Offshore Qatar Research Articles

Case Study: Smart Liner Matrix-Acid Stimulation—A Cost-Effective Performance-Enhancement Technique for Carbonate Reservoirs

Carbonate reservoirs require effective acid stimulation to improve well productivity. For long horizontal wells, a complicating factor has previously been the difficulty of controlling acid placement along the reservoir section. The Smart Liner (SL) concept solves this problem. It consists of a number of small holes spaced in such a way so as to distribute acid evenly along the reservoir interval. Fig. 1 shows a schematic of the concept. Without the need of a coiled tubing, acid is bull-headed at a high rate from surface through the production tubing and enters the liner from the left. The liner does not have to be horizontal but very often is. When acid reaches the first hole, which typically has a diameter of 3–6 mm, the pressure drop across the hole is so large that only a small portion of the acid exits the liner through the hole; the remaining acid continues along the liner until it reaches the next hole where the process is repeated. Appropriate hole spacing ensures that acid is distributed with a given acid coverage (dosage) in barrels of acid per foot of reservoir section. The small cross-sectional area of the holes results in focused acid jetting at velocities often exceeding 20 m/s (65 ft/s). The jetting helps promote wormhole formation leading to substantial productivity enhancement. The hole-spacing design requires dedicated software which must take into consideration constraints pertaining to the reservoir, the well, and the pumping equipment while minimizing operational complexity. The tool should also yield a quick answer to enable the user to optimize the final design post drilling and provide a running tally consisting of the sequence of liner joints to be run in hole. In heterogeneous reservoirs, it is typically required to segment the wellbore with swellable packers to isolate sections with different reservoir pressure and/or fluid mobility, and the SL concept readily accommodates that. Also, since the subsequent stimulation relies on matrix acidization, the tool must ensure that fracturing pressures are not exceeded. The original limited-entry liner (LEL) technique dates to the early 1960s and was proposed for fracturing applications (SPE 530). Reviews by Somanchi et al. (SPE 184834) and Weddle et al. (SPE 189880) suggest that it is still widely applied for such purposes. In the late 1990s, Maersk Oil adapted the concept to effectively stimulate extended-reach wells in its North Sea chalk reservoirs on a large scale. Hansen and Nederveen (SPE 78318) refer to the technology as controlled acid jetting (CAJ). In the following years, the CAJ technique was implemented in more difficult formations such as a 0.1 mD chalk reservoir (SPE 144159) as well as in a tight, gas-bearing formation (SPE 123979). Balsawer et al. (IPTC 17611) designed multizone completions in ultralong wells in a giant field offshore Qatar, which comprised more heterogeneous limestone formations. Other field implementations have been described by Issa et al. (SPE 171779) for a super-giant reservoir offshore Abu Dhabi. Past deployments have concentrated on extended-reach wells with reservoir temperatures up to 210°F. Over the past year, ADNOC has significantly expanded the operational envelope of the Smart Liner concept. Fig. 2 summarizes the variation in completed reservoir length and average permeability for 80 well designs. Table 1 shows that reservoir temperatures vary from 140°F to 300°F.

