting and variations in flow capacity. The entire area is divided into several sections based on reservoir characteristics and porosity development, Fig. 2, and on varying production rates, Fig. 3. As such, there is no single optimized method to develop the area. Rather, based on a comprehensive study of field and laboratory data, an area specific methodology needs to be developed to optimize gas exploitation from this area. Based on a detailed analysis of reservoir development, stratigraphic cross sections, seismic profiles, and well performances, the Khuff-B reservoir in the SA-A field has been divided into three parts, namely Area-1, Area-2 and Area-3.

These three areas represent the good, moderate and poor reservoir development, respectively. The average Khuff-B reservoir properties are presented in Table 1. The characteristics of the Khuff-B reservoir can be evaluated using a few key indicators: Seismic impedance profiles, reservoir cross sections, Fig. 4, and current well performances. The seismic maps (impedance values) for the northern and southern area of the field, Figs. 5a and 5b, respectively, show the variability in the reservoir properties. Khuff-B is usually thin (7 ft to 20 ft thick) and for that reason impedance values are not precise, but they still provide a general overview of the area. It is clear from the seismic profiles that the areal heterogeneity is prominent, which poses a challenge for locating wells, selecting correct drilling azimuth and choosing optimal well inclination. Cross Sections

A comprehensive analysis of Khuff-B cross sections throughout the SA-1 field has been performed. Khuff-B is well-developed in the northeast part of the field and on the east flank, where the prolific producers are located. Toward the south in the east wing, the reservoir quality gradually deteriorates, Fig. 2 (Area-3).

Fig. 4. SW-NE seismic impedance cross section.

Figs. 5a and 5b. Northern (above) and southern (below) area seismic impedance map.

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Fig. 6. Comparing Khuff-B and Khuff-C rate contribution (percent).

Analysis of the N-S cross section shows that the good quality Khuff-B reservoir in the northern section deteriorates toward the south. The long-term production rates from the wells match the porosity profile quite well. On the other hand, the E-W cross section through the middle of the field shows much variation in reservoir quality confirming the unpredictable nature of this reservoir. In the southern part of the field, Khuff-B development is poor. This is well reflected in the open hole logs as well as in well performances. Comparing Khuff-B Potential to Khuff-C in Commingled Wells

Khuff-C is the prolific reservoir in the SA-1 field and the major contributor to total production from the area. Although there are a few combined producers, depending on the KhuffB reservoir development, some wells produce from the Khuff-B as much as 40% - 60% of the total production while others produce 10% or less. Figures 6 and 7 present the Khuff-B and Khuff-C rate contribution, production history and several production logs from the combined producers indicating the dominant nature of Khuff-C as compared to the Khuff-B reservoir. It is obvious from the logs that Khuff-B dominates only where Khuff-C is poorly developed.

Although a commingled producer, the well is considered to be a Khuff-B producer because of its production and because the location of the well is outside the Khuff-C boundary (logs indicate only a small upper section of the Khuff-C is productive and the remaining is below water ). This well is important in providing data for reservoir analysis due to its location on the west flank where there is no other well. The current well rate is around 10 MMscfd, 60% of which is from the Khuff-B interval. The well is located in Area-3, and is certainly an ideal candidate for a long, horizontal sidetrack in Khuff-B to boost its production. The well log and performance are provided in Fig. 8. Well SA-W – Moderate Producer

Well SA-W was one of the early dedicated Khuff-B vertical

KHUFF-B RESERVOIR PERFORMANCE EXAMPLES Well SA-Y – Poor Producer

Well SA-Y was drilled in 2009 as a vertical Khuff gas producer on the west flank of the field. It penetrated GWC in lower KhuffC and encountered poor porosity development in Khuff-B. Upper Khuff-C was then perforated underbalanced, due to its proximity to GWC, and initially flowed 7 million standard cubic feet per day (MMscfd) at 1,900 psig flowing wellhead pressure (FWHP). Subsequently, Khuff-B was perforated and acid fractured, and its production was commingled with Khuff-C. Production has since declined, with most contribution coming from Khuff-B only.

Fig. 7. Comparing Khuff-B and Khuff-C open hole logs.

Fig. 8. Well SA-W log and production history (located adjacent to Area-3).

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Fig. 9. Well SA-W log and production history (located adjacent to Area-3).

Fig. 10. Well SA-U log and production history (located in Area-1).

producers drilled in 1985 in the SA-1 field. The well, located on the mid-flank in the western part of the field away from Area-3, encountered good Khuff-B porosity development. Well SA-W is the only stand-alone Khuff-B producer in the west side of the field. This well has moderate potential with about 10 MMscfd after acid fracturing. The well log and performance are provided in Fig. 9. Well SA-U – Excellent Producer

The spud date for this well was July 1999. The well was drilled as a deviated well with a 50° inclination. The well was put on initial production in September 2002. Due to its high productivity, the well was not stimulated. The well is located next to the major fault identified by seismic, which indicates the presence of natural fractures and therefore explains its high performance. A PLT was run in 2006, which showed major contribution from the upper Khuff-B section with the highest porosity, as indicated in the log, Fig. 10. Well SA-U is the highest Khuff-B producer in the SA-1 area.

IMPROVED PRODUCTION WITH NEW STRATEGY Once the areas and reservoir potential were identified, the new proposed strategy focused on Area-3, where the low-porosity, low-permeability Khuff-B reservoir is present. In this area, 30

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Fig. 11. Slanted pilot hole and horizontal laterals showing net pay sections and tested rates.

vertical wells offer nominal rates even with massive acid fracturing. The highly slanted or horizontal wells, when drilled to provide maximum reservoir , deliver higher rates as per expectation5. An added benefit of drilling the pilot hole first is to ascertain GWC. If GWC is present, the production lateral can be drilled with a minimum standoff

Fig. 12. Sustained production rate from Well SA-T and an offset well drilled in Area-3.

Fig. 13. Gas potential comparison between vertical and horizontal wells..

Fig. 15. MSF example showing improved inflow parformance relationship (IPR) after each treatment stage.

Fig. 14. Installed MSF equipment schematic showing packers, ports, and target intervals.

from this level so as to avoid any future water production or encroachment. An example case (Well SA-T), initially drilled as a pilot hole in Area-3, has shown some reservoir development in Khuff-B. Later on, a horizontal well was drilled with 2,560 ft of reservoir , Fig. 11. Another example well is also shown in the same Figure. Well SA-T tested 39 MMscfd at 1,800 psi FWHP and has been producing for a considerable length of time with a sustained rate, Fig. 126, 7. Figure 13 presents the overall performance and potential comparison between vertical and horizontal producers. The average rate achieved from the horizontal producers is more than double that of the vertical producers. The Khuff-B development strategy has thereby proven to be very effective in developing a tight reservoir.

NEW TECHNOLOGY Multistage fracturing (MSF) is also being considered to improve well productivity in tight gas formations. This technology allows wells to be drilled highly slanted or

Fig. 16. Schematic representation of UBCTD.

horizontal and subsequently fracture treated across multiple intervals, depending on the reservoir development. The number of stages, fluid volume, proppant amount, pump rate and placement of frac ports and packers are determined by assessing open hole logs, reservoir characteristics and geomechanical properties. Figure 14 shows a typical MSF installation in a horizontal well with frac ports located against the high porosity intervals. The open hole packers in between the frac ports isolate each interval to control fracture overlap in case fractures grow longitudinally to the wellbore. Figure 15 illustrates the productivity increase after each fracture treatment in the three stage MSF treatment that was conducted in a well drilled across Khuff-B. Underbalanced coiled tubing drilling (UBCTD) is a viable option for drilling several laterals at different angles and SAUDI ARAMCO JOURNAL OF TECHNOLOGY

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azimuths in consolidated and low permeability formations. The drilling fluid weight is lower than the formation pressure; therefore, the well produces gas as it is being drilled. The benefits include minimum formation damage and monitoring of the well performance during drilling. The flexibility in drilling direction and inclination is an added advantage. Figure 16 presents a schematic representation of an underbalanced drilling example where three laterals have been drilled and are contributing to production. The well can also flow from its original pilot hole, which may be initially perforated to communicate directly with all gas bearing intervals.

CONCLUSIONS AND RECOMMENDATIONS 1. All new wells are recommended to be slanted, highly deviated, or horizontal. This will ensure maximum reservoir . 2. A slanted pilot hole is recommended to identify the porosity interval. It will also make it easy to initiate the main lateral as well as to stay above GWC. 3. Drill delineation wells in the areas where there are fewer wells – on the western and southern sides of the field. Drilling and testing of such wells will help in assessing reservoir boundaries and extent. 4. Delineation wells can be slanted, so they can be turned into producers if good reservoir development is encountered. A lateral hole can subsequently be drilled. 5. Run on image log for accurate dip calculation in the pilot hole. This will provide good information on how to land the lateral. 6. Acid stimulate or acid fracture the well, depending upon log results. Multistage acid fracturing could be an option, depending on the reservoir quality and the scatter of the porosity interval encountered in the lateral. Perform routine buildup tests and other surveillances to understand reservoir properties, obtain reservoir fluid samples and measure reservoir pressure to assess the depletion rate. 7. Wells that have been drilled and completed using the slant hole strategy have proven to deliver higher rates compared to the conventional vertical, acid fractured wells with an expected stabilized rate gain of twofold.

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8. Application of other technologies, such as MSF and UBCTD, is important. Both strategies have shown very positive results in the development of tight gas reservoirs. MSF fractures the gas intervals so the reservoir can communicate with the wellbore, bying any near wellbore damage. UBCTD minimizes drill-in fluid damage and assists in lifting the well, while drilling helps in assessing reservoir quality and performance.

ACKNOWLEDGMENTS The authors would like to thank the management of Saudi Aramco for permission to publish this article. The authors would also like to thank the engineers who struggled hard to implement the process in the field.

REFERENCES 1. “SA-1 Khuff-B Development Strategy,” Saudi Aramco Internal Documentation. 2. “Reservoir Properties and Production Data,” Saudi Aramco Field and Well Database. 3. Rahim, Z., Barto, K. and Al-Qahtani, M.: “Hydraulic Fracturing Case Histories in the Carbonate and Sandstone Reservoirs of Khuff and Pre-Khuff Formations, Ghawar Field, Saudi Arabia,” SPE paper 77677, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, September 29 - October 2, 2002. 4. Al-Shehri, D. and Rabba, A.: “Commingled Production Experiences of Multilayered Gas-Carbonate Reservoir in Saudi Arabia,” SPE paper 97073, presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 9-12, 2005. 5. “SA-1 Khuff Simulation Study,” Saudi Aramco Internal Documentation. 6. “PROSPER: Production Data Analysis and Forecasting Software,” Petroleum Experts IPM 7.0. 7. “MBAL: Material Balance Computational Software,” Petroleum Experts IPM 7.0.

BIOGRAPHIES Dr. Zillur Rahim is a Petroleum Engineering Consultant with Saudi Aramco’s Gas Reservoir Management Division. His expertise includes well stimulation design, analysis and optimization, pressure transient test analysis, gas field development, planning and reservoir management. Prior to ing Saudi Aramco, Rahim worked as a Senior Reservoir Engineer with Holditch & Associates, Inc., and later with Schlumberger Reservoir Technologies in College Station, TX, where he used to consult on reservoir engineering, well stimulation, reservoir simulation and tight gas qualification for national and international companies. He has taught petroleum engineering industry courses and has developed analytical and numerical models to history match and forecast production and well testing data, and to simulate 3D hydraulic fracture propagation, proppant transport, and acid reaction and penetration. Rahim has authored 50 Society of Petroleum Engineers (SPE) papers and numerous in-house technical documents. He is a member and a technical editor of SPE and the Journal of Petroleum Science and Engineering (JPSE). Rahim is a ed Professional Engineer in the State of Texas, and a mentor for Saudi Aramco’s Technologist Development Program (TDP). He is also a technical advisor for the Production Technology team and an instructor for the Reservoir Stimulation and Hydraulic Fracturing course at the Upstream Professional Development Center (UPDC) of Saudi Aramco. Rahim received his B.S. degree from the Institut Algerien du Petrole, Boumerdes, Algeria, and his M.S. and Ph.D. degrees from Texas A&M University, College Station, TX, all in Petroleum Engineering. Dr. Hamoud A. Al-Anazi is a Supervisor in the Gas Reservoir Management Division in the Southern Area Reservoir Management Department. His areas of interest include studies on formation damage, fluid flow in porous media and gas condensate reservoirs. Hamoud has published more than 38 papers at local/international conferences and in refereed journals. He is an active member of the Society of Petroleum Engineers (SPE) where he serves on several committees for technical conferences. In 1994, Hamoud received his B.S. degree in Chemical Engineering from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia, and in 1999 and 2003, respectively, he received his M.S. and Ph.D. degrees in Petroleum Engineering, both from the University of Texas at Austin, Austin, TX.

Adnan A. Al-Kanaan is the General Supervisor for the Gas Reservoir Management Division where he heads a team of more than 30 petroleum engineering professionals to meet the Kingdom’s increasing gas demand for internal consumption. He started his career at the Saudi Shell Petrochemical Company as a Senior Process Engineer. Adnan then ed Saudi Aramco in 1997 and was an integral part of the technical team responsible for the on-time initiation of the two major Hawiyah and Haradh gas plants that currently process 4 BCF of gas per day. He also manages Karan and Wasit, the two giant offshore gas increment projects, with expected total production capacity of 4.3 BCF of gas per day. Adnan has 13 years of diversified experience in reservoir management, field development, reserves assessment, gas production engineering and mentoring young professionals. His areas of interest include reservoir engineering, well test analysis simulation modeling, reservoir characterization, fracturing analysis and reservoir development planning. Adnan received his B.S. degree in Chemical Engineering from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia. He is a member of the Society of Petroleum Engineers (SPE). Ahmad Azly Abdul Aziz is currently the Lead Engineer for the ‘Uthmaniyah gas fields in the Gas Reservoir Management Division. He has 20 years of diversified experience in reservoir management for oil and gas reservoirs. Ahmad’s expertise includes general reservoir engineering, well testing, and planning and development of oil and gas reservoirs. Prior to ing Saudi Aramco, he held senior positions in reservoir engineering in Qatar Petroleum and Petronas Carigali Vietnam. In 1989, Ahmad received his B.S. degree in Petroleum and Natural Gas Engineering from Pennsylvania State University, University Park, PA.

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Detection of Drag Reducing Agents (DRAs) in Fuels Using Laser Induced Fingerprints Author: Dr. Ezzat M. Hegazi

ABSTRACT To streamline the flow of liquid hydrocarbon fuels, such as gasoline, diesel and jet fuels in distribution pipelines, calculated amounts of a polymer based Drag Reducing Agent (DRA) is often injected into the pipelines at the pump stations. The mixing of the polymer based DRA with the hydrocarbon fuel has the effect of decreasing the friction between the turbulent flow of the fuel and the walls of the pipelines, and in turn, leads to considerable reduction in the pipeline shipping costs. The polymer based DRA is originally made of long chains of poly-alpha-olefin polymers having a high molecular weight. As it travels through the pipes, it gradually breaks up into smaller molecular chains due to mechanical shearing action. When the fuel reaches its final destination in the pipeline system, the injected DRA does not necessarily disappear completely; there will always be some residual amounts of the long chain polymers in the fuel in addition to other amounts of sheared and partially sheared polymers. International aviation rules do not permit the use of DRA in turbine fuel, and as such, the residual DRA remaining in the pipeline system is considered troublesome if jet fuel is to be transported through the DRA contaminated pipelines. The general practice in this case is to clean the pipeline system down to zero levels of DRA by flushing the pipelines with a considerable amount of DRA free fuel. Therefore, an effective and fast method for detecting traces of DRA in fuels is needed. The conventional method for detecting DRA is based on a molecular size monitoring technique, such as gel-permeation chromatography, which in itself is a lengthy and rather complex technique. This article describes an alternative method, stemming from the application of a newly introduced laser induced fluorescence technique. The technique is described in two U.S. Patents: Pat No. 66330431 and Pat No. 7560711B22, in addition to Hegazi et al., 2001.