Largest WAG Pilot in Giant Al-Shaheen Field Reveals Optimization Methods

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190343, “Challenges and Learnings From Operating the Largest Offshore WAG in the Giant Al-Shaheen Field and Ways To Optimize Future WAG Developments,” by M. Pal, S. Furqan Gilani, and G. Tarsauliya, North Oil Company, prepared for the 2018 SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 26–28 March. The paper has not been peer reviewed. This paper discusses the operation of the largest offshore high-pressure water-alternating-gas (WAG) injection pilot using hydrocarbon (HC) gas, with a gas-injection capacity of approximately 100 MMscf/D, in the giant Al-Shaheen field offshore Qatar. The paper also analyzes the current HC-WAG pilot and optimizes future development scenarios for extending HC-WAG injection to the field scale. Al-Shaheen WAG Background As part of the field-development plan, a comprehensive enhanced oil recovery (EOR) screening study was performed that explored the range of available EOR techniques. On the basis of these studies, WAG injection was identified as one of the more-promising EOR options for the field. Additional studies performed in 2006 and 2007 indicated a large full-field potential for WAG in Al-Shaheen, with an estimated recovery of hundreds of millions of barrels over and above water-flood recovery. Data analysis and intensive simulation work, including both a history match and several forecast sensitivities, were conducted to understand and to estimate WAG potential on Al-Shaheen reservoirs. The Al-Shaheen WAG process is largely an immiscible process with some multi contact miscibility effects between injectors and producers. Overall, WAG has been a success in the field in terms of seeing incremental oil gains on several patterns. Although physically successful, the project had been challenging operationally. In spite of incremental gains, a number of operational challenges were encountered during the execution of the WAG pilot. These challenges mostly were related to WAG-cycle conversions and operational efficiency of gas-compression systems. WAG Recovery Optimization WAG will be a major part of the development of the mature-flank and heavy-oil areas of the field. The areas proposed for WAG are undersaturated with gas at reservoir conditions. Incremental recovery from WAG could be affected by thermodynamic effects caused by large variations in permeability, viscosity, and saturation pressure in the field along with several other variables described in the complete paper. To analyze the effect of these optimization parameters on incremental oil recovery from WAG, a sector model with varying static and dynamic properties was built (Fig. 1). The properties of the sector model were based on the history-matched model of the neighboring areas. The well spacing was 700 ft, which lies in the middle of the well-spacing ranges of the ongoing WAG pilot wells (500 to 1,000 ft). The WAG sector model was initialized with a range of fixed oil API gravities. Different thermodynamic effects of gas injection have been examined on the sector model. The model is also simulated for different WAG cycle lengths (1/1, 3/3, 6/6, and 12/12), ratios (1:2, 2:1, and 1:3), and slug sizes (1–30 years of WAG). The effects of choking production wells and changes in injection gas composition were also tested on the sector model.

Influence of a major exposure surface on the development of microporous micritic limestones - Example of the Upper Mishrif Formation (Cenomanian) of the Middle East

Microporous platform top limestones of the Cenomanian Mishrif Formation (offshore Qatar) were studied in order to investigate the diagenetic processes associated with the top-Mishrif subaerial unconformity and its influence on the development of microporosity in underlying carbonates. Petrographical and stable isotope results indicate that complex diagenetic changes occurred during subaerial exposure of the Mishrif Formation, including pervasive dissolution and meteoric cementation, as well as neomorphism of the micritic matrix. Micrites at the top of the Mishrif Formation are coarse (i.e. >2μm), sub-rounded and very dull luminescent under cathodoluminescence. In this uppermost part of the studied interval, the limestone matrix first underwent dissolution of unstable grains in the vadose zone, with subsequent precipitation of low-magnesium calcite (LMC) overgrowths within an oxidising phreatic setting. This process explains the poor luminescence of the micrite crystals and their relatively coarse crystallometry which results in the present day in relatively good reservoir properties. δ13C ratios within the microporous limestones are negative (up to −4‰ V-PDB) due to the incorporation of isotopically light carbon derived from palaeosols which developed during exposure. By contrast, fine (i.e. <2μm), polyhedral and bright luminescent micritic matrix with higher δ13C values (up to +4‰ V-PDB) and lower permeability are dominant within the underlying carbonate interval. These fine micrites are likely to be the product of early neomorphic recrystallisation in the lowermost part of the palaeo-aquifer associated with the Top-Mishrif Unconformity, and were precipitated from meteoric or mixed dysoxic waters which were slightly supersaturated with respect to calcite.

Method of Surface Interception To Access Annulus With Abnormal Gas Pressure

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18122, “A Safe and Efficient Method of Surface Interception To Access Outermost Sealed Annulus Charged With Abnormal Gas Pressure Relieves Well- Integrity Concerns,” by Prashun Kumar Das and Wael Moneer El-Mandrawy, Qatargas, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed. One of the operator’s newly acquired ventures is in the North field offshore Qatar. Abnormal rise in Annuli C and D pressures during the last phase of drilling highlighted the need to investigate the condition of producing wells on other platforms. The chances of inner annuli becoming charged with shallow-gas pressure and possible communication to Annulus D was thought to be a well-integrity concern. Establishing safe access to the sealed and potentially gas-charged Annulus D thus posed a challenge. Introduction The North field is offshore northeast of Qatar and is the world’s largest nonassociated-gas field. The wells are typically 7-in. monobore completed with a 26-in. conductor and three casing strings. Wells are completed with a liner-top isolation packer, tied back to the surface with 7-in. corrosion-resistant-alloy tubing. The annuli between the well casings are labeled A (7×10¾ in.), B (10¾×13? in.), C (13?×18? in.), and D (18?×26 in.). Provisions were made for monitoring and bleeding off pressures in Annuli A, B, and C. Background During the drilling and well-completion phase, some of the wells developed unusual pressures in Annulus C. Attempts were made to bleed off gas through the drilling facility. However, pressures built up every time, indicating a continuous intrusion of gas. Further pressure bleedoff was not attempted because of concerns that it may open up the communication channels and aggravate the situation. Several attempts were then made to lubricate and fill Annulus C with treated brine, but these attempts did not help to subdue the gas pressure. A proposal was then made to operate the wells with modified maximum-allowable-annulus- surface-pressure and maximum-allowable- wellhead-operating-pressure techniques for Annulus C, considering it fully charged with gas. With time, it was established that the same wells also developed gas pressure in Annulus D.

Successful Application of Intelligent Completions in Al Khalij Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 172027, “Successful Application of Intelligent Completions in Al Khalij Field,” by X. Briz-Quintero, M. Sofyan, P. Pouget, J. Le-Roch, J. Authier, and Y. Deffous, Total; S.F. Gurses, E. Gulamov, and N. Mukashev, Schlumberger; and M.R. Jaafar, I. Abul-Hamd, and A.R. Al-Naimi, Qatar Petroleum, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13.November. The paper has not been peer reviewed. Al Khalij field offshore Qatar is formed of a highly heterogeneous carbonate reservoir with significant remaining dynamic uncertainties. Moreover, given the current high field water cut, any operation to decrease it can have a large effect on field oil potential. This paper details the design, planning, and execution of the intelligent-completion technology in the field and covers the value generated for field development. Field Location The field, discovered in 1991, is located offshore Qatar (60-m water depth) and is adjacent to the Iranian border (please see the complete paper for a reservoir and geological description). The field was put into production in 1997 and has been developed through three successive phases. In 2013, 42 electrical-submersible-pump (ESP) -activated wells were producing 223,000 B/D of liquid, with an average water cut slightly below 90%. Eight injectors are available for a total injection capacity of 205,000 BWPD. A water- treatment platform, PP1 (adjacent to the DP2 platform), allows an injection rate of 190,000 BWPD on the DP3 and WP3 platforms. On the DP4 and DP1 platforms, injected water is produced from a regional shallow aquifer, Umm Er Radhuma (600. m). The production is exported to Halul Island facilities through two pipes (Fig. 1). Well Architecture The well architecture in Al Khalij field is characterized by a 1500- to 2000-mlong 9.-in. production casing set in the Mishrif formation, an (on average) 1500-m-long 7-in. cemented-andperforated production liner, and an (on average) 1500-m-long 6-in. openhole extension. Both the 7-in. liner and the open hole are acid stimulated before well production. Other well architectures are also present in the field. The oil-producing wells are ESPactivated. They are completed with two ESP strings in order to avoid production shortfalls while waiting on the workover rig should the primary ESP fail. Downhole monitoring is provided by the pressure/temperature (P/T) gauges located at the bottom of each ESP. Fig. 2.presents a schematic of a standard dual-ESP completion with zone selectivity. Smart-Well Strategy Intelligent-Completion Components. The subsurface components consist of a subsurface-controlled subsurface safety valve, production packer, temporary tubing-plugging device (to set the production packer), ESPs (including P/T gauges), isolation packers, and surface hydraulic-controlled flow-control valves (FCVs). No valve-positioning modules or additional gauges are incorporated in the string; therefore, a robust valve-tracking system is available in order to track the valve position. The FCV actuation is achieved with portable hydraulic pumps and can be actuated manually by the service- provider specialists whenever needed.