EXPERIMENTAL The setup and modes of operation are described in detail in the previously mentioned patents. In brief, the method relies on measuring the laser induced fluorescence (LIF) spectra within adjacent narrow time gates (3-5 ns) when the fuel is 34

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excited by short laser pulses of ultraviolet (UV) radiation. The resulting LIF spectra, which represent graphs of fluorescence intensity as a function of emission wavelength, show different shapes and intensities that are unique to the fuel being tested. These LIF spectra are displayed as contour diagrams featuring the normalized intensity of the LIF as a function of both emission wavelength and time gate. In this study, the fuel samples are irradiated with pulsed UV laser beams at 266 nm, and the LIF from the sample is detected at a 90° angle to the incident laser beam. A dispersing device, such as a spectrograph coupled with a time gated intensified charge coupled device (ICCD), is used to measure the intensity of the wavelength resolved LIF in a short spectral range between approximately 300 nm and 550 nm. The narrow time gates during which the measurements were made were 3 ns in width. The present method uses a comparison methodology; i.e., the contour diagram of the tested fuel sample is always compared to the contour diagram of a standard fuel sample free of the Drag Reducing Agent (DRA) to determine whether the tested sample is contaminated or not. Comparisons with the contour diagrams of prepared standard samples with known concentrations of DRA are also used to confirm the trend in the contour changes. For this study, the DRA polymer was prepared in a solid form by freeze-drying the liquid commercial product. An amount of 5 mg of the solid DRA polymer was dissolved in 500 ml of the fuel (gasoline, jet fuel or diesel fuel) by means of a magnetic stirrer that was kept running overnight. The standard concentrations of DRA were 0, 0.5, 1, 2, 5, 10 and 15 ppm and they were left for more than 24 hours before the measurements were carried out.

RESULTS AND DISCUSSION The polymer based DRA is a pure hydrocarbon whose chemical structure cannot be distinguished from other hydrocarbon molecules when using conventional techniques. In addition, the DRA polymer has no UV chromophores, so it does not fluoresce when irradiated by UV light. Consequently, the laser based spectral fingerprinting technique cannot monitor the DRA directly, although it can detect the effect the DRA polymer has on the time resolved LIF spectra.

As previously mentioned, the laser based spectral fingerprints are constructed in the form of fluorescence intensity vs. emission wavelength and time gate simultaneously, which typically gives two-dimensional contours. Two types of fingerprints were used in this study. One is the first order fingerprint, which is usually sufficient to discriminate between samples having considerable spectral differences, such as gasoline having high concentrations of DRA. A full description of this type of fingerprint can be found in U.S. Patent No. 66330431. The second type of fingerprint is the result of spectral subtraction of the normalized spectra. This type is capable of discriminating between samples of closely similar spectra. A description of the latter type of fingerprint can be found as one of the innovative points in U.S. Patent No. 75607112. The first order spectral fingerprints as measured in the case of jet fuel with and without a polymer DRA contamination of 10 ppm are shown in Fig. 1. The measurements were repeated at least twice to confirm the reproducibility of the results. It is clear that the first order fingerprints are adequate for monitoring the DRA contamination at such high ppm concentration in jet fuel. Figure 2 shows the spectral subtraction fingerprints of gasoline with and without freeze-dried DRA contamination. The DRA concentrations are 0, 1, 2, 5, 10 and 15 ppm. It can be seen that there is a clear trend in the changes of the contour diagrams as the amount of DRA concentration is increased in the gasoline fuel.

The effect of freeze-dried DRA on diesel fuel is shown in Fig. 3, also using the spectral subtraction fingerprints. The concentrations of DRA were the same as in the case of the gasoline, i.e., 0, 1, 2, 5, 10 and 15 ppm. Once again it is clear that the laser based technique is successful in not only in detecting the presence of DRA, but also in providing a systematic trend in the changes of the fingerprints as the DRA concentration is increased in the diesel fuel. Finally, Fig. 4 shows how the spectral subtraction fingerprints can be successfully used to monitor the cleaning of a DRA contaminated pipeline. Here the pipeline was utilized to transport 91 octane grade gasoline to which polymer DRA had been added at the pump station. When the time came to transport jet fuel, the pipeline had to be cleaned of the DRA residue prior to pumping the aviation grade jet fuel. The cleaning was done by pumping DRA free gasoline through the pipe and the laser based technique was used to monitor the flushing procedure. It can be seen that the fingerprints readily describe how the DRA contaminated pipeline is getting cleaned as it is being flushed with 2,500 barrels, 10,000 barrels and 15,000 barrels, respectively, of blank gasoline.

CONCLUSIONS The following are the conclusions drawn from the present study: 1. The laser fingerprinting technology is very effective in detecting the DRA polymer. All tests show a systematic

Fig. 1. First order spectral fingerprints for DRA free (blank) jet fuel and DRA contaminated jet fuel (10 ppm).

Fig. 2. Spectral subtraction fingerprints for DRA free (blank) gasoline and DRA contaminated gasoline (0, 1, 2, 5, 10 and 15 ppm from left to right).

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Fig. 3. Spectral subtraction fingerprints for DRA free (blank) diesel fuel and DRA contaminated diesel fuel (0, 1, 2, 5, 10 and 15 ppm from left to right).

Fig. 4. Spectral subtraction fingerprints for DRA free (blank) gasoline (contour diagram on the left) and DRA contaminated gasoline in a pipeline that is being cleaned by flushing blank gasoline through it.

pattern change in the blank fuel fingerprint as the DRA concentration is increased. 2. The technology is well established by now and is able to detect DRA concentrations in the sub-level ppm range, suring any other conventional method. 3. The DRA polymer can be effectively washed out of gasoline pipelines by flushing with clean fuels. It is strongly recommended that the flushing operation be combined with a monitoring procedure since the pipelines are always subject to unexpected DRA accumulations. 4. There is no alternative to measuring the spectral fingerprints of the original blank fuel samples along with those of the samples collected from the field to perform the comparison. Workers collecting the DRA samples must be aware of the best practices procedure recommended for the collection operation. According to the laser based results provided in this article, the pipeline network can greatly benefit from using the developed laser based technology in monitoring DRA contamination. It is the author’s belief that considerable cost savings could be achieved if the technology is utilized in-situ at different pipeline locations. The Research and Development Center (R&DC) in Saudi Aramco has already revealed a fully developed commercial portable laser instrument for measuring DRA contamination in fuels. Similar instruments can be ordered and delivered within a period of 4 - 6 months.

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ACKNOWLEDGMENTS The author would like to thank the management of Saudi Aramco for permission to publish this article. The author wishes to thank N. Fayad for his initial collaboration and M. Al-Sayegh for helping with the sample preparation.

REFERENCES 1. Hegazi, E., Hamdan, A. and Mastromarino, J.: U.S. Patent No. 6633043, “Method for Characterization of Petroleum Oils Using Normalized Time-Resolved Fluorescence Spectra,” 2003. 2. Hegazi, E.: U.S. Patent No. 7560711B2, “Multiple Fingerprinting of Petroleum Oil Using Normalized TimeResolved Laser-Induced Fluorescence Spectral Subtraction,” 2009. 3. Hegazi, E., Hamdan, A. and Mastromarino, J.: “New Approach for Spectral Characterization of Crude Oil Using Time-Resolved Fluorescence Spectra,” Applied Spectroscopy, Vol. 55, Issue 2, February 2001, pp. 202-207.

BIOGRAPHIES Dr. Ezzat M. Hegazi is currently a Science Specialist at the Research & Development Center (R&DC) with a specialty in laser-induced fluorescence techniques on gases and liquids. Prior to ing Saudi Aramco, he was an Associate Professor in the Physics Department at King Fahd University for Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia. Since ing Saudi Aramco in October 2007, Ezzat has been focusing on originating innovative, laser-based analytical techniques related to company operations and developing them into stand-alone measuring instruments, one of which is the recent instrument for oil spectral fingerprinting. He has several patents and more than 50 publications related to laser-induced fluorescence techniques in petroleum oils, supersonic gases, metal amalgam vapors and cable insulators, in addition to other optics related techniques. In 1985, Ezzat received his M.S. degree from the Catholic University of America, Washington, D.C., and in 1989 he received his Ph.D. degree in Physics from the University of Windsor, Ontario, Canada.

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Application of an Innovative Ceramic Centralizer for a Solid Expandable Liner Authors: Dr. Shaohua Zhou, Syed Mohammed Mansoor Kamal and Tom Sanders

ABSTRACT

• Isolating the gas cap above the reservoir.

Traditionally, solid expandable liners have been run without any centralizers due to the perceived risk involved, since typical centralizers would impose extra restrictions on the pipe body, which would then require additional force to expand. Also, the centralizers may break during running in hole (RIH), which would lead to a possible stuck liner, and consequently, be a major problem for liner expansion. It’s also important to realize that there is a limited running clearance if conventional centralizers are utilized, which puts a lot of constraints on the type and availability of possible centralizers. As a result of running without centralizers some residual mud may remain on the low side of the hole during cementing operations, since it is not possible to rotate the expandable liner while cementing nor to reciprocate the liner after reaching setting depth to avoid possible damage of the expandable casing’s connection protection sleeves across the previous 7” casing shoe or window exit. Consequently, the cement bond between the expanded casing and the formation would be limited, and longterm isolation may be less than required. Recently, an innovative ceramic centralizer was evaluated and implemented in the field. The ceramic centralizer consists of three individual pads affixed to the expandable casing, 120° offset to each other, with three centralizers equally spaced out along the middle part of the 38 ft expandable casing t. The pad itself is made of a carbon fiber ceramic composite material that is characterized by extreme toughness. Once it is bonded to the base pipe, it is not possible to remove it, even with 180,000 lbs of force. It has a lower friction factor than casing and is corrosion resistant. After tailoring the pad design to suit a 5½” expandable liner, cemented expandable liners with such centralizers were successfully run in five wells without any problem. The acquired ultrasonic image tool (USIT) log demonstrated that the cement bond created while using such centralizers was substantially better than bonds made without the use of any centralization.

• Extending the existing 7” liner to convert a 1 km horizontal well to a smart maximum reservoir (MRC) well. • Extending the 7” liner in the event that the liner is stuck off bottom. • Providing cemented zonal isolation of the built section from a 7” window exit to reservoir target entry. • Serving as a casing patch for corroded casing1-9. Traditionally, solid expandable liners have been run without any centralizers due to the perceived risk involving the liner running and expansion. Subsequently, it was inevitable that some residual mud would remain, Fig. 1, since the liner was not rotated while cementing due to the limitations of the expandable tubular connections’ torque capability. Also, the liner was not typically reciprocated after reaching the setting depth to avoid possible damage to the expandable casing’s connection protection sleeves across the previous 7” casing shoe or window exit. Consequently, the cement bond between the expanded casing and the formation would be limited, and long-term isolation may be less than required. Over the years, this limitation has been highlighted, and a continued effort was made toward identifying possible centralizers that can enhance zonal isolation of the expanded horizontal liner, but not impose operational risk. It is recognized that conventional centralizers may not be suitable because: (1) They impose extra restrictions on the

INTRODUCTION Solid expandable liners have been used extensively in the Kingdom of Saudi Arabia over the last 7 years, primarily in reentry workover wells to provide zonal isolation and to enable a larger drilling and completion internal diameter (ID) than is the case with unexpanded liners. The applications included: 38

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Fig. 1. A rough schematic of the situation with a 5½” expanded liner without the centralizer.

Fig. 2. Basic carbon fiber ceramic centralizer design (left) and a photo of ceramic centralizer at rig floor (right).

expandable pipe body, which would in turn require additional force to expand, and (2) Traditional centralizers may break during running in hole (RIH), which would lead to a possible stuck liner, and consequently, create major problems during the expansion of the liner. It’s also important to realize that there is a limited running clearance (maximum of 0.65” in the case of running a 5½” expandable liner through a 7” 26 lb/ft casing), which puts a lot of constraints on the type and availability of possible centralizers that can be utilized. The second point worth mentioning is that solid expandable liners are required to be run in the open hole much faster than expected, particularly in porous reservoir sections, due to repeated observations that expandable liners using an inner work string have a tendency toward differential sticking because of a larger pipe outside diameter (OD) than typical drillpipe and equivalent heavy pipe. Consequently, the lesson learned is: To avoid sticking the liner before reaching setting depth, the liner should be run once inside the open hole’s permeable formation as quickly and as safely as possible. Sticking can also be avoided by minimizing connection time during the running of the liner. As a result, any centralizer that is utilized has to be durable, tough and not easily broken during such rig operations.

• Each centralizer is set with three individual pads. • Each pad is 0.25” thick. • Each pad is about 1 ft long. • The pads are at a 120° offset. • There is a 1.3 ft offset gap between the pads. • Total coverage of the centralizer set is 5.6 ft. To qualify the product for field deployment, the following test data was obtained and evaluated. First, to assess the risk of possible centralizer breakage during RIH, the product was tested for scraper wear (also toughness), Fig. 3. The test proved that this is a very tough and hard material. The wear test can be summarized as: • Rotated at 30 rotations per minute (rpm) for 4.5 hours. • Run for 10.5 hours.

CERAMIC CENTRALIZER FOR EXPANDABLE LINER Recently, after an innovative product was evaluated, it was decided to trial test it in the field in June 2008. The product was developed and patented by ENI SpA10 as an alternative to conventional centralizers for use in their lean profile wells. The product is essentially a carbon fiber ceramic composite material molded and bonded directly to the tubular11. It was decided to tailor an optimal design for expandable tubular centralization, Fig. 2, which is characterized as:

Fig. 3. Photo of ceramic centralizer (or pad) post wear test. SAUDI ARAMCO JOURNAL OF TECHNOLOGY

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• Start thickness was 11.8 mm. • Finish thickness was 11.4 mm. • Wear was 0.4 mm. Next, the product was tested to its bondage to the casing body. As shown in Fig. 4, it is not possible even with 180,000 lbs force to remove the pad from the casing once it is properly glued onto the pipe body. Further surface tests were conducted to evaluate both friction and torque in comparison with steel, Fig. 5. The centralizers demonstrated a much lower friction and torque compared with bare casing. Therefore, it was concluded that the utilization of the centralizer would greatly facilitate running the expandable liner into the wellbore. In addition to the previously mentioned tests, the product was subjected to corrosion testing. The test condition described

below simulated possible downhole conditions in a very corrosive environment. The centralizers successfully ed the test without any noticeable reduction in material hardness. The autoclave test condition for corrosion resistance is listed as: • Test temperature = 200 °F. • Test pressure = 500 psig. • Liquid composition = 10% NaCl brine. • Gas composition = 5% CO2, 15% H2S, 80% N2. • Test duration = 6 days. It was concluded that the centralizer product would be ideally suited for use with an expandable liner due to the following characteristics: • Very high adhesion to the substrate. • Impact resistance. • Overall toughness. • Flexibility. • Low friction coefficient reducing torque and drag. • Versatility – any geometry, any thickness and any location. • Corrosion resistance.

Fig. 4. Photo of ceramic centralizer (or pad) post adhesion to substrate pull test (after 180,000 lbs force).

Finally, because the product is a carbon fiber composite material, it is highly possible that ceramic pad breakage during liner expansion may occur. To address the implication for the liner cement bond, a simple analysis was carried out. It should be noted that typically the cement slurry is pumped before the liner is expanded, and therefore, the cement is placed around the centralized liner before expansion. As illustrated in Fig. 6, if the ceramic pad is on the bottom to provide some standoff for the cement slurry, there is little

Fig. 5. Surface tests demonstrated much lower friction and torque in ceramic centralizer compared with bare casing.

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concern because there should already be some cement slurry coverage due to the standoff provided by possible broken pad pieces. If the pad is on the side or top of the pipe, it is even less of a concern since the cement slurry would be present anyway.