カタール沖合における高濃度H&lt;sub&gt;2&lt;/sub&gt;Sを含む中小油田の開発

カタール沖合における高濃度H&lt;sub&gt;2&lt;/sub&gt;Sを含む中小油田の開発

Technology Focus: Horizontal and Complex-Trajectory Wells (November 2010)

Technology Focus In the late 1980s, I helped plan one of the first horizontal wells in the UK North Sea. One aspect I recall was trying to force well-planning software to form a sensible trajectory from the surface location to the geometrically defined horizontal targets. The software did not cooperate until we realized that we had to plan the well from the bottom up. We had to enter the toe and heel target locations first and then build the trajectory back to surface. I never had to do that before, but it worked. When asked to write this introduction, the significance of that experience became apparent. It was the first time I remember planning a well from the bottom up. As horizontal-drilling activity increased, so did focus on the reservoir to improve the payback from these “more expensive” wells. As confidence to deliver these wells grew and performance improved, consideration was given to more-complex trajectories to enhance reservoir performance further. Over the last 20 years, this focus on the reservoir has driven tremendous advances in drilling and completion technology. Initially, these technologies were applied in high-cost drilling locations, but now are relied upon to improve or even to enable productivity more widely. For example, in the Middle East, complex multilateral wells are commonly drilled by use of advanced technologies to improve reservoir performance. Another example is onshore North America. Since mid-2009, there are more rigs drilling horizontal wells in this area than any other type of well. Application of advanced technologies onshore North America has enabled production from otherwise stranded reserves in these unconventional reservoirs. It is difficult to imagine any capability over the last 20 years that has contributed more to sustaining affordable energy supply than widespread application of horizontal wells, and we should expect the level of complexity to grow as the energy supply tightens. Horizontal and Complex-Trajectory Wells additional reading available at OnePetro: www.onepetro.org IPTC 13066 • “Characterizing the Flow Units in Carbonates With Production Logging and Borehole Images: Developing a Workflow in Western Offshore India,” by Ram Avtar, ONGC India, et al. IPTC 13453 • “Utilizing Advanced Well-Placement Process To Develop Structurally Complex Areas in Maydan Mahzam Field (Offshore Qatar)” by A. Al-Ahmed, Qatar Petroleum, et al. SPE 132816 • “An Innovative, Low-Cost Approach to Deriving Stress Conditions To Maximize Reserves Recovery in Unconventional Reservoirs” by Jason Kneedy, Chesapeake Operating, et al.

Successful Implementation of a Gas-Injection Trial in a Low-Permeability Carbonate Reservoir Offshore Qatar

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 13327, ’Successful Implementation of a Gas-Injection Trial in a Low-Permeability Carbonate Reservoir Offshore Qatar,’ by Kristian Mogensen, SPE, and Soren Frank, SPE, Maersk Oil Qatar, and Rashed Noman, SPE, Qatar Petroleum, prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. The planning and implementation of a lean-gas-injection trial conducted in the low-permeability Kharaib B carbon-ate reservoir of the Al Shaheen field, offshore Qatar, is described. The main objectives of the trial were to determine whether premature gas breakthrough would occur in the neighboring production wells and whether water injectivity after the gasflood would be reduced as a result of the presence of high gas saturation around the injection well. Introduction The Al Shaheen field began production in 1992 from two thin separate Cretaceous carbonate formations and an overlying sandstone formation. Field development used horizontal wells, some placed in radial patterns and others in parallel line-drive patterns of alternating water injectors and oil producers. These carbonate reservoirs are relatively thin oil columns with a large areal extent (25×45 km) with permeabilities in the 1- to 10-md range. The reservoir-fluid properties exhibit large lateral variations, with oil gravities ranging from 16 to 38°API within the same reservoir. The field contains several gas caps and shows large variations in solution gas/oil ratio (GOR) and in saturation pressures. Development studies focus on expanding of the current waterflood and on enhanced oil recovery (EOR). A promising EOR process is water-alternating-gas (WAG) injection that uses either CO2 or hydrocarbon gas as the injectant. A coordinated effort was initiated in 2006 to evaluate the scope for incremental field oil recovery. An important part of the EOR evaluation was to conduct an early gas-injection trial for a period of 6 months in the Kharaib B reservoir. The purposes of the trial were to investigate whether unexpected large-scale permeability heterogeneities exist in the reservoir, to gather gas- and water-injectivity data, and to gain experience for planning potential WAG-injection applications for the whole field. Planning Phase The most important part of the preparatory phase was to select the correct injection well for the trial to ensure that the trial objectives could be met. Once selected, the required modifications to the surface facilities then could be scheduled and a data-gathering program set up.

Technology Focus: Offshore Drilling and Completion (April 2010)

Technology Focus After a high-activity and high-oil-price period, we again entered into a low phase of the cycle in which reducing costs becomes our priority. Meanwhile, we still must deliver barrels and wells, in due time, keeping employees safe and healthy, and without any damage to the environment. Consequently, we are obliged to intensify efforts to innovate and try new concepts, either to access prospects that were technically not possible just a few years ago or to increase recovery from mature and declining fields without spending excessive amounts of money. But we should keep in mind that technical progress is not the only path to improve our global and economic performances. Such an improvement should include an established process of questioning all our practices, including but not limited to: Adapted personnel management—because at the end of the day, the quality of the deliveries is linked closely with the training and knowledge of the employees running the job Contractual changes that establish win-win relationships between the parties—it is always useful to remember that a good contract is a contract making both parties happy Working transversely throughout all companies and contractors to establish and generalize commonly agreed on standards and best practices The following summaries and additional reading suggestions provide good examples of our constant research of new technologies. But our scope of work is much larger, and every improvement in every aspect of our job will help us to push away this decline of our industry that some prophets foresee; it is not closer today than it was 10 or 20 years back. Offshore Drilling and Completion additional reading available at OnePetro: www.onepetro.org OTC 20295 • “SBOP Drilling Enables Efficient Drilling in Extreme Water Depths” by Michel Dib, Intecsea, et al. IPTC 13142 • “Anticollision and Risk Management Offshore Qatar: A Successful Collaboration” by Benny Poedjono, SPE, Schlumberger, et al. OTC 20277 • “Moho Bilondo—The First Deepwater Development Offshore the Republic of Congo” by Claude Cahuzac, Total, et al.

Technology Focus: Production Operations (March 2010)