FIELD IMPLEMENTATION ON EXPANDABLE LINER After the detailed analyses, it was decided to install the ceramic centralizers on 33 ts of 5½” expandable tubulars as a first experiment. The centralizer installation process was simple and straightforward, and can be summarized as:

1. Sandblast and clean the part of the tubular where the ceramic centralizer is to be molded and bonded. 2. Inject the carbon fiber ceramic mixture into a pre-made plastic or aluminum master mold fixed onto the pipe. 3. Let it cure (dry) - usually within 30 hours. 4. Polish and test the centralizer to ensure the final hardened pad of each set meets the pre-design dimensions previously mentioned. To reduce operational risk during initial implementation in the field, only eight ts with centralizers were incorporated into the bottom section of the expandable liner. The operation is summarized as: 1. The first well had the longest open hole expandable liner (2,306 ft) in the field. 2. The liner was run into the well and had about 1,683 ft in the open hole when it became differentially stuck. Although at first it seemed this could be blamed on the centralizers, detailed reviews of all previous expandable liner runs indicated the eight ts with centralizers actually enabled running approximately 300 ft extra into the open hole. Differential sticking of liners was a common risk, particularly for long liners in this field.

Fig. 6. A rough schematic of the situation with a 5½” expanded liner with centralizer.

3. Compared with all previous expandable liner runs in the field, this run achieved the longest liner length to date in the horizontal open hole (considering the fact that the reservoir had always been very prone to differential sticking).

Fig. 7. Rig (left) and cement unit (right) recorded data during expansion of 5½” liner with centralizers.

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4. No additional expansion pressure was required, nor was any overpull seen, during the hydraulic expansion of the liner interval with centralizers, Fig. 7. After the first successful deployment of the ceramic centralizers on an expandable liner, four more expandable liners with these centralizers were successfully deployed without any problem in the same field. Table 1 shows the summary of runs implemented so far. The centralizers were generally installed on the bottom sections of the cemented expandable liners. Finally, to the cement bond result, two USIT logs were acquired for comparison with logs from two separate wells, both installed with the same size of cemented expandable liner in the same wellbore environment within the same field, one Well Name Well A Well B Well C Well D Well E

Pre-exp Liner Length, ft 2,306 508 1,005 1,143 1,357

Number of ts with Centralizers 8 10 15 12 14

Table 1. Rate test results of newly drilled seven horizontal wells in the Arab-D reservoir

Fig. 8. Cement evaluation logs associated with two expandable liners.

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with centralizers and the other without. Figure 8 illustrates the USIT log comparison, which clearly indicates that the centralizers substantially improved the cement bond quality. In summary, the following are lessons learned: 1. The deployed ceramic centralizer did not add any extra hole drag (in fact it helped provide some standoff and reduced friction. It may be worthwhile to consider adding more ts with centralizers for future long expandable liners, particularly in a reservoir prone to differential sticking). 2. This kind of centralizer did not affect liner expansion (there was no extra expansion pressure or overpull required to expand through the ts with centralizers). 3. Because of the design, adding this kind of centralizer onto an expandable t casing was seen to improve cement coverage around the pipe, and therefore to provide better zonal isolation. 4. The standoff percentage on the t can be easily improved by slightly modifying the design of the ceramic centralizers (i.e., extending each pad’s length and thickness). The current plan is to apply such centralizers on cemented expandable liners to improve the cement bond and zonal isolation, ultimately prolonging well life and reducing well cost.

CONCLUSIONS 1. An expandable liner with this type of centralizer encountered much less hole drag, and therefore was able to run a longer liner length. 2. There was no noticeable effect on the liner expansion.

5. Salamy, S.P., Al-Mubarak, H.K., Hembling, D.E. and AlGhamdi, M.S.: “Deployed Smart Technologies Enablers for Improving Well Performance in Tight Reservoirs – Case: Shaybah Field, Saudi Arabia,” SPE paper 99281, presented at the SPE Intelligent Energy Conference and Exhibition, Amsterdam, the Netherlands, April 11-13, 2006.

3. The USIT logs acquired from two wells (one with centralizers and one without) clearly demonstrate that the cement bond was much improved through the use of these types of centralizers.

6. Rivenbark, M. and Abouelnaaj, K.: “Solid Expandable Tubulars Facilitate Intelligent Well Technology Application in Existing Multilateral Wells,” SPE paper 102934, presented at the SPE ATCE, San Antonio, Texas, September 24-27, 2006.

ACKNOWLEDGMENTS

7. Al-Umran, M.I., Al-Obaidi, I.A., Zhou, S. and Al-Nassir, A.: “Solid Expandable Tubular Technology Applications in Saudi Arabia: Lessons Learned,” IADC/SPE paper 111871, presented at the IADC/SPE Drilling Conference, Orlando, Florida, March 4-6, 2008.

The authors would like to thank the management of Saudi Aramco, Weatherford and Protech Centreform (now part of Halliburton) for permission to publish this article.

REFERENCES 1. Zhou, S., et al.: “Saudi Aramco Lessons Learned from Expandable Tubular Applications,” paper presented at the SPE Applied Technology Workshop on Expandable Technology, Phuket, Thailand, July 22-25, 2004. 2. Morrison, W., Baggal, Z., Baxendale, B. and Boudreaux, R.: “Optimizing Wellbore Design Using Solid Expandable Tubular and Bi-center Bit Technologies,” SPE paper 92886, presented at the 14th Middle East Oil and Gas Show and Conference, Manama, Bahrain, March 12-15, 2005. 3. Jeffre, A.M., Al-Dossary, A.S., Zhou, S., Al-Hajji, A.A., Al-Khanferi, N.M. and Al-Jaafari, S.M.: “World’s First MRC Window Exits Out of Solid Expandable Open Hole Liner in the Shaybah Field, Saudi Arabia,” SPE/IADC paper 97514, presented at the SPE/IADC Drilling Technology Conference and Exhibition, Dubai, U.A.E., September 12-14, 2005.

8. Al-Umran, M.I., Al-Amri, K.M., Ahmed, I., et al.: “New 5½” Solid Expandable Systems Provide Effective Technology for Successful Workover Project in Saudi Arabia,” SPE paper 120797, presented at the SPE Saudi Arabia Section Technical Symposium, al-Khobar, Saudi Arabia, May 10-12, 2008. 9. Sanders, T., Zhou, S., York, P., Joulaud, T., Teo, J. and Gandikota, R.: “Installation and Operational Performance of Horizontal Solid Expandable Open Hole Production Liners in Maximum Reservoir Wells – Case Histories,” SPE paper 124965, presented at the SPE ATCE, New Orleans, Louisiana, October 4-7, 2009. 10. Baynham, R., et al., (ENI S.p.A.): Integral Centraliser, U.K. patent GB 2396877B, O/2004/015238. 11. Protech CRB Centralizers, Halliburton Cementing Documents, H060735.

4. Bargawi, R.A., Zhou, S., Al-Umran, M.I. and Aghnim, W.: “Expandable Tubular Successfully Scabs Off Severe Casing Leaks,” SPE/IADC paper 97357, presented at the SPE/ IADC Drilling Technology Conference and Exhibition, Dubai, U.A.E., September 12-14, 2005.

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BIOGRAPHIES Dr. Shaohua Zhou is a Petroleum Engineering Consultant with the Drilling Technology Team, Exploration and Petroleum Engineering Center Advanced Research Center (EXPEC ARC) where he works primarily in drilling technology research and field implementation. Prior to ing Saudi Aramco in 2001, Shaohua was with Baker Atlas (a division of Baker Hughes Inc.) as Geomechanics Coordinator for Europe and Africa, responsible for product development and oil field services for a number of oil and gas operators. He has published numerous papers and between 2002 and 2004 was a technical editor for the Society of Petroleum Engineers’ (SPE) Drilling & Completion Journal, receiving the 2003 SPE Outstanding Editor Award. Shaohua holds a Ph.D. in Geoscience from the University of Adelaide, Adelaide, Australia, and B.S. and M.S. degrees in Applied Geophysics from Chengdu University of Technology, Chengdu, China. Syed Mohammed Mansoor Kamal ed Saudi Aramco as a Workover Engineer in December 2006, and is involved in the planning and execution of sidetracks through expandable liners that mostly compete with smart well completions, mechanical workovers and safety workovers. He began his career in 1994, working for 2 years in Shell Pakistan Ltd. as a Fueling Superintendent. From 1996 to 2006 Syed worked for Pakistan Petroleum Ltd. in Karachi as a Senior Drilling Engineer, involved in the design and execution of appraisal high-pressure/high temperature (HP/HT) gas wells and exploratory wells. In 1994, he received his B.S. degree in Mechanical Engineering from NED University of Engineering and Technology, Karachi, Pakistan. Tom Sanders is the Solid Expandables MENA/North Africa Regional Manager for Weatherford International Ltd. He has been involved in solid expandable casing technology operations and development since 2000, when he was working with Halliburton. Tom has a total of over 32 years of international experience, with over 10 years of experience in the development of Solid Expandable Technology in the Middle East for various customers. He is a member of the Society of Petroleum Engineers (SPE) and has written several articles on solid expandable technology.

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Production Enhancement of Hilly Terrain Onshore Remote Fields Authors: Shadi M. Hanbzazah, Mohammed N. Merwat and Dr. Mohammed N. Al-Khamis

ABSTRACT Developing and producing remote fields in a hilly terrain environment economically and effectively poses a great challenge to oil operators1. Transporting hydrocarbon fluids in these fields from the wells to the processing facilities and then to shipping terminals requires a detailed assessment of the flow hydraulics of the entire production network2-6. Moreover, a viable optimizing flow option needs to be considered and thoroughly evaluated prior to implementation for cost optimization, effectiveness and long-term impact on reservoir sweep7. Saudi Aramco has recently embarked on the development of several fields, including remote fields, such as Shaybah, which is located in a remote, hilly terrain desert area in the Empty Quarter of the Arabian Peninsula. The crude from Shaybah’s oil producing wells must travel a long distance from wellheads located in Sabkhah (flat terrain) to the gas-oil separation plant (GOSP), ing across high sand dunes ri to 200 m, and then through a 638 km cross-country pipeline to reach a final stabilization facility. Due to the aberrant topography of the area, high back pressure and changes of flow regime, huge slugs have been observed, affecting the overall performance of the wells and the operation of the processing facilities. Consequently, three innovative technologies: Horizontal Thrust Boring (HTB), multiphase pumps, and Drag Reducing Agents (DRAs), have been evaluated and implemented to circumvent these problems. This article will discuss in detail the realized benefits from these three technologies where results have shown a reduction in the flow and pipeline pressure with drops of 230 psig and 300 psig after the application of HTB and DRAs, respectively. Moreover, an overall production increase of about 50 thousand barrels of oil per day (MBOD) was realized from the utilization of HTB technology, and an incremental increase of 250 MBOD in the capacity of the 638 km cross-country pipeline resulted from the utilization of the DRAs. On the other hand, the results of the trial test of the multiphase pump have indicated unsatisfactory performance due to the frequent maintenance needs and pump failures.

technological evolution since the late 1990s. The field is located in a very remote desert area of the Arabian Peninsula, which is characterized by elevated unconsolidated sand dunes that rise more than 200 m above the desert floor. Interspaced between the sand dunes are flat areas called Sabkha. Due to the hilly terrain and sand dune environment, wells and facility development are being limited to the flat Sabkha areas only, Fig. 1. In this field, all wells are completed in a single producing reservoir, which is driven by an overlaid gas cap. The reservoir also undergoes a litho-faces change, with a gradual reduction in reservoir permeability from the Northern to the Southern part of the field. The average permeability in the Southern part of the field decreases to as low as 5 millidarcies (mD) compared to 50 mD in the Northern part of the field. Shaybah field produces Arabian Extra Light crude with an API gravity of 42° and with an average gas-oil ratio (GOR) of 1,200 standard cubic ft/stock tank barrel (scf/stb). Crude from each Sabkha area is transported via flow lines to a common production header located within the Sabkha and then via trunk lines that generally over several sand dunes that rise up to 200 meters before they finally reach the processing facility, Fig. 2. The length of the flow lines inside the Sabkha’s range from 100 m to 200 m while the total trunk line lengths range from 6 km to 19 km. The combination of the frequent and vast changes in trunk line elevation along with the relatively high GOR produced crude oil creates operational difficulties at both ends of the production trunk lines. At the inlet of the trunk lines, large,

INTRODUCTION Shaybah field is one of the fields in Saudi Arabia that has recently under gone major development with the new

Fig. 1. Entrance of field trunk lines to the oil processing facility in a Sabkha area. SAUDI ARAMCO JOURNAL OF TECHNOLOGY

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Fig. 2. Typical route of trunk lines in Shaybah field.

in upstream flow lines to circumvent the impact of high back pressure on the wells’ performance. Before proceeding with the project design phase, a frontline engineering study and extensive simulation were performed using actual field data. Information obtained from simulation models indicated very promising results, subsequently, a pilot field test was approved prior to the implementation of HTB on a large scale. The pilot was then carried out where a 16” diameter by 900 m long flow line was laid through an unconsolidated sand dune connecting two Sabkha areas, Fig. 4. These two Sabkhas were selected because the distance between them is relatively short, which was within the HTB drilling rig limit at the time, and the exerted back pressure on the wells in this area is rather high. For this operation, the optimum pipe size was selected based on the criteria of having a maximum pressure drop of 3 psi/km and a minimum liquid velocity of 5 ft/sec to prevent water accumulation in the low section of the pipe and therefore minimize pipe corrosion. As a result of the HTB field pilot application, four previously dead wells on the far Sabkha were successfully revived, and a total production gain of 10 thousand barrels of oil per day (MBOD) has been realized. The four wells were revived as a result of a 160 psig reduction in wellhead back pressure, Fig. 5.

HTB LARGE SCALE IMPLEMENTATION Fig. 3. Fluctuation of pressure at the inlet of the production trunk lines.

Based on the positive results from the pilot test, two additional 20” trunk lines were laid under the sand dunes

fluctuating back pressure is causing some of the wells to cease to flow, Fig. 3, while at the exit end, huge gas slugs are being generated, which require special handling at the processing facilities. The impact of the back pressure is more pronounced at the Southern section of the field since the reservoir rock there is relatively poor. To overcome the impact of high back pressure on the wells’ performance, the following options have been evaluated: • Lay down trunk lines under the sand dunes utilizing Horizontal Thrust Boring (HTB) technology. • Install multiphase pumps at the surface. • Use electrical submersible pumps.

Fig. 4. HTB field pilot layout.

• Construct a new satellite processing facility. • Attempt to reduce the inlet pressures of existing processing facilities. Among these options, HTB technology was initially determined to be the most viable choice to reduce the back pressure on the wells, and consequently, improve their performance wherever applicable, within the drilling reach limit of this technology.

HTB SIMULATION AND FIELD PILOT TESTING Although HTB technology has been widely used for installing downstream pipelines across highways and roads, Saudi Aramco has pioneered this technology using it for the first time 46

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Fig. 5. Reduction in back pressure from the HTB field pilot.

connecting five Sabkha areas with the gas-oil separation plant (GOSP). The distance the two trunk lines traversed was 28 km. Of that length, 10.8 km lay under the sand dunes at seven separate locations, Fig. 6. The seven sand dune segments were carefully selected to increase the production from as many dead and marginally producing wells as possible. For this project, extra measures were taken to minimize the possibility of pipe leaks under the sand dunes. A relatively thicker pipe was used, and the line was equipped with both a corrosion inhibitor and scraping facilities. The selection of two smaller trunk lines, instead of one bigger trunk line, was selected for the following reasons: • The boring rig could not lay a pipeline greater than 20” in diameter through the required length of sand dunes. • Smaller trunk lines reduced the risk of bored section cave-ins, as earlier experience has showed cave-ins usually occur in large pipe sizes (30” - 36”). • The dual pipes provide a backup capacity, which will ensure uninterrupted crude production. A total of 24 wells in the subject Sabkhas were tested prior to and after the commissioning of the HTB flow lines, and results indicated a total production gain of 40 MBOD with 10 wells being revived after being dead due to the high initial back pressure. Moreover, the wellhead back pressure was reduced by 10 psig to 150 psig as a result of the new flow line layout, Fig. 7. Based on these encouraging results, further

Fig. 6. HTB main project layout.

drilling development in Shaybah’s Southern section has been performed in recent years now that newly completed wells in this tight reservoir area can flow naturally.