Technology Focus I was joking with my colleague Todd Zahacy that we should write a series of papers about the number of things we production engineers usually do not know when trying to design or optimize a production system and, therefore, the risks we take that things may not go exactly as planned. Zahacy was quick to forward me a link to the now-famous quote of former US Secretary of Defense Donald Rumsfeld (explaining the limitations of intelligence reports): “There are known knowns. There are things we know we know. We also know there are known unknowns. That is to say, we know there are some things we do not know. But there are also unknown unknowns, the ones we don’t know we don’t know.”* I was thinking mostly of our lack of scientific knowledge in certain areas, but Zahacy reminded me that bad-quality data or bad assumptions also can lead to devastating results. We both believe that engineers should often question the source of information and the validity of assumptions, and then make a conscious effort to think about significant effects that may not have been considered. Some of the papers featured in this issue stress the importance of knowing as much as possible about a production-operation issue before trying to address it: knowing where (and why) the produced fluids or solids are entering the wellbore before planning a workover or knowing how a downhole device is likely to function (or not) under certain operating conditions before installing it in a well, among other issues. Other papers listed here stress the importance of questioning one’s source of information (e.g., the validity of some meters’ readings and/or the representative nature of some fluid samples). Usually, we are good at sharing our successes, but we can also learn much from our failures. Let us share more often the troubles we sometimes get ourselves into, and save our peers in the industry some grief. Production Operations additional reading available at OnePetro: www.onepetro.org OTC 20204 • “The Impact of Reservoir-Fluid Compositional Variation and Valid Sample Acquisition on Flow-Assurance Evaluation” by Oliver C. Mullins, SPE, Schlumberger, et al. IPTC 14068 • “Multiphase Metering in Siberian Gas and Condensate Wells—Lessons Learned in Multiphase Well-Testing Operations Since 2006” by Bertrand Theuveny, SPE, Schlumberger, et al. SPE 123949 • “Case Study: Successful Application of a Novel Conformance Treatment in an Extended-Reach Horizontal Well in the Al Shaheen Field, Offshore Qatar” by M.H. Pedersen, SPE, Maersk Oil Qatar, et al. IPTC 13765 • “Successful Field Application of an Inhibitor-Concentration-Detection System in Optimizing the Kinetic-Hydrate-Inhibitor (KHI) Injection Rates and Reducing the Risks Associated With Hydrate Blockage” by Orlin Lavallie, Dolphin Energy, et al. OTC 20013 • “Operation of Multiphase Flowmeters in the Sour Environment of the Qatif Field, A Case Study” by Faisal M. Al-Dossary, SPE, Saudi Aramco, et al. *www.scientifi camerican.com/article.cfm?id=rumsfelds-wisdom accessed 27 January 2010.

High-Angle Directional Drilling With 9 5/8-in. Casing Offshore Qatar

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 119446, "High-Angle Directional Drilling With 9⅝-in. Casing in Offshore Qatar," by Michael Avery and Tod Stephens, Occidental Petroleum of Qatar Ltd.; Ali K. Al-Hadad, SPE, Qatar Petroleum; Mounir Turki, SPE, Tesco Corp.; and Malek Abed, SPE, Schlumberger, originally prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed. Horizontal-well programs that require drilling through unstable formations at high angles before entering the productive zone are becoming more common. Casing while drilling (CWD) is becoming a powerful method in mitigating both lost-circulation and wellbore-stability issues in offshore directional wells. As a result of recent advances in tool design, it is now possible to circulate, rotate, and reciprocate the casing during bottomhole-assembly (BHA) retrieval and setting operations without modifications to the rig. Introduction Occidental Petroleum of Qatar currently drills a number of offshore horizontal production and injection wells in the Shuaiba limestone formation. Directly above the Shuaiba is the Nahr Umr formation, which is composed of a nonreactive, but unstable, kaolonitic shale. The 12¼-in. section is drilled conventionally approximately 80 ft into the Shuaiba [20 ft true vertical depth (TVD)] at up to 86° inclination, and a 9⅝-in., 47-lbm/ft L-80 casing string is run and cemented to isolate the shale and sand while drilling the 8½-in. reservoir section. The Nahr Umr/Shuaiba interface is often a point where highly conductive faults are encountered. Severe losses of drilling mud often occur at this interface, resulting in a dramatic reduction of hydrostatic pressure as the wellbore-annulus fluid level falls. This pressure loss causes the unstable formation to collapse on the drillstring and BHA, packing it off and making it practically impossible to retrieve. The Shuaiba exploitation strategy, however, depends on landing wells at near-horizontal angles so that long sections can be drilled in the reservoir. A potential solution to this problem is to drill the section with casing and a retrievable BHA. Directional CWD technology uses the casing, in place of drillpipe, to convey rotation and torque and act as a conduit for the drilling fluids. The directional BHA is latched to the lowermost casing joint and extends approximately 85 ft out of the shoe. It is driven by both surface rotation and a downhole motor. For this application, an 8½-in. bit is used to drill a pilot hole, which is opened up immediately to 12¼ in. by an underreamer positioned just below the 9⅝-in. casing-reamer shoe. The BHA can be retrieved through the casing at any point during the drilling operation by running in through the casing with drillpipe and a latch tool.

Replacing Wireline Formation Pressure With Formation Pressure While Drilling in Long Horizontal Wells

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 12103, "Replacing Wireline Formation Pressure With Formation Pressure While Drilling in Long Horizontal Wells," by J.K. Larsen, SPE, Maersk Oil Qatar; C.J. Maeso, SPE, and F. Liu, SPE, Schlumberger; and R. Narayanan and R. Noman, SPE, Qatar Petroleum, prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed. A case history presents how formation-pressure-while-drilling (FPWD) technology effectively has replaced traditional pipe-conveyed wireline technology in long horizontal wells. The Al Shaheen field, offshore Qatar, in the Middle East, is developed with 20,000- to 30,000 ft-long horizontal wells, drilled in radial and line-drive patterns in one sandstone and two carbonate reservoirs. Eleven FPWD jobs were performed within the first year, and FPWD now is the preferred option for formation-pressure acquisition in Al Shaheen. Introduction Knowledge of the reservoir pressure is essential for understanding the behavior of the reservoir fluids. Fluid gradients are used to establish fluid contacts in the reservoir, and pressure data obtained during the production phase reveal important information about drive mechanisms and the geology. Traditionally, wireline formation testers have been used to obtain formation pressures. FPWD tools have advantages and disadvantages compared to wireline formation testers, depending on the type of well and the objectives of the logging program. Understanding these advantages and disadvantages and the objectives of the logging program is required, and is best achieved through a joint effort by the operator and the service company. The full-length paper details the transition of, and the considerations associated with, introducing FPWD in the Al Shaheen field. Al Shaheen Field The Al Shaheen field is a low-relief structure with an areal extent of approximately 40×60 km and is developed in three main reservoirs: Nahr Umr, Shuaiba, and Kharaib (known as Thamama B elsewhere in the region). The Nahr Umr formation is a thin sandstone reservoir normally less than 15 ft thick, with a target zone less than 3 ft thick. The high-permeability target zone often is unconsolidated. The Shuaiba formation is a highly heterogeneous carbonate reservoir with large permeability contrasts associated with facies changes. The Kharaib formation is a tight carbonate reservoir with uniform reservoir properties across the field. The Kharaib permeability ranges from 1 to 10 md. The 20,000- to 30,000 ft-long horizontal wells are drilled with geosteering to control the position of the wells in the reservoir. Optimal well spacing ranges from 600 ft in the tight Kharaib formation to 2,000 ft in the high-permeability Nahr Umr sandstone. Fig. 1 shows the well placement in the three reservoirs in the northeastern part of the Al Shaheen field. Water injection is used extensively for pressure maintenance in all three reservoirs.

Unstructured Gridding for Full-Field Simulation of a Giant Carbonate Reservoir Developed With Long Horizontal Wells