DRAG REDUCING AGENT (DRA) Unstabilized crude from Shaybah field is transported from the field Central Producing Facility (F) to a stabilization plant via a 640 km cross-country pipeline. This pipeline was designed to handle a production rate of about 655 MBOD. Recently, the field’s production capacity was increased to reach a total rate of 840 MBOD, which far exceeds the design capacity of the original pipeline. Therefore, the following options to circumvent the pipeline capacity limitation were evaluated: • Building an additional new 640 km cross-country pipeline or constructing a partial line and looping it to the existing line. • Installing an intermediate pump station in the 640 km cross-country pipeline. • Using Drag Reducing Agents (DRAs). Among the three evaluated options, the third option was found to be the most economical. To achieve this objective, two DRAs were tested in the field starting from the F to study their effectiveness and determine both the required injected chemical volumes to achieve the desired crude production rate and the cost of the chemical for every produced barrel of crude oil. The first chemical was tested for 37 days in dosages that varied from 10.1 ppm to 27.2 ppm. Results of the tests indicated a 63% reduction in frictional pressure drop, Table 1. Similarly, the second chemical was tested for two weeks at three dosage rates (5 ppm, 10 ppm and 16 ppm) and with an average flow rate of 625 MBOD. In this case, results of the tests indicated a 55% reduction in frictional pressure drop. In addition, the required chemical treatment volume required to achieve the same results was found to be approximately 47% more than that of the first chemical. The chemical selection was finally based on the economics, as the price per volume of each chemical is different. Finally, the results of both tests indicated that the line capacity can be increased to meet the desired flow rate of 840 MBOD with the utilization of DRAs. Inlet Pressure (psig) 580 411

Outlet Pressure (psig) 80 113

ΔP (psig)

620 620

DRA Injection Rate (ppm) 0.0 10.1

620 622 630

15.5 21.0 27.2

389 391 375

160 172 177

229 219 198

Oil Rate (MBOD)

Fig. 7. Reduction on back pressure from the main HTB project.

500 298

Table 1. Test results of the first DRA

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MULTIPHASE PUMP PILOT TEST

REFERENCES

The objective of trial testing the multiphase pump was similar to the HTB objective in that both overcome high back pressure and help in reviving dead wells. For this test, a new location was selected, one where the distance between the two Sabkha areas is beyond the reach of current HTB technology. The pump was designed, Fig. 8, based on observed operational conditions and for the purpose of reviving three dead wells at this location8. Following the pump commissioning, a production gain was realized, however, the gain did not last long due to operational difficulties with the pump, necessitating frequent maintenance.

1. Taylor, N.F.: “Managing Remote Field Operations in the Cooper-Eromanga Basin, Australia,” SPE paper 29914, presented at the International Meeting on Petroleum Engineering, Beijing, PR China, November 14-17, 1995. 2. Zheng, G., Brill, J.P. and Shoham, O.: “Hilly Terrain Effects on Slug Flow Characteristics,” SPE paper 26566, presented at the 68th SPE Annual Technical Conference and Exhibition, Houston, Texas, October 3-6, 1993. 3. Hill, T.J., Fairhurst, C.P., Nelson, C.J., Beeerra, H. and Bailey, R.S.: “Multiphase Production through Hilly Terrain Pipelines in Cusiana Oil Field, Colombia,” SPE paper 36606, presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, October 6-9, 1996. 4. Alvarez, C.J. and Al-Awwami, M.H.: “Wet Crude Transport through a Complex Hilly Terrain Pipeline Network,” SPE paper 56463, presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, October 3-6, 1999.

Fig. 8. Multiphase pump.

CONCLUSIONS Three innovative technologies have been tested to enhance the production of Shaybah field, which is located in hilly terrain in a remote onshore area. The following is a summary of the major findings: • HTB technology has proven to be the most effective and economical means to overcome the high back pressure in this hilly terrain environment. • As a temporary solution, the use of DRA chemicals has helped significantly in maximizing the production capacity of a cross-country pipeline. Nonetheless, for a long-term solution, a full economical study will be required to determine the viability of DRA use. • The performance of the multiphase pump was determined to be unsatisfactory due to the intensive maintenance required.

ACKNOWLEDGMENTS The authors would like to thank the management of Saudi Aramco for permission to publish this article. Appreciation is expressed to the Northern Area Production Engineering and Well Services management of Saudi Aramco for their . Acknowledgment is also extended to Shaybah Field Producing for their continuous in this field development.

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5. Putra, S.A.: “Transportation of High Pour Point Oil through Long Hilly Terrain Pipe Line, a Case Study in Kalimantan Indonesia,” SPE paper 86929, presented at the SPE International Thermal Operations and Heavy Oil Symposium and Western Regional Meeting, Bakersfield, California, March 16-18, 2004. 6. Christiansen, P.E., McKay, S.A., Mullen, K. and Upston, L.R.: “Remote Field Control and Strategy – Umbilicals vs. Control Buoys,” SPE paper 88546, presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, October 18-20, 2004. 7. Ragab, A., Brandstaetter, W., Ruthammer, G. and Shalaby, S.: “Analysis of Multiphase Production through Hilly Terrain Pipelines in Matzen Field – Austria by CFD,” SPE paper 115355, presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, September 21-24, 2008. 8. Hamoud, A.A., Boudi, A.A., Al-Qahtani, S.D. and AlDayil, N.: “Development of a Rotodynamic Multiphase Pump in a Remote Hilly-Terrain Oil Field in Saudi Arabia,” SPE paper 117462, presented at the Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, U.A.E., November 3-6, 2008.

BIOGRAPHIES Shadi M. Hanbzazah ed Saudi Aramco as a CDPNE student in 1996 and is now a Production Engineering Supervisor for the Abu Hadriyah, Fadhili and Khursaniyah (AFK) unit. His experience includes working in Shaybah field, along with his experience in reservoir management and simulation. Shadi received his B.S. in Petroleum Engineering from the University of Louisiana at Lafayette, Lafayette, LA, in 2001. Mohammed N. Merwat has 37 years of intensive experience in petroleum engineering, including 33 years with Saudi Aramco and 4 years with SONATRACH in well completion, development of new fields, production operation, new technology evaluation/implementation and intelligent field equipment. For 10 years of that time, he worked with the Shaybah Field Development project. Mohammed was a member of Shaybah Asset Management team and was actively involved in the design, layout and construction of the surface facilities, evolution of horizontal drilling technology and complex well completions, wellbore stability study/testing and monitoring of the Shu’aiba soft formation. He received his B.S. degree in Petroleum Engineering from the University of Engineering & Technology (UET), Lahore, Pakistan in 1972. Mohammed has received professional recognition for his petroleum engineering activities. Dr. Mohammed N. Al-Khamis is a Production Engineering Supervisor with the Ras Tanura Production Engineering Division. He has 9 years of academic experience and more than 17 years of work experience in various departments within Saudi Aramco, and has published and presented numerous technical papers and research reports. In 1988, Mohammed received his B.S. degree and in 1995 he received his M.S. degree, both in Petroleum Engineering, from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia. In 2003, he received his Ph.D. degree in Petroleum Engineering from the Colorado School of Mines, Golden, CO.

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Use of XRD and XRF Techniques to Determine the Chemical Composition and Crystallite Size of Metal Matrix Composite Materials Authors: Dr. Shouwen Shen, Dr. Husin Sitepu, Saud A. Al-Hamoud, Dr. Ihsan M. Al-Taie, Dr. Gasan Alabedi, Dr. Abdullah A. Al-Sharani and Bander F. Al-Daajani

ABSTRACT Metal matrix composite (MMC) is a material consisting of a metallic matrix (e.g., aluminum, magnesium, iron, cobalt and copper) combined with a ceramic (e.g., oxides and carbides) or metallic (e.g., lead, tungsten and molybdenum) dispersed phase. MMC is widely used in material science today. A number of MMCs are being investigated for high temperature applications, such as a high temperature metallic coating for the gas flare system at Saudi Aramco. To choose the raw material for a high temperature coating, we investigated 11 MMC powders and determined their chemical composition and crystallite size using X-ray diffraction (XRD) and X-ray fluorescence (XRF) techniques. This critical information will help scientists and engineers in coating design and research.

EXPERIMENTAL Elemental Analysis by Wavelength Dispersive X-ray Fluorescence (WDXRF)

X-ray fluorescence (XRF) spectrometry is an analytical technique to determine the elemental composition of various materials1. XRF has the advantage of being nondestructive, multi-elemental, fast and cost-effective2. The XRF technique can be categorized into two classes: energy dispersive X-ray fluorescence (EDXRF) spectrometry and wavelength dispersive X-ray fluorescence (WDXRF) spectrometry. The elements that can be analyzed and their detection levels mainly depend on the spectrometer system used. The elemental range for EDXRF goes from sodium (Na) to uranium (U). For WDXRF the range is even wider, from beryllium (Be) to uranium (U)3. The concentration range goes from parts per million (ppm) levels to 100%. In this study, all samples were measured as received (a loose powder) in a helium atmosphere. WDXRF data was obtained using the IQ+ method for elemental composition determination semi-quantitatively with a PANalytical PW2400 spectrometer. Phase Identification by XRD

X-ray diffraction (XRD) is a nondestructive technique for analyzing a wide range of materials, including metals, minerals, polymers, catalysts, plastics, pharmaceuticals, thin-film coatings, ceramics, solar cells and semiconductors4-6. Therefore, 50

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XRD has become an indispensable method for the investigation, characterization and quality control of materials. In this study, XRD analysis was performed on 11 composite raw materials. Each of the composite powder samples was manually ground by an agate mortar and pestle for approximately 20 minutes to achieve a fine particle size. The fine powder was mounted into the XRD sample holder by back pressing. The XRD patterns of the sample powders were measured using a PANalytical X’Pert PRO PW3050/60 diffractometer (CoKa radiation generated at 40 kV and 40 mA) equipped with an automatic divergence slit. The irradiated length was 15 mm, with a receiving slit size of 0.3 mm, single Xenon detector and sample changer (sample diameter 16 mm). The samples were measured from 10° to 150° 2θ with a step size of 0.02°, the scan step time was 1 second. To identify the phases present in the sample, the XRD pattern of the sample was compared with every calculated pattern in a database from the International Center for Diffraction Data (ICDD). Its Powder Diffraction File (PDF) database contains 291,440 inorganic and organic substance entries. Using the search-match capabilities of XRD software JADE 8.0+ and the ICDD-PDF database, all phases present in the samples were identified.

Fig. 1. XRD pattern of sample #156.

Peak # 1 2 3 4 5

2-Theta 20.170 33.427 39.407 43.025 57.083

d-value (Å) 4.3990 2.6785 2.2847 2.1006 1.6122

FWHM 0.491 0.485 0.538 0.537 0.519

Crystallite Size (nm) 35DŽ2 36DŽ2 28DŽ6 29DŽ3 33DŽ2

Table 1. Analysis of reference sample (Y2O3) with average crystallite size of 30 nm using JADE 8.0+

Sample Number #152 #153 #154 #155 #156 #157 #158 #159 #160 #161 #162

Co 51 43 1.2 11 29 -

Weight Percentages (Wt%) Ni Cr Mo W 1 7 23 0.3 14 23 2.3 0.1 56 16 0.4 0.1 3 50 0.1 4.3 11 5 2 73 30 16 39 12 47 0.1 49 -

Fe 1 1 0.2 2 81 0.1 0.3 0.3 0.4 0.1 -

Al 0.3 4 18 49 0.2 5 57 52 50

Zr 89 0.1 0.1 0.1

Y 8 1 0.3 -

Hf 2 -

Cu 0.1 1 -

Mn 0.4 -

Ti 0.4 -

Table 2. Elemental analysis by WDXRF* * Note: The wt% of elements above 0.1% are the only ones listed here, for others less than 0.1% are not in the list. Our WDXRF cannot analyze light elements with atom less than nine. For example, if carbon (C) is present in the samples, it is not detected.

Figure 1 is the XRD pattern of sample #156 with all identified compound references. It shows that the matrix phase is iron (Fe), whereas the dispersed phases are cohenite (Fe3C), aluminum (Al) and molybdenum (Mo). XRD phase identification of the MMCs in some cases is insuficient, and further XRF elemental information is badly needed to make the right choice from different candidates of possible phases. For example, the XRD patterns of nickel tungsten (Ni17W3) and cobalt tungsten (Co0.87W0.13) are exactly the same. Therefore, XRD can’t differentiate them without XRF elemental information. Crystallite Size Determination by XRD

Since traditional methods, such as laser granulometry, determine only particle size – a parameter that is not directly correlated with crystallite size – XRD techniques play an important role in crystallite size analysis. Usually, crystallite size is not the same as particle size, as one particle can contain several crystals. The XRD diffraction lines (peaks) broaden for two principal reasons. They are ing instrumental effects and crystallite size. The strain effects can also contribute to the broadening of XRD diffraction lines, but mainly within the crystal lattice. The instrumental effects can be determined by measuring the XRD data of a standard sample, such as silicon (Si) powder. Originally, Paul Scherrer developed the method to calculate the crystallite size from XRD line broadening, noting that as the crystallite size gets smaller, the peak gets broader. Scherrer’s equation is given by Dv = Kλ /(β cosθ). Where Dv is the crystallite size weighted by volume, K is the Scherrer constant (which is somewhat arbitrary, varying from 0.62 to 2.08, and depends on crystal shape, usually taking the value of 0.9 by assuming the crystals are spherical with cubic symmetry), λ is the wavelength of X-ray radiation (Å) (unless it is a cobalt X-ray source, then it takes 1.7909Å) and β is the integral breadth of peak (in radians 2θ) located at

Sample # #152

#153

#154

#155

#156

#157

#158

#159 #160 #161 and 162

Phase Identified Cobalt (Co) Cobalt Molybdenum (Co3Mo) Chromium Cobalt Molybdenum (CrCoMo) Cobalt (Co) Cobalt Tungsten (Co0.8W0.2) Chromium Molybdenum (Cr0.5Mo0.5) Chromium Cobalt Molybdenum (CrCoMo) Zirconium Yttrium Oxide (ZrO2)0.95(Y2O3)0.05 Baddeleyite (ZrO2) Hafnium Oxide (HfO2) Nickel Aluminum (NiAl) Chromium Nickel (CrNi) Iron Nickel (FeNi2) Iron (Fe) Iron Carbide (Fe3C) Aluminum (Al) Molybdenum (Mo) Nickel (Ni) Aluminum (Al) Molybdenum (Mo) Tungsten Carbide (WC) Nickel Tungsten (Ni17W3) Chromium Nickel (CrNi) Cobalt Tungsten (Co0.87W0.13) Chromium Nickel (Cr2Ni3) Aluminum Cobalt (Al0.47Co0.53) Chromium Nickel (CrNi) Aluminum (Al) Nickel (Ni) Aluminum (Al)

Table 3. Phase identification results from XRD data

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Crystallite Size (nm) Sample # #152

#153

#154

#155

#156

#157

#158

#159 #160 #161 #162

Phase Co Co3Mo CrCoMo Co Co0.8W0.2 Cr0.5Mo0.5 CrCoMo (ZrO2)0.95 (Y2O3)0.05 ZrO2 HfO2 NiAl CrNi FeNi2 Fe Fe3C Al Mo Ni Al Mo WC Ni17W3 CrNi Co0.87W0.13 Cr2Ni3 Al0.47Co0.53 CrNi Al Ni Al Ni Al

JADE 8.0+ Pseudo-Voigt Pearson VII 27 27 26 9 22 20 35 35 23 23 23 24 21 ? 141 194 81 141 6 60 60 12 26 88 178 81 151 224 129 42 42 42 61 22 108 131 67 93 65 70

84 191 ? 71 71 10 22 86 174 80 167 223 141 42 42 42 63 26 112 150 74 101 75 77

FW HM 26 29 22 37 33 28 24 194 137 194 22 49 49 13 21 83 112 69 111 112 99 43 43 43 57 38 73 91 60 77 61 77

High Score Integral Breadth 13 16 12 21 36 36 14 194 96 194 20 24 24 9 29 125 252 79 250 252 141 49 49 49 60 43 103 167 60 125 64 111

Table 4. Crystallite size determination from XRD data

angle θ (usually full width at half maximum (FWHM)) is used for the determination of the integral breadth of peak). In our study, the Scherrer equation, using FWHM, was utilized for crystallite size calculation. Subsequently, there are different methods for FWHM determination, such as those by the XRD software HighScore Plus and JADE 8.0+. The XRD software JADE 8.0+ method is to perform a XRD pattern profile fitting to calculate FWHM with different mathematic models of Pseudo-Voigt and Pearson VII. We found the results from JADE 8.0+ with the Pseudo-Voigt model to be more accurate and stable. Table 1 is the result of analyzing a reference material of Y2O3 with an average crystal size of 30 nm using JADE 8.0+ with the Pseudo-Voigt model, which matches well with the real value.

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RESULTS AND DISCUSSION The semi-quantitative elemental composition results from the WDXRF analysis are shown in Table 2, which indicates that samples #152 and #153 are dominated by cobalt (Co); #154 is dominated by zirconium (Zr); #155 is dominated by nickel (Ni); #156 is dominated by iron (Fe); #158 is dominated by tungsten (W); #159 is dominated by cobalt (Co) and nickel (Ni); and #157, #160, #161 and #162 are dominated by aluminum (Al) and nickel (Ni). Table 3 is the result of phase identification from the XRD data, which matches the WDXRF results very well. It also shows that some minor elements present in the WDXRF results do not appear in the phase compositions of the XRD data. The reason is probably that the minor elements replaced

the major elements in the form of solid solution. For example, molybdenum (Mo) likely replaced some tungsten (W) in the phase of tungsten carbide (WC) of sample #158. Table 4 is the result of the crystallite size calculation for each phase present in the 11 samples. It shows that the results obtained in four different ways are similar except in a few cases. The results indicate that the 11 composite powders are almost a nanocrystallite size7, ranging mostly from 20 nm - 200 nm, in which the crystallite size of iron is 9 nm - 13 nm; cobalt is 26 nm - 37 nm; nickel is 60 nm - 94 nm; aluminum is 77 nm 121 nm; and molybdenum is 112 nm - 336 nm.

CONCLUSIONS 1. Eleven composite powders were analyzed using a PANalytical X’Pert diffractometer and a WDXRF spectrometer. 2. The WDXRF element analysis provides invaluable information for the phase identification of the XRD data of the composite materials. 3. The XRD patterns of all the data sets are sharp, which indicates that the 11 samples of composite powder are crystalline material. 4. Some minor elements present in the WDXRF results do not occur in the phase compositions of XRD data. The reason is probably that the minor elements replaced the major elements in the form of solid solution. 5. Crystallites of the 11 samples of composite powder are in nano-size, ranging mostly from 20 nm to 200 nm.

ACKNOWLEDGMENTS

REFERENCES 1. Jenkins, R., Gould, R.W. and Gedcke, D.: Quantitative Xray Spectrometry, 2nd Edition, Marcel Dekker Inc., New York, 1995. 2. Sitepu, H., Kapylova, M.G., Quirt, D.H., Cutler, J.N. and Kotzer, T.G.: “Synchrotron Micro-X-ray Fluorescence Analysis of Natural Diamonds: First Steps in Identification of Mineral Inclusions In-situ,”American Mineralogist, Vol. 90, 2005, pp. 1,740-1,747. 3. Shen, S., Sherik, A.M., Sitepu, H., Zaidi, S.R. and Hamoud, S.A.: “Chemical Composition Determination of Black Powder Samples by XRD and XRF,” paper 10096, presented at the 13th MECCE, Manama, Bahrain, February 14-17, 2010. 4. Chung, F.H.: “Quantitative Interpretation of X-ray Diffraction Patterns of Mixtures I. Matrix-flushing Method for Quantitative Multicomponent Analysis,” Journal of Applied Crystallography, Vol. 7, 1974a, pp. 519-525. 5. Chung, F.H.: “Quantitative Interpretation of X-ray Diffraction Patterns of Mixtures II. Adiabatic Principle of X-ray Diffraction Analysis of Mixtures,” Journal of Applied Crystallography, Vol. 7, 1974b, pp. 526-531. 6. Chung, F.H.: “Quantitative Interpretation of X-ray Diffraction Patterns of Mixtures III. Simultaneous Determination of a Set of Reference Intensities,” Journal of Applied Crystallography, Vol. 8, 1975, pp. 17-19. 7. Savino, V., Fallatah, G.M. and Mehdi, M.S.: “Applications of Nanocomposite Materials in the Oil and Gas Industry,” Saudi Aramco Journal of Technology, Winter 2008, pp. 30-36.

The authors would like to thank the management of Saudi Aramco for permission to publish this article. The authors would also like to thank Mr. Yazeed Al-Dukhayyil and Mr. Abdulelah Al-Naser for their various .

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BIOGRAPHIES Dr. Shouwen Shen is a Senior Lab Scientist and X-ray Group Leader at the Elemental Analysis Unit of the Research & Development Center (R&DC). He has more than 25 years of experience in the petroleum industry and universities. Before ing Saudi Aramco in 2006, he worked at Southwest Petroleum University in China as an Associate Professor, at the University of Miami as a Visiting Scientist and at Core Laboratories Canada Ltd. as an X-ray Specialist. He studied the seismic facies, sedimentary facies and sequence stratigraphy of Jurassic formations in the TurpanHami basin of China. Shouwen used piezoelectric transducers to measure the sonic velocity of various dolomites from the Madison Formation of Wyoming and Montana and developed an empirical formula to predict the sonic velocity of dolomite according to thin section description. He also developed new XRD methods in-house for quantitative mineral analysis of sandstone and successfully solved the problem caused by the Rietveld method limitation. Shouwen’s specialties include sequence stratigraphy, clastics diagenesis, clay mineralogy and formation damage assessment, thin section description, XRF elemental analysis, XRD phase identification and quantification, crystallite size determination, and texture and residual stress analyses. Shouwen received a B.S. degree from the China University of Geosciences, Beijing, China, in 1982 and a Ph.D. degree in Petroleum Geology from Chengdu University of Technology, Sichuan, China, in 1998. Dr. Husin Sitepu ed Saudi Aramco’s Research and Development Center (R&DC), Analytical Services Division, in 2008. Currently, he is contributing to several research projects under both the Downstream and the Strategic Upstream R&DC programs, in providing crystallographic information on developed materials including nano-materials and catalysts. Before ing Saudi Aramco, Husin worked at NIST Center for Neutron Research in Gaithersburg, MD; Ruhr University Bochum, in Bochum, ; the Institute Laue-Langevin Neutrons for Science, in Grenoble, ; the University of British Columbia in Vancouver, Canada; and the Curtin University of Technology in Perth, Australia. He has authored and coauthored 32 papers in several peer-reviewed journals, including the International Union of Crystallography’s Journal of Applied Crystallography. Husin has extensive experience in Rietveld refinement of polycrystalline structures using X-ray, synchrotron and neutron powder diffraction data.

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He received his Postgraduate Diploma, M.S. and Ph.D. degrees in Physics from the Curtin University of Technology, Perth, Western Australia, in 1989, 1991 and 1998, respectively. Husin is a member of the International Center for Diffraction Data and the Society of Crystallographers in Australia and New Zealand. Saud A. Al-Hamoud ed Saudi Aramco in 1988 as a Senior Lab Scientist at the Elemental Analysis Unit of the Research & Development Center (R&DC). Prior to this, he was a Lecturer at King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia. Saud’s specialty is in X-ray analysis, including X-ray fluorescence (XRF) and X-ray diffraction (XRD). He has worked on many projects related to the oil and gas industry, such as catalyst studies to determine their effectiveness through measuring the concentration of chloride in the hydrocracker catalyst, and detailed analytical studies on scale, corrosion products and deposits that are found in the oil and gas plants. Saud also studied cement elemental analysis and developed calibration curves for different projects. Recently, he acquired the training and did research work in residual stress, texture analysis and crystallite size determination using XRD methods. Saud also did an analysis of nanomaterials using XRF and XRD. He received his B.S. degree in General Chemistry from King Abdulaziz University, Jiddah, Saudi Arabia, and his M.S. degree in Inorganic Chemistry from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia. Dr. Ihsan M. Al-Taie ed Saudi Aramco’s Research and Development Center (R&DC) in 2001. Currently, he is the Project Leader of the Pipeline Integrity Program under the Upstream R&D program. Prior to this, Ihsan worked as a Research Scientist at the Canadian Ministry of Natural Resources. He received his Ph.D. degree in High Temperature Materials and Corrosion from Manchester University, Manchester, U.K., in 1992.

Dr. Gasan Alabedi has worked as a Research Fellow and Lecturer at the Manchester School of Materials for many years in the field of Advanced Ceramics, Thermal Spray Coatings and Nano-Materials. His main research interests were focused on the utilization of advanced materials for the oil and gas industry. In 1982, Gasan received his B.Eng. degree in MiningGeological Engineering from the University of Tuzla, Tuzla, Bosnia and Herzegovina, and in 1991, he received his M.Eng. degree from Belgrade University, Belgrade, Serbia. He then received his M.S. degree in 1994 and Ph.D. degree in 1999 in Materials Science, both from the University of Manchester Institute of Science and Technology (UMIST), Manchester, U.K. Dr. Abdullah A. Al-Sharani ed Saudi Aramco in September 2000. He started his career as a Corrosion Scientist in the Research and Development Center (R&DC) after graduating from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran Saudi Arabia. Abdullah is currently a member of the Advanced Materials Group in the Research and Development Division where he is working on several projects. In 2003, he received his M.S. degree in Corrosion Engineering from the University of Manchester Institute of Science and Technology (UMIST), Manchester, U.K., and in 2009, Abdullah received his Ph.D. in Materials Science and Engineering from the University of Manchester, Manchester, U.K. Bander F. Al-Daajani ed Saudi Aramco in October 2001, working as a Lab Scientist in the Corrosion Science Unit of the Research & Development Center (R&DC). He started his field deployment assignment in April 2003 with the Tanajib gas plant as an Operations Engineer. In 2004, Bander moved to the Riyadh Refinery as an Operations Engineer for a 2 year period. After completion of his field assignment, he reed the Advanced Materials Group as a Lab Scientist. In 2000, Bander received his B.S. degree in Chemical Engineering from King Saud University, Riyadh, Saudi Arabia. He is currently a professional member of ASM International.

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Effective Strategies in Development of Heterogeneous Gas Condensate Carbonate Reservoirs Authors: Dr. Hamoud A. Al-Anazi, Ahmad M. Al-Baqawi, Ahmad Azly Abdul Aziz and Adnan A. Al-Kanaan

ABSTRACT A gas bearing carbonate reservoir has been under development in Saudi Arabia to exploit the nonassociated gas to meet the robust increase in gas demand. Initial penetrations showed reservoir heterogeneity with several gas-water s (GWCs), variation in reservoir pressure, the presence of faults/channels, and an H2S content and condensate yield. All these factors made it hard to meet the targeted developmental plans with conventional reservoir exploitation techniques. Therefore, several delineation wells were initially drilled to assess reservoir boundaries. When the drilling resulted in an upside potential for an increase in reserves, future wells were located based on calibrated 3D seismic impedance and simulation runs. Several strategies have been used to drill these wells so as to target the best reservoir development, such as dual lateral, geosteering, horizontal and extended reach wells. Other technologies, like multistage horizontal fracturing and underbalanced coiled tubing drilling (UBCTD), were also very effective in enhancing the wells’ productivity from poorly developed and tight reservoirs. One main obstacle was that wells had to be drilled in populated areas, which required finding a reasonable surface location that provided the most cost-effective drilling operations. This article will address all the challenges that were faced during the initial field development and the technologies and methodologies that were used to achieve full field development and meet the target gas production. Several field cases will be discussed in detail, covering geological interpretation, drilling/completion operations, stimulation, production performance and reservoir management. These strategies were found so effective in developing this gas field that they are currently being implemented in other fields that will be put on production during the business plan cycle. These strategies helped to confirm field boundaries, identify multiple GWCs, avoid areas dominated by water encroachment, optimize reservoir depletion and extend the production plateau.

over the years has been to develop gas carbonate reservoirs due to their prolific production and shallower basins compared to sandstone gas reservoirs. The development started in the mid 1980s with various exploratory efforts to assess the nature of the reservoir rock and fluid properties, along with understanding the reservoir drive type. As we entered the new millennium, the high demand from the petrochemical industry empowered Saudi Arabia to develop the gas fields so as to load their prospective gas plants to their maximum manifolding capacity. Throughout

INTRODUCTION In the Middle East, gas condensate reservoirs have great importance due to the high value of condensate reserves and their excellent natural gas depletion potential. The main focus 56

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Fig. 1. Reservoir cores recovered from the pay zone at various depths.

Fig. 2. Thin section and SEM photomicrographs of the dolomitic and anhydritic limestone core.

Fig. 3. Thin section and SEM photomicrographs of the dolostones core.

the development of the gas carbonate reservoirs, reservoir engineers uncovered many challenges. Most of the challenges were related to the extreme heterogeneity of the reservoir. As a result, more care and time was required to devise the best stepout development strategy and well completion configuration for better achieving an effective development strategy and meeting the desired economic recovery target. The first part of this article will discuss the challenges to developing complex, naturally fractured gas condensate reservoirs with a high degree of heterogeneity from the field down to the well level. The second part of the article will use various examples to address how over the years modern technologies through various examples have been essential in

maximizing well production in the shadow of depleting pressures in the center of the field as well as sparse reservoir development on the flanks. The examples will share various details on both well and reservoir aspects to highlight the significant improvements.

PETROGRAPHY A petrographic evaluation of several core samples, Fig. 1, from various wells indicated they consist of limestones and dolostones: calcite, dolomite and anhydrite are common cements/replacement minerals in many samples. Scanning Electron Microscope (SEM) and X-ray Diffraction (XRD)

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analysis conducted on these samples confirmed the observed mineralogy. The allochems in the lime grainstones are moderately sorted, and average grain size ranges from 330 to 383 microns (medium sand size). Some of the micritic grains have been replaced by dolomite, Fig. 2. Grains appear to have undergone a minor to moderate amount of compaction, as evidenced by the numerous point and long grain s and by the fewer concavo-convex grain s and stylolites. On the other hand, the dolostones are poorly sorted, and average grain size ranges from 438 to 882 microns (upper medium to coarse sand size). The original fabric of the remaining dolostones has been partially to almost completely obscured by the dolomitization process, Fig. 3. The average crystal size in the dolostones ranges from 14 to 25 microns (finely crystalline). Grains appear to have undergone a minor to moderate amount of compaction. Cementation by calcite and anhydrite was the main cause of this reduction of the primary pore volume, and a

Fig. 4. Core permeability and porosity cross plot integrated by lithology.

Fig. 5. Cross section of lateral extent of Reservoir A development profile.

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later dissolution of the grain and dolomitization generated secondary pores that make up much of the total porosity. Porosity and permeability data from conventional core analysis was integrated and cross-plotted and integrated by lithology, Fig. 4. The average porosity and permeability in limestone is 12.5% and 0.196 millidarcies (mD), respectively, while in dolostones it is 16.6% and 5.88 mD. The lower values in limestone are due to pore-filling calcite cement that leaves few primary pores. The secondary pores are poorly connected due to the extensive calcite cementation.

RESERVOIR HETEROGENEITY Reservoir A is a naturally fractured gas carbonate reservoir and covers most of the field. It is the largest in size of all the other carbonate and sandstone reservoirs in the field. The reservoir is part of the Khuff formation and belongs to the Triassic period. The reservoir quality varies regionally according to the ratio of anhydrite to carbonate components and by matrix porosity and permeability. The fracture density increases out from the central area, where the fractures are thin, dispersed and mostly short in length (< 1 ft)1. Therefore, the reservoir performance varies widely among offset wells in the same field2. Analysis of the reservoir data indicates the presence of significant areal and vertical pressure compartmentalization. The seismic maps (impedance values) show the variability in the reservoir, which is usually thin, with up to 20 ft true vertical depth (TVD). Therefore, the impedance values are not precise and many times cannot be correlated with log porosity and reservoir performance. In many places, multiple contaminations of the data make it impossible to arrive at a correct interpretation. Change in dip and structures also poses a major problem for correct interpretation. Another challenge is the presence of multiple gas-water s (GWCs) as

Rock Type Fluid Type Condensate-Gas Ratio Average Porosity Average Permeability Initial Reservoir Pressure Irreducible Water Saturation

Carbonate (Khuff-B) Gas Condensate 40 bbls/MMscfd 7.5% 1 mD 7,600 psi 30%

Table 1. Reservoir A main properties

Fig. 6. Western flank indications of compartmentalization.

observed in the formation analysis logs and well tests. Consequently, well placement was not an easy task in avoiding the wet zone and enhancing water encroachments3-4. Reservoir heterogeneity necessitates the need for effective drilling and completion fluids that reduce induced formation damage if the well is to achieve the expected well potential5-6. Pressure compartmentalization has a major impact on production performance because a drop in the bottom-hole flowing pressure below the dew point pressure triggers the onset of condensate banking7. Several techniques have been deployed, such as solvent treatment, to remove the condensate banking around the wellbore region, but production was enhanced only up to several months8. More effective treatment, such as wettability alteration, has been extensively tested and approved in the lab, and is now undergoing field trials on candidate gas wells9-10.

FIELD CASES Well-1 was the first well to produce from Reservoir A in the 1980s. It was initially drilled as an exploration well, where it encountered a lean gas condensate reservoir with a condensate gas ratio of 40 bbls/million standard cubic feet (MMscf). The main properties of Reservoir A are summarized in Table 1. Extensive testing through core and lab experiments showed a permeability of 1 mD, though this permeability changes over the field as previously discussed. During the continuous development of the field, it was difficult to depend on seismic

impedance results with confidence. The poor seismic imaging was due to the extended depth of the reservoir and the high degree of disturbance on the surface3. It was better to use engineering evidence as drilling extended away from the crest of the reservoir. This forced a careful step-out strategy from the crest of the reservoir where Well-1 was drilled toward the west flank of the field. The continuous development of the field, showed that mostly the top layer of all layers in Reservoir A is moderately or fully developed. It was found that the porosity development changes and is not even uniform from the crest of the reservoir to the flanks. Figure 5 displays a depth corrected cross section that clearly indicates the variation in porosity development. For example, Well-2 is located on the west flank inside the field limits; the log showed surprisingly high water saturation, which was confirmed with a production test. Well-2 will be discussed in more detail later in the article and how it was converted into a strong gas producer. Abundant engineering evidence indicates that the reservoir has a complex structure with different compartments that in turn adds complexity to the field development plans as there is no uniform GWC. On the western flank, pressure surveillance tests were collected from three different wells 2 km apart that had been drilled, but not placed on production yet, Fig. 6. Well-4 was drilled between Well-3 and Well-5 and found to be in a compartment with a lower pressure of 4,500 psig compared to the normal pressure on the flanks, which exceeds 7,000 psig. This is a strong indication of localized compartmentalization since no other offset wells had such steep pressure depletion. The porosity logs of these offset wells show a difference in development profile within the top layer of Reservoir A, which is in agreement with the expected reservoir characteristics. Another example of reservoir heterogeneity is a delineation well that was drilled in the southern part of the field and encountered a porosity development that was completely wet, although modular dynamic testing (MDT) pressure points showed virgin reservoir pressure. The latest seismic DETECT technology was not able to confirm the presence of faults to the north or south of this surprising well. A year later, another delineation well was drilled 6 km east of the first well and encountered fair porosity development. MDT pressure points and fluid samples were captured to compare with the first well, Fig. 7. It was found that the samples collected confirmed SAUDI ARAMCO JOURNAL OF TECHNOLOGY

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Fig. 10. 3D well view of pilot hole and laterals.

Fig. 7. Collecting MDT data is essential to identify compartments.

Fig. 8. DETECT technology could not confirm faults in the southern part of Reservoir A.

Fig. 11. Dual lateral detailed trajectory.

Fig. 9. Dual lateral well configuration to prepare for heterogeneity surprises.

planning new wells extremely complex, requiring a plan for contingencies, Figs. 9 and 10. The plan was to drill a highly slanted pilot hole across the entire reservoir to confirm the reservoir development in the flank, where the closest well is 3 km away. Then drill an upper horizontal lateral (L1) crossing the top layer of the reservoir and reaching 4,500 ft to maximize reservoir , however, an operational problem caused a major fish in the hole that caused the loss of both the pilot hole and the upper lateral. A decision was then made to drill a second lateral (L2) to salvage the well and convert it into a gas producer. Lateral L2 was placed near the pilot hole that showed better reservoir development compared to lateral L1, Figs. 11 and 12. It is clear there is a high level of contrast in porosity development between each hole drilled even though the maximum displacement between each lateral did not exceed 200 ft. Well-2 further illustrates the geological complexities of Reservoir A. This well was originally drilled as a dual lateral to assess the production potential in the western part of the field. It was drilled down structure in a westerly direction and encountered good porosity development, but it became wet, based on open hole logs and well testing, Fig. 13. The water in this well was 300 ft higher than the GWC proven in an

gas development and a communication with the central part of the main reservoir, as the pressure was depleted by 750 psig. The well delivered a post-stimulation gas rate of 15 MMscfd at 1,500 psig flowing wellhead pressure (FWHP). As the actual depth difference between the two wells is less than 30 ft, it was not possible to confirm this segregation through seismic, Fig. 8, which was just a geophysical hypothesis before drilling the second well. The high contrast in porosity development is found in a localized scale around the wells. This makes the task of 60

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exploration well drilled nearby, and it defined the reserve limits in the area. The results corroborate the reservoir compartmentalization generated by the north-south trending faults as evidenced in the seismic interpretation. Later, the well was sidetracked 2 km up structure in the east direction as a deviated well and encountered fair porosity development with 15 ft net pay and 5% average porosity. The well was acid fractured and tested 45 MMscfd at 2,851 psig FWHP, compared to a prestimulation rate of 1 MMscfd at 1,000 psig FWHP. The high post-fracture rate is due to crossing the natural fractures that enhance well productivity from this thin net pay zone.

WELL TEST ANALYSIS AND CORE SAMPLES Core samples were collected from the first exploration well, Well-1, which became the first producer from the field. Strategic wells were cored in a continuous step out from the crest to compare the nature of the rock quality, porosity and permeability development. Initially, it was thought that the

fractures only resided close to the crest of the reservoir where a major north-south oriented fault runs through the entire reservoir. By comparing the permeability measurements from the core samples, Fig. 14, it clearly shows a high contrast in rock permeability across the entire reservoir. The reservoir is believed to be composed of different layers with different permeability profiles. Well test analysis interpretation, given in Fig. 15, indicates the presence of dual porosity reservoir behavior in the middle time region of the rate normalized pressure and derivative log-log plot, with the reservoir permeability ranging between 1.5 mD and 1.7 mD10-11. This contradicts with the true nature of the reservoir, which shows a uniform porosity type of rock, since the data is best matched with dual porosity models. All data collected from these wells was beneficial to calibrating the existing 3D seismic impedance and fine-tuning the reservoir simulation models, which helped in better planning the maintenance of the potential gas wells and in adopting the most effective technologies, as will be discussed in the next sections.

Fig. 12. Depth corrected cross section of all laterals drilled. Fig. 14. Rock permeability profile as a function of depth.

Fig. 13. Well-2 trajectory and porosity logs.

Fig. 15. Well test analysis log-log plot shows clear dual porosity behavior.

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DEVELOPMENT STRATEGIES AND TECHNOLOGIES Dual Lateral Wells

As discussed in the first part of the article, the reservoir was known to be very heterogeneous since the first years of development. The large uncertainties in the seismic interpretation made it difficult to anticipate structural dips or potential surprises while drilling, particularly for the flank wells. A thorough study was conducted by a multidisciplinary team to determine the best strategy to encounter the most reservoir and deliver gas producers with high economic value. The team decided to plan the wells as dual lateral wells with a pilot hole at an inclination above 70° that cuts across the entire reservoir to assess the development profile and reservoir structure. Then, a horizontal lateral would be drilled as a contingent to the open hole logs run in the pilot hole to target the most developed layer in the reservoir. Geosteering was kept to a bare minimum since the reservoir has a varying thickness ranging between 10 ft - 60 ft. This strategy has proved highly successful in moving out from the reservoir crest, allowing the geological team to gather more critical sonic and imaging logs from the pilot hole. More importantly, this strategy ensured that each well delivered a minimum initial rate of 15 MMscfd from the 3,000 ft upper horizontal lateral. This strategy is applied only in thin reservoirs due to the extensive cost of a dual lateral well compared to a single horizontal or deviated well. This strategy is limited to new wells that will be drilled in locations where there are no or little control points.

reservoir locations where the surface is congested with manned facilities. Underbalanced Coiled Tubing Drilling (UBCTD)

A commingled well was drilled in the late 1990s as a vertical well penetrating Reservoir A and a lower reservoir formation. The well’s initial production was 10 MMscfd at a FWHP 1,780 psig. After six years of production, a production log showed that 60% of the production was coming from the highly heterogeneous Reservoir A, Fig. 16. In 2008, the production rate dropped to 4 MMscfd with a FWHP of 1,100 psig. The well faced mechanical problems, and based on the reservoir and production data, it was decided to focus only on Reservoir A and shut-off the deeper reservoir. After sealing off the deeper reservoir, a whipstock was placed to initiate sidetracks using an underbalanced coiled tubing drilling (UBCTD) rig, with the goal of drilling at least three slim hole laterals. In previous UBCTD efforts, the target layers in the reservoir of interest had a much more uniform porosity distribution with a common profile. The nonuniform porosity development in this well made it very challenging to plan the most optimal lateral trajectory. Based on the reservoir development profiles in offset wells, Fig. 17, the development is changing in the upper layer of the reservoir as it moves away from the pilot hole. The seismic data encouraged the planning of the laterals in a western

Extended Reach Wells

The practice of drilling wells is based on the rock mechanic’s analysis by drilling parallel to the rock’s maximum horizontal stress profile, targeting reservoir locations east or west of the surface locations. In this carbonate reservoir, wellbores are strongly maintained and stable even many years after production. In addition to the high heterogeneity in the reservoir, the surface of the field is congested with the facilities and infrastructure required to both oil and gas delivery. Therefore, targeting the remaining prime reservoir locations around the crest of the field is becoming a challenge. For this reason, it was necessary to plan the first extended reach well to will have a 2 km horizontal displacement from the surface location. The well was drilled as a highly slanted open hole in the reservoir perpendicular to the maximum horizontal stress profile. This was the only possible drilling trajectory that could meet the safety regulations and standards. The well achieved a total length of 17,400 ft with an open hole completion. It encountered an excellent reservoir of 500 ft with an average porosity of 7%. This well was tested at 50 MMscfd at 3,200 psig FWHP without any stimulation. This successful case will open up an added strategy of using extended reach wells to tap into prolific 62

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Fig. 16. Production log results show Reservoir A is more dominant.

direction. An optimized plan was developed to drill the first sidetrack due west, then to utilize the same window to branch out the second lateral in a southwestern direction. As a contingent to the rate of these laterals, a third lateral would be drilled in the opposite direction. The first lateral crossed the entire top layer, from bottom to top due to mechanical difficulties in the placement of the whipstock. This operation could not take advantage of the gas flowing from the original hole since it was sealed off completely by setting the whipstock. During the sidetrack operation, the gas rate increased strongly as the well crossed the porosity development zones shown in the original hole logs. Since the FWHP was lower than expected, a series of buildup tests was conducted to ensure that the operations were truly underbalanced. It was found that the drilling fluid circulation rate had to be reduced to achieve underbalanced conditions at the window and the drilling bit. A flow back test was conducted before drilling the second lateral and showed a good gas rate at the surface. Then, the second lateral was drilled in more optimized underbalanced conditions and geosteered based on gas rate, Fig. 18. A final pressure rate test

Fig. 17. Cross section of Reservoir A development in offset wells used to plan laterals with UBCTD.

was conducted after pulling out all the equipment from the well and reached a gas rate of 6 MMscfd at 1,650 psig FWHP. The gas rate is expected to increase once the well is tied-in and flowed into the gas plant. Horizontal Multistage Fracturing

Horizontal multistage fracturing completion in gas wells has been used sparsely in this field12-14. The concept is to create multiple transverse fractures that will enhance production and ultimately increase recovery. This innovative completion strategy is promising but still in the infancy stage in this challenging and heterogeneous field. Well-D was the first well to be deployed with a horizontal multistage fracturing completion in this low permeability reservoir. The well was first drilled as a dual lateral to produce from and assess reservoir development in the northern area of the field. It encountered a net reservoir of 1,500 ft with an average porosity of 7%, but the well flowed at 1 MMscfd with FWHP of 650 psi, along with a significant amount of drilling solids. Further attempts to cleanup and stimulate the laterals with coiled tubing (CT) failed due to the downhole obstructions, highlighting the challenges in stimulating long open hole laterals with high wellbore damage. Later, the well was sidetracked as a highly slanted 2,780 ft lateral (87° inclination) across the most developed porosity sections and encountered an average porosity of 7%, Fig. 19. Then the well was equipped with three stages of horizontal fracturing completion to provide more effective stimulation and avoid costly and potentially risky CT operations. The multistage acid stimulation treatment was conducted successfully and established a gas rate of 19 MMscfd at 1,300 psig FWHP. A pressure buildup test is being planned to evaluate the fracture treatment. The results of this first horizontal multistage fracturing completion in Reservoir A are deemed encouraging and a few more wells are planned for completion with the same system. The results from these wells will be used to compare against the existing producers to further assess and quantify the cost benefits of this technology.

Fig. 18. 3D well view of the pilot hole and the laterals drilled with UBCTD.

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Fig. 19. Porosity profile in the sidetrack of Well-D and the horizontal multistage fracturing completion.

CONCLUSIONS The development of heterogeneous gas condensate carbonate reservoirs has been successfully achieved to exploit the nonassociated gas to meet the robust increase in gas demand. The implementation of optimum strategies and the latest technologies was the key to overcoming the reservoir challenges and achieving production sustainability. The active delineation program helped to assess reservoir boundaries and resulted in an upside potential for an increase in reserves. Several strategies have been used to drill producer wells targeting the best reservoir development, such as dual lateral, geosteering, horizontal and extended reach wells. These strategies were found so effective in developing this gas field that they have been currently implemented in other gas fields to be put on production in the business plan cycle. These strategies helped to confirm field boundaries, identify multiple GWCs, avoid areas dominated with water encroachment, optimize reservoir depletion and extend production plateau. Other technologies, like multistage horizontal fracturing and UBCTD, were very effective in enhancing well productivity from poorly developed and tight reservoirs.

ACKNOWLEDGMENTS The authors would like to thank Saudi Aramco management for the permission to present and publish this article. The authors also appreciate the help of all personnel from the Gas Reservoir Management Division for their assistance.

REFERENCES 1. Ameen, M.S., Buhidma, I.M. and Rahim, Z.: “The Function of Fractures and In-Situ Stresses in the Khuff Reservoir Performance, Onshore Fields, Saudi Arabia,” AAPG Bulletin, Vol. 94, No. 1, January 2010, pp. 27-60. 2. Al-Qahtani, M.Y. and Rahim, Z.: “Optimization of Acid Fracturing Program in the Khuff Gas Condensate Reservoir of South Ghawar Field in Saudi Arabia by Managing Uncertainties Using State-of-the-Art Technology,” SPE

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paper 71688, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, September 30 - October 3, 2001. 3. Rahim, Z., Al-Anazi, H.A., Al-Kanaan, A.A. and Abdul Aziz, A.: “Successful Exploitation of Khuff-B Low Permeability Gas Condensate Reservoir through Optimized Development Strategy,” SPE paper 136953, presented at the SPE/DGS Saudi Arabia Section Technical Symposium and Exhibition, al-Khobar, Saudi Arabia, April 4-7, 2010. 4. Al-Shehri, D.A., Rabaa, A.S., Duenas, J.J. and Ramanathan, V.: “Commingled Production Experiences of Multilayered Gas-Condensate Reservoir in Saudi Arabia,” SPE paper 97073, presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 9-12, 2005. 5. Al-Anazi, H.A., Bataweel, M.A. and Al-Ansari, A.A.: “Formation Damage Induced by Formate Drilling Fluids in Gas Bearing Reservoirs: Lab and Field Studies,” SPE/IADC paper 119445, presented at the SPE/IADC Drilling Conference and Exhibition, Amsterdam, the Netherlands, March 17-19, 2009. 6. Al-Anazi, H.A., Okasha, T.M., Haas, M.D., Ginest, N.H. and Al-Faifi, M.G.: “Impact of Completion Fluids on Productivity in Gas/Condensate Reservoirs,” SPE paper 94256, presented at the SPE Production and Operations Symposium, Oklahoma City, Oklahoma, April 17-19, 2005. 7. Al-Anazi, H.A., Solares, J.R. and Al-Faifi, M.G.: “The Impact of Condensate Blockage and Completion Fluids on Gas Productivity in Gas-Condensate Reservoirs,” SPE paper 93210, presented at the Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, Indonesia, April 5-7, 2005. 8. Garzon, F.O., Al-Anazi, H.A., Leal, J.A. and Al-Faifi, M.G.: “Laboratory and Field Trial Results of Condensate Banking Removal in Retrograde Gas Reservoirs: Case History,” SPE paper 102558, presented at the SPE Annual Technical Conference & Exhibition, San Antonio, Texas, September 24-27, 2006.

9. Al-Anazi, H.A., Xiao, J.J., Eidan, A.A., et al.: “Gas Productivity Enhancement by Wettability Alteration of Gas-Condensate Reservoirs,” SPE paper 107493, presented at the 7th SPE European Formation Damage Conference, Scheveningen, the Netherlands, May 30 - June 1, 2007. 10. Rahim, Z. and Petrick, M.: “Sustained Gas Production from Acid Fracture Treatments in the Khuff Carbonates, Saudi Arabia: Will Proppant Fracturing Make Rates Better? Field Example and Analysis,” SPE paper 90902, presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, September 26-29, 2004. 11. Al-Baqawi, A.M. and Al-Malki, B.H.: “Well Test Analysis in Naturally Fractured Gas Condensate Reservoirs below Dew Point Pressure,” SPE paper 122594, presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, Indonesia, August 4-6, 2009. 12. Demarchos, A.S., Porcu, M.M. and Economides, M.J.: “Transverse Multifractured Horizontal Wells: A Recipe for Success,” SPE paper 102262, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, September 24-27, 2006. 13. Al-Jubran, H.H., Wilson, S. and Johnston, B.: “Successful Deployment of Multistage Fracturing Systems in Multilayered Tight Gas Carbonate Formations in Saudi Arabia,” SPE paper 130894, presented at the SPE Deep Gas Conference and Exhibition, Manama, Bahrain, January 24-26, 2010. 14. Solares, J.R., Franco Giraldo, C.A., Al-Marri, H., et al.: “Successful Deployment of Innovative Completion Technology Designed for Multistage Fracturing Treatments in Horizontal Producers Achieved Significant Rate Increase in Saudi Arabia,” SPE paper 114766, presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, September 21-24, 2008.

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BIOGRAPHIES Dr. Hamoud A. Al-Anazi is a Supervisor in the Gas Reservoir Management Division in the Southern Area Reservoir Management Department. His areas of interest include studies on formation damage, fluid flow in porous media and gas condensate reservoirs. Hamoud has published more than 38 papers at local/international conferences and in refereed journals. He is an active member of the Society of Petroleum Engineers (SPE) where he serves on several committees for technical conferences. In 1994, Hamoud received his B.S. degree in Chemical Engineering from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia, and in 1999 and 2003, respectively, he received his M.S. and Ph.D. degrees in Petroleum Engineering, both from the University of Texas at Austin, Austin, TX. Ahmed M. Al-Baqawi started his career at Saudi Aramco in 2001 after receiving his B.S. degree in Computer Engineering from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia. Since that time, he has worked on many important projects throughout the Company providing IT and communication solutions, and earning many certificates of appreciation and recognition. In 2008, Ahmed received his M.S. degree in Petroleum Engineering from the Imperial College, London, U.K., with a main area of research in test analysis and interpretation for gas wells. Upon his return from the U.K., he went to work in the Gas Reservoir Management Division as a Reservoir Engineer managing the ‘Uthmaniyah-Ghawar gas field. Currently, Ahmad is part of the North Gas Field Unit overlooking the development of offshore and northern area gas projects.

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Ahmad Azly Abdul Aziz is currently the Lead Engineer for the ‘Uthmaniyah gas fields in the Gas Reservoir Management Division. He has 20 years of diversified experience in reservoir management for oil and gas reservoirs. Ahmad’s expertise includes general reservoir engineering, well testing, and planning and development of oil and gas reservoirs. Prior to ing Saudi Aramco, he held senior positions in reservoir engineering in Qatar Petroleum and Petronas Carigali Vietnam. In 1989, Ahmad received his B.S. degree in Petroleum and Natural Gas Engineering from Pennsylvania State University, University Park, PA. Adnan A. Al-Kanaan is the General Supervisor for the Gas Reservoir Management Division where he heads a team of more than 30 petroleum engineering professionals to meet the Kingdom’s increasing gas demand for internal consumption. He started his career at the Saudi Shell Petrochemical Company as a Senior Process Engineer. Adnan then ed Saudi Aramco in 1997 and was an integral part of the technical team responsible for the on-time initiation of the two major Hawiyah and Haradh gas plants that currently process 4 BCF of gas per day. He also manages Karan and Wasit, the two giant offshore gas increment projects, with expected total production capacity of 4.3 BCF of gas per day. Adnan has 13 years of diversified experience in reservoir management, field development, reserves assessment, gas production engineering and mentoring young professionals. His areas of interest include reservoir engineering, well test analysis, simulation modeling, reservoir characterization, fracturing analysis and reservoir development planning. Adnan received his B.S. degree in Chemical Engineering from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia. He is a member of the Society of Petroleum Engineers (SPE).

Who Is an Inventor and What Is an Invention? Author: Dr. Rashid Khan, Intellectual Assets Management Group

In our organization, we often face the question, “Who is an inventor?” In other words, what qualifies an individual to be an inventor under patent laws? “Who is a t inventor” is also a difficult concept under the patent law. The patent offices have specific rules for defining inventorship, along with having defined other criteria that an individual must meet to be named as an inventor on a patent application. To claim inventorship is to claim some specific role in the final formation of what is to be patented: • Those who contribute concepts that are embodied in the claims. • A sole inventor must have conceived the ideas in all claims. • Those who contribute ideas, but whose ideas don’t make it into claims are not inventors. In addition, one must be confident to state that without his contribution to the final conception, the invention would have been of lesser value. According to U.S. Patent rules, a person does not qualify as an inventor, for example, if the person served in a supervisory or group leader role, and/or his role was limited by a grant proposal to the work that ultimately led to the invention. A person who has merely followed instructions of another in doing experiments is not a co-inventor of the entity to which those experiments are directed; however, the matter is not that simple. The inclusion or exclusion of even one inventor may make a patent invalid. Under current U.S. patent laws; there is a procedure whereby it is possible to obtain a Certificate of Correction, but only if the mistake was a truthful error that occurred without any “deceptive intention.” Search your principles before you name yourself as an inventor. If you are excluded when you should have contributed to the major claims of a final patent, you are risking not only your rights but also those of the co-inventors or that of the company. What is an invention? You can boast that you have a possible invention if the concept is novel, is unobvious, and can be “reduced to practice” for useful purposes to add value. You also have to demonstrate the best mode and your invention with sufficient data and results. The invention should not be “obvious” to those

“ordinarily skilled in the art.” Furthermore, the inventor and those who are handling or reviewing the invention have a “duty to disclose” all related existing patents or publications to the patent office. In Saudi Aramco, the invention should add value to Saudi Aramco before we process the filing of a patent application. All Saudi Aramco employees are required to assign their invention to Saudi Aramco, as part of the employment contract. How does conception of an invention affect the process? For the conception part of the invention to be completed, the inventor must have formed at least a complete description and identified the needed means or resources for accomplishing the desired results. It is not adequate for an inventor merely to identify that a problem exists or that a particular product would be desirable, or a proposal in of a breakthrough idea. The inventor must find a complete and operative means to put the invention to use, i.e., to reduce it to practice. There is no invention without reduction to practice. “Actual” reduction to practice is the thriving physical use or carrying out of the invention to attain the intended results. “Constructive” reduction to practice is the filing with the patent application that discloses the invention completely enough with sufficient details for a person “skilled in the art” to put it into practice. Conception may occur in many phases. For example: A spark of a breakthrough idea or conception occurred; the original inventor requested his/her lab technician to run several experiments to demonstrate that their ideas are actually valid, but the events or the results often did not advance according to plans. During experimentation, the technician modified the original recipe to make the entire original “spark” viable. The lab technician is now a coinventor. Now, there is a significant change in inventorship status. This is because of the technician’s role to the conception of the invention. If during the “reduction to practice” or experimentation, a technician makes such a drastic modification to the original concept that it results in a completely different invention, the technician will be the sole inventor of the new invention, to the elimination of the original inventor. Finally, it is vitally important that you keep appropriate records regarding your inventions.

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ENHANCED ISOTROPIC 2D AND 3D GRADIENT METHOD Granted Patent: U.S. 7,653,258, Grant Date: Jan. 26, 2010 Mohammad H. Al-Fares, Yi Luo and Yuchun Eugene Wang

Summary

A system and method that uses 2D and 3D numerical gradient operators for reducing anisotropic inaccuracies in digital image processing. In accordance with the invention, enhanced isotropic operators are derived by first parameterizing corresponding numerical operators, followed by determining the parameters for the operators by matching analytical gradients with numerical gradients, which produces generic frequency-independent operators. The system and method also optimize the design of operators for use at any given frequency range as needed for any special purpose application.

AUTOMATED EVENT MONITORING SYSTEM FOR ONLINE RESERVOIR SIMULATION Granted Patent: U.S. 7,660,711, Grant Date: Feb. 9, 2010 Jorge A. Pita, Ali H. Dogru and Nabil M. Al-Zamel

Summary

Briefly, the present invention provides a new and improved computer-implemented method of analysis of simulation results of a subsurface hydrocarbon reservoir. The method includes the steps for generating predicted values of properties of fluids in the volume of the reservoir. Event monitoring rules are then applied to the generated predicted values of the volume of the reservoir to detect whether specified event monitoring conditions are present at locations in the reservoir.

METHOD FOR HYDRAULIC RUPTURING OF DOWNHOLE GLASS DISC Granted Patent: U.S. 7,661,480, Grant Date: Feb. 16, 2010 Ammal F. Al-Anazi

Summary

A method for rupturing a glass disc in a well completion tool located downhole in a section of production tubing. Steps include providing a wellhead isolation tool, or tree saver, to isolate the wellhead Christmas tree, adding a pressurized fluid to the tubing/casing annulus and pumping a disc rupturing fluid into the production tubing via the tree saver until the disc is ruptured. Following rupture, the pump can be rapidly stopped, or slowed, and started to create a water hammer effect that removes any glass shards remaining in the disc holder.

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SYSTEMS, PROGRAM PRODUCTS AND METHODS OF HUMAN RESOURCE PLANNING AND DEVELOPMENT Granted Patent: U.S. 7,672,861, Grant Date: March 2, 2010 Hani A. Al-Otaibi, Maan J. Khalife and Saad Younes Mousa

Summary

Systems, program products and methods of human resources planning and development are provided. An embodiment of the system includes a server in communication with a communication network having an associated human resource database, a plurality of client computers, and a computer medium associated with the server that has program code responsive to preselected manning assumptions to process human resource information from the human resource database for predicting a future number of employees desired within the organization for a preselected period of time, program code responsive to preselected employment development assumptions to process the human resource information for asg a plurality of employment development activities to participating employees in the organization, and program code responsive to information generated by the employment development plan to revise the human resources manning plan and responsive to revisions in the human resources manning plan to revise the employment development plan.

STEERING AND FIXED ANGLE GEOPHONE Granted Patent: U.S. 7,684,284, Grant Date: March 23, 2010 Mohammad Abdul-Ghani Al-Jadani

Summary

In a preferred embodiment, the external part of the adjustable geophone combines features of spike and flat base geophones and consists of a spike assembled to a rounded flat base. The spike attached at the bottom together with the rounded flat base enhances the coupling with the ground and keeps the external part of the geophone in a vertical position. The internal parts can be adjusted manually by hand through an angle gauge steering system, or alternatively the internal parts can be adjusted electronically through an automatic steering device controlled from a recording unit.

WELLBORE SYSTEM AND METHOD FOR PRODUCING FLUID

OIL BASED THERMO-NEUTRAL REFORMING WITH A MULTICOMPONENT CATALYST

Granted Patent: U.S. 7,694,741, Grant Date: April 13, 2010 Ahmed J. Al-Muraikhi

Granted Patent: U.S. 7,700,005, Grant Date: April 20, 2010 Bashir O. Dabbousi, Tomoyuki Inui, Shakeel Ahmed, Fahad I. AlMuhaish and Mohammed Abdul Bari Siddiqui

Summary Summary

Provided is a well system for producing fluid from an Earth formation through the well. A primary wellbore section is used to produce the fluid from the well system to the surface. The primary wellbore section has a number of apertures. At least one flanking wellbore is drilled, such that a portion of the flanking wellbore runs substantially alongside but is not connected to the primary wellbore section. Each flanking wellbore includes at least one laterally extending wellbore section. The flanking wellbore sections communicate with the primary wellbore section through a portion of the porous Earth formation located between the primary wellbore section and the flanking wellbore section.

SYSTEM, METHOD AND PROGRAM PRODUCT FOR TARGETING AND OPTIMAL DRIVING FORCE DISTRIBUTION IN ENERGY RECOVERY SYSTEMS Granted Patent: U.S. 7,698,022, Grant Date: April 13, 2010 Mohmoud Bahy Noureldin and Ahmed Saleh Aseeri

Summary

A system, method and -friendly program product to calculate global energy utility targets and define optimal driving force distribution for a process or cluster of processes under all possible process changes and streams specific minimum temperature approach values, simultaneously and without enumeration, are provided. The program product can utilize stream-specific minimum temperature approach values. The program product can define optimal process conditions and an optimal driving force distribution in heat recovery systems, and can produce an optimal Pareto-curve that shows the rigorous tradeoff between energy cost and capital cost for any energy recovery system.

A method is provided for the thermo-neutral reforming of liquid hydrocarbon fuels, which employs a Ni, Rh and Re catalyst having dual functionalities to achieve both combustion and steam reforming.

SYSTEM AND SOFTWARE OF ENHANCED PHARMACY SERVICES AND RELATED METHODS Granted Patent: U.S. 7,706,915, Grant Date: April 27, 2010 Om Mohapatra, Rao Arimilli and Masood U. Farooki

Summary

A system, software and methods related to enhanced pharmaceutical order entry and istration by medical personnel, and enhanced pharmaceutical inventory control within a medical institution are provided. An embodiment of the system includes a pharmaceutical information management server having a memory and a medication istration program product including a set of instructions stored in the memory of the pharmaceutical information management server to enhance the provision of pharmacy services.

DOWNHOLE VALVE FOR PREVENTING ZONAL CROSS FLOW Granted Patent: U.S. 7,708,074, Grant Date: May 4, 2010 Saeed Mohammed Al-Mubarak

Summary

A flow control valve for use in a downhole completion tubing string, where the control valve prevents cross flow between the producing zones. The control valve comprises a housing forming a plenum therein, a tubular member having a perforated end disposed in the housing and a plug assembly disposed in the perforated end of the tubular member. The plug assembly comprises a shaft reciprocatingly disposed in the tubular member. Produced fluids flow within the tubular member through the perforations to the plenum, and then outside of the control valve through corresponding perforations formed in the disk and housing.

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DETERMINATION OF WELL SHUT-IN TIME FOR CURING RESIN-COATED PROPPANT PARTICLES

OVERFLOW DRAINAGE SYSTEM FOR FLOATING ROOF STORAGE TANK

Granted Patent: U.S. 7,712,525, Grant Date: May 11, 2010 Saeed Mohammed Al-Mubarak

Granted Patent: U.S. 7,721,903, Grant Date: May 25, 2010 Mohammed A. Ben Afeef

Summary

Summary

A laboratory test method employs maximum acoustic wave velocity to determine the cure time of a sample of curable resin-coated proppant (CR) that is packed in a pressurized chamber to simulate conditions in a reservoir rock formation during fracturing, where the CR will be used. The pressurized CR is subjected to a varying temperature profile that replicates the reservoir temperature recovery during shut-in of the fractured zone to develop maximum proppant pack strength and minimize proppant flow back following completion of the fracturing operation and to determine shut-in time to complete curing of the resin.

Provided is a buoyant drain cover assembly for temporary sealing of a drain pipe projecting from the surface of the floating roof assembly. It comprises a drain pipe sealing cover secured to a plurality of depending buoyant spaced apart from each other and configured to conform to the exterior of the projecting drain pipe, which permits vertical movement of the assembly relative to the projecting pipe. The assembly moves from a sealed position, in which the assembly is ed by the top rim of the drain pipe, to an open position, in which the buoyant floating in water accumulated on the roof lift the cover from the rim of the drain.

PROCESS FOR TREATING A SULFUR CONTAINING SPENT CAUSTIC REFINERY STREAM USING A MEMBRANE ELECTROLYZER POWERED BY A FUEL CELL

SYSTEM, METHOD AND PROGRAM PRODUCT FOR TARGETING AND IDENTIFICATION OF OPTIMAL PROCESS VARIABLES IN CONSTRAINED ENERGY RECOVERY SYSTEMS

Granted Patent: U.S. 7,713,399, Grant Date: May 11, 2010 Bashir O. Dabbousi, Gary D. Martinie and Farhan M. Al-Shahrani

Granted Patent: U.S. 7,729,809, Grant Date: June 1, 2010 Mohmoud Bahy Noureldin

Summary

Summary

A continuous method for the treatment of a spent aqueous caustic stream used to scrub a hydrocarbon process stream to remove oxidizable sulfur-containing compounds. Steps include: (a) mixing an oxidizing hypochlorous (HCIO) acid stream produced from an aqueous brine solution with the aqueous caustic stream to form a reactive mixed feed stream; (b) ing the reactive mixed feed stream with at least one catalyst to promote the oxidation of the sulfur containing compounds and the neutralization of the sodium hydroxide; and (c) recovering a neutral treated product stream comprising aqueous sodium sulfate, sodium carbonate and sodium chloride that is odorless, nontoxic and environmentally acceptable for discharge into the sea or into a conventional sewage treatment system.

Systems, methods and program product to calculate global energy utility targets and to model and determine an optimal solution for a non-thermodynamically constrained process or cluster of processes, subject to non-thermodynamic constraints under all possible process changes and stream specific minimum temperature approaches, are provided. An exemplary system can utilize thermodynamic constraints exhibited in streamspecific minimum temperature approach values and establish a high fidelity relationship between energy cost vs. capital cost to design energy recovery systems systematically and without enumeration.

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DESCALING AND CORROSION INHIBITING METHOD

DIESEL OIL DESULFURIZATION BY OXIDATION AND EXTRACTION

Granted Patent: U.S. 7,731,803, Grant Date: June 8, 2010 Abdulghani Jaralla

Granted Patent: U.S. 7.744,749, Grant Date: June 29, 2010 Bashir O. Dabbousi, Gary D. Martinie and Farhan M. AlShahrani

Summary Summary

A highly effective industrial cleaning composition, which is effective in descaling without causing corrosion, has now been found. It comprises a mixture of hydrochloric acid, hydrofluoric acid, one or more chelating agents, a surfactant, a copper complexing agent and a nontoxic inhibitor, which serves to block the anodic and cathodic sites on the steel surfaces of the process equipment.

NON-DAMAGING MANGANESE TETROXIDE WATER-BASED DRILLING FLUIDS Granted Patent: U.S. 7,732,379, Grant Date: June 8, 2010 Abdullah S. Al-Yami

Summary

The present invention provides a manganese tetroxide containing wellbore drilling fluid formulation that generates about 90% or greater return permeability without the need for acidizing washes after the completion of drilling to stimulate the hydrocarbon reservoir. The formulation, which is water-based, possesses all of the necessary physical properties, such as appropriate rheology and fluid loss prevention, to effectively drill reservoir sections while also having the ability to form a filter cake, which is easily removed simply by the natural flow of the hydrocarbons from the formation.

PROCESS TO UPGRADE WHOLE CRUDE OIL BY HOT PRESSURIZED WATER AND RECOVERY FLUID Granted Patent: U.S. 7,740,065, Grant Date: June 22, 2010 Ki-Hyouk Choi

Summary

A process for upgrading whole crude oil by utilizing a recovery fluid, depressurizing an extracted whole crude oil/recovery fluid mixture in a step-wise fashion, and subsequently ing at least a portion of the whole crude oil with supercritical water fluid to produce high value crude oil having low sulfur, low nitrogen and low metallic impurities for use as hydrocarbon feedstock.

The process of the present invention is directed to the desulfurization of a full-range, hydrotreated diesel oil with an aqueous oxidizing agent in the presence of a catalyst and a co-catalyst, and thereafter the selective removal of the oxidized compounds by solvent extraction. Optionally, the foregoing steps are followed by solvent stripping and recovery, and finally by a polishing step.

METHODS OF FACILITATING PIPELINE MANAGEMENT, SYSTEMS, AND SOFTWARE Granted Patent: U.S. 7,761,496, Grant Date: July 20, 2010 Thamer K. Tarabzouni, Abdulaziz K. Al-Mejna and Howard Wood

Summary

Methods for facilitating pipeline management, systems and software are provided. A method can include forming digitized map segments to provide a display of the geographical relationship between terrain featured in the map segments and a pipeline network; forming pipeline equipment records to provide for detailed engineering analysis on associated pipeline equipment, functionally linking each digitized map segment and each pipeline equipment record to at least one geographically associated pipeline operational area, at least one geographically associated pipeline, or both; and spatially displaying a pipeline equipment work location in relation to one of the map segments.

PROCESS FOR REMOVAL OF NITROGEN AND POLYNUCLEAR AROMATICS FROM HYDROCRACKER FEEDSTOCK Granted Patent: U.S. 7,763,163, Grant Date: July 27, 2010 Omer R. Koseoglu

Summary

A feed stream to a hydrocracking unit is treated to remove or reduce the content of polynuclear aromatics and nitrogen containing compounds by ing the feed stream with an adsorbent compound, selected from attapulgus clay, alumina, silica gel and activated carbon in a fixed bed or slurry column and separating the treated feed stream that is lower in the undesired compounds from the adsorbent material. The adsorbent can be mixed with a solvent for the undesired compounds and stripped for re-use.

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MULTIPHASE FLUID SAMPLING METHOD AND APPARATUS

METHODS FOR MAKING HIGHER VALUE PRODUCTS FROM SULFUR CONTAINING CRUDE OIL

Granted Patent: U.S. 7,763,474, Grant Date: July 27, 2010 James Clyde Hassell

Granted Patent: U.S. 7,790,018, Grant Date: Sep. 7, 2010 Rashid Khan

Summary

Summary

The invention provides a method for producing a homogeneous sample of a pressurized fluid stream flowing in a pipeline and consisting of a majority component of hydrocarbon gas, with the remainder consisting of one or more hydrocarbon liquids and water in the form of vapor, aerosols, droplets and/or liquid streams. The method includes the steps of: (a) injecting one or more surface active agents into the fluid stream in an injection zone at a rate that is sufficient to form a uniform foam of the gas and the one or more hydrocarbon liquids and water components; (b) mixing the one or more surface active agents with the fluid stream in a mixing zone to form a uniform foam composition flowing in the pipeline downstream of the mixing zone; (c) withdrawing a portion of the foam composition from the pipeline at a sampling point; (d) ing the portion of the foam composition withdrawn through a sampling loop; and (e) removing a sample of predetermined volume of the foam composition from the sampling loop for analysis.

A process for upgrading, or refining, high sulfur containing heavy hydrocarbon crude oil to a lighter oil having a lower sulfur concentration and, therefore, a higher value product, is disclosed. The process includes reacting the high sulfur heavy hydrocarbon crude oil in the presence of a catalyst and low-pressure hydrogen to produce a reaction product stream from which the light oil is recovered. Part of the reaction product is separated and subjected to further upgrading to produce a lower sulfur oil product for application as distillate fuels. The upgrading process also produces residual oil that is suitable for making olefins, carbon fiber or road asphalt. Catalysts utilized in the processes of the invention can include a transition metal containing compound, the metal being selected from Group V, Group VI and Group VIII of the Periodic Table, and mixtures of these metals.

METHOD OF PRODUCING LOW SULFUR, HIGH OCTANE GASOLINE Granted Patent: U.S. 7,780,847, Grant Date: Aug. 24, 2010 Ki-Hyouk Choi

Summary

A process for producing gasoline having reduced sulfur content while maintaining or improving octane rating is provided. A gasoline fraction having a substantial amount of olefinic and sulfur compounds, produced from fluidized catalytic cracking or coking, is ed first with an adsorbent to selectively remove alkylated thiophenic, benzothiophene and alkylated benzothiophenic sulfur compounds. The adsorbent treated gasoline fraction is then introduced into a conventional hydrodesulfurizing catalyst bed with hydrogen for further removal of sulfur compounds. Adsorbents containing alkylated thiophenic, benzothiophene and alkylated benzothiophenic compounds are regenerated through washing with a hydrocarbon solvent and subsequent drying out by warming.

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PREDICTION OF SHALLOW DRILLING HAZARDS USING SEISMIC REFRACTION DATA Granted Patent: U.S. 7,796,468, Grant Date: Sep. 14, 2010 Stephen C. Kellogg

Summary

Shallow drilling hazards (44), such as karsts, caves, voids and unconsolidated discontinuities, that can pose significant risks to exploration and development well drilling operations are detected employing seismic refraction data on which a series of attribute analyses are performed, the resulting data being further processed to provide a 3D visualization. Refracted wave raypaths (40, 46, 48) are highly distorted by encountering a karst feature with the occurrence of backscattering absorption. The resultant energy recorded at the surface receivers (52) is significantly reduced as compared to refracted waves recorded by other receivers (50) where no karsting is present.

PROCESS FOR UPGRADING WHOLE CRUDE OIL TO REMOVE NITROGEN AND SULFUR COMPOUNDS

GENERALIZED WELL MANAGEMENT IN PARALLEL RESERVOIR SIMULATION

Granted Patent: U.S. 7,799,211, Grant Date: Sep. 21, 2010 Omer R. Koseoglu, Adnan Al-Hajji, Jaffar H. Al-Nufaily and Dhiya Al-Syed Ahmad

Granted Patent: U.S. 7,809,537, Grant Date: Oct. 5, 2010 Kesavalu Hemanthkumar, Henry H. Hoy, William Thomas Dreiman and Usuf Middya

Summary

Summary

A crude oil feed stream is treated to remove or reduce the content of known undesired heteroatomic and polynuclear aromatic compounds containing nitrogen and sulfur by ing the feed stream with one or more solid adsorbent materials, selected from attapulgus clay, alumina, silica gel and activated carbon, in a mixing vessel for a time that is sufficient to optimize the adsorption of the undesired compounds from the crude oil; subjecting the mixture to atmospheric flash distillation and then to vacuum flash distillation to recover the pre-sorbed boiling ranges of products having a lowered content of the undesired compounds; and preferably regenerating at least a portion of the solid adsorbent material for reuse in the process.

A computer implemented process simulates production of oil and gas from hydrocarbon reservoirs. The process is used to help forecast the optimal future oil and gas recovery from large hydrocarbon reservoirs. This process is not only flexible to allow for the further addition of new options, but also robust and reliable, and easy to use. The process is also comprehensive in that it allows a forecast of future performance of a wide range of reservoirs and future operation scenarios. By using the high resolution models provided, a reservoir can be described much more accurately.

PORTABLE CORE FLOOD APPARATUS FOR CONDUCTING ON-SITE PERMEABILITY MEASUREMENTS Granted Patent: U.S. 7,805,982, Grant Date: Oct. 5, 2010 Victor V. Hilab

Summary

A portable apparatus and method provide on-site permeability measurements of a core sample extracted from a subterranean reservoir. The portable apparatus is easily and conveniently transported to well locations for use on-site, thereby allowing the core sample to be tested in actual reservoir conditions. The apparatus can simultaneously test incoming liquids and liquids ing through the core sample, and can measure data in the forward and reverse flow directions. The apparatus requires only a single pump to pressurize and inject the liquid into the core sample.

THERMO-NEUTRAL REFORMING OF PETROLEUM BASED LIQUID HYDROCARBONS Granted Patent: U.S. 7,820,140, Grant Date: Oct. 26, 2010 Tomoyuki Inui, Bashir Osama Dabbousi, Ahmeed Shakeel, Fahad Ibrahim Al-Muhaish and Mohammed Abdul Bari Siddqui

Summary

A method for the thermo-neutral reforming of liquid hydrocarbon fuels that employs a catalyst having dual functionalities to achieve both combustion and steam reforming.

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GUIDELINES FOR SUBMITTING AN ARTICLE TO THE SAUDI ARAMCO JOURNAL OF TECHNOLOGY These guidelines are designed to simplify and help standardize submissions. They need not be followed rigorously. If you have additional questions, please feel free to us at Public Relations. Our address, fax and phone numbers are listed on page 74.

Acknowledgments

Use to thank those who helped make the article possible. Illustrations/tables/photos and explanatory text

Varies, but an average of 2,500-3,500 words, plus illustrations/photos and captions. Maximum length should be 5,000 words. Articles in excess will be shortened.

Submit these separately. Do not place in the text. Positioning in the text may be indicated with placeholders. Initial submission may include copies of originals; however, publication will require the originals. When possible, submit both electronic versions, printouts and/or slides. Color is preferable.

What to send

File formats

Send text in Microsoft Word 6.0/95 or higher (do not submit UNIX files) via e-mail or on disc, plus one hard copy. Send illustrations/photos and captions separately but concurrently, both as e-mail or as hard copy (more information follows under Format).

Illustration files with .EPS extensions work best. Other acceptable extensions are .TIFF, .JPEG and .PICT. Illustrations in PowerPoint are also acceptable.

Length

Procedure

Notification of acceptance is usually within three weeks. The article will be edited for style and clarity and returned to the author for review. All articles are subject to the company’s normal review. No paper can be published without a signature at the manager level or above.

Permission(s) to reprint, if appropriate

Previously published articles are acceptable but can be published only with written permission from the copyright holder. Author(s)/contributor(s)

Please include a brief biographical statement. Submission/Acceptance Procedures

Format

No single article need include all of the following parts. The type of article and subject covered will determine which parts to include. Working title Abstract

Usually 100-150 words to summarize the main points. Introduction

Different from the abstract in that it “sets the stage” for the content of the article, rather than telling the reader what it is about. Main body

May incorporate subtitles, artwork, photos, etc. Conclusion/summary

Papers are submitted on a competitive basis and are evaluated by an editorial review board comprised of various department managers and subject matter experts. Following initial selection, authors whose papers have been accepted for publication will be notified by e-mail. Papers submitted for a particular issue but not accepted for that issue will be carried forward as submissions for subsequent issues, unless the author specifically requests in writing that there be no further consideration. Papers previously published or presented may be submitted. Submit articles to: Editor

The Saudi Aramco Journal of Technology Room 2240 East istration Building Dhahran 31311, Saudi Arabia Tel: +966/3-873-5803 Fax: +966/3-873-6478 E-mail: [email protected]

Assessment of results or restatement of points in introduction. Submission deadlines Endnotes/references/bibliography

Use only when essential. Use author/date citation method in the main body. Numbered footnotes or endnotes will be converted. Include complete publication information. Standard is The Associated Press Stylebook, 39th ed.

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Issue

Abstract submission deadline

Release date

Summer 2011 Fall 2011 Winter 2011 Spring 2012

March 2, 2011 June 1, 2011 August 31, 2011 December 1, 2011

June 30, 2011 September 30, 2011 December 31, 2011 March 31, 2012