This article, written by Technology Editor Dennis Denney, contains highlights of paper IPTC 11512, "The Application of Unstructured Gridding Techniques for Full-Field Simulation of a Giant Carbonate Reservoir Developed With Long Horizontal Wells," by H. Vestergaard, SPE, H. Olsen, SPE, and A.S. Sikandar, SPE, Maersk Oil Qatar, and I.A. Al-Emadi and R. Noman, SPE, Qatar Petroleum, prepared for the 2007 International Petroleum Technology Conference, Dubai, 4–6 December. The paper has not been peer reviewed. A case history is presented on reservoir simulation of a giant, complex, low-permeability, carbonate reservoir completed with many long horizontal wells. The multiple radial layouts of 75 very long horizontal wells in the field posed a challenge in modeling individual-well performance with a manageable grid size and acceptable run time for history matching. The gridding dilemma was solved by use of 2.5D perpendicular-bisector (pebi) grids around each individual wellbore. This method provided sufficient resolution between wells and aligned the grid with the well paths, thereby avoiding grid nonorthogonality issues. Introduction The Al Shaheen field is offshore Qatar, covering an area of 800 sq miles. The Kharaib formation is part of the Lower Cretaceous Thamama group. The dome-shaped reservoir has a net oil-column thickness of 23 ft at the crest of the field, thinning toward the flank. The field has relatively low permeability, ranging from 1 to 15 md. Developed wells have no pressure support from the distant flank aquifer or the trapped water in the central part of the field. Oil gravity varies significantly: saturated low-viscosity (&amp;lt;1 cp) oil to highly undersaturated higher-viscosity (35-cp) oil. The field has several local gas caps and a free-water level (FWL) dipping more than 500 ft across the field. At the time of this study, the reservoir was developed with 75 ultralong horizontal wells, up to 30,000 ft long, drilled in alternating producer/injector patterns from five platforms. Production from the field began in 1994, and secondary recovery by water injection commenced in 1997. Continuing evaluation of reservoir performance and assessment of further development potential of the field prompted the need for detailed history matching on a full-field basis. Modeling issues detailed in the full-length paper were part of a history-matching study completed in 2004 that formed the basis to develop the reservoir with an additional 89 wells to infill existing well pat-terns and to develop the thinner oil column toward the flank of the reservoir. Background The Kharaib B formation is a laterally continuous limestone with a relatively constant thickness of approximately 80 ft within the subject area. Oil gravity ranges from 38°API at the crest of the field to 12°API at the northern flank. The saturation pressure varies from saturated near the gas caps to 1,300 psi undersaturated in low-gravity areas. There is not, however, a distinct correlation between saturation pressure and oil gravity. The large variation in saturation pressure indicates different natural-drive mechanisms in different areas of the reservoir.

Optimization of Big-Bore Wells in a Giant Offshore Field

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105509, "Design, Construction, and Optimisation of Big-Bore Gas Wells in a Giant Offshore Field," by B.M. Clancey, SPE, A.S.D. Khemakhem, SPE, and T.F. Bene, RasGas Co. Ltd., and M.H. Schmidt, SPE, ExxonMobil Development Co., prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20-22 February. An extensive big-bore gas-well drilling and completion program is in progress to develop the giant North field offshore Qatar. Benefits of the big-bore concept compared to the previous 7-in.-monobore design include reduced development costs by requiring fewer wells and deferred installation of compression by providing higher flowing wellhead pressures (FWHPs). This is the widest application known of big-bore wells in a single field and involves more than 75 wells. An extensive system of detailed design review, equipment-performance testing, and quality programs was implemented to meet project requirements for well reliability. Introduction Discovered in 1971, the North field of Qatar extends over approximately 2,316 sq miles and contains approximately 900 Tcf of abnormally pressured natural gas. Development has taken place in several stages, commencing with initial production by Qatar Petroleum in 1991 to supply the domestic gas market. More recently, the growth in global liquefied-natural-gas (LNG) demand has sparked much-more-extensive development. RasGas is responsible for the development of a large area of the North field, covering more than 193 sq miles, to provide natural gas for both new LNG trains and the growing domestic gas market. The RasGas expansion plan requires more than 75 wells to be drilled from 2002 to 2010. Production is from the massive Khuff carbonate formation, which includes several productive intervals (K1, K2, K3, and K4), at approximately 10,000 ft true vertical depth (TVD). More than 90 wells will be operated, producing a total of 8 Bscf/D. Well deliverability from the K1 to K4 reservoirs is very high because of formation quality, near-initial reservoir pressure, and high net-pay thickness. Well designs evolved from packer/tubing completions intended to produce 60 MMscf/D in the initial Qatar Petroleum project to high-rate 7-in.-monobore wells able to deliver more than 100 MMscf/D in the first LNG projects. Higher-capacity well designs, capable of producing more than 150 MMscf/D, could be suitable for the planned expansion projects. Although individual wells would be more expensive to construct, fewer wells would be required, and the higher FWHP would defer installation of compression facilities.

Methanogenesis during Shu’aiba diagenesis: examples from Al Shaheen Field, Block 5, offshore Qatar

ABSTRACT Evidence has been found for the involvement of bacterial methanogenic processes in the diagenesis of late Early Aptian Shu’aiba Formation sedimentary rocks from Block 5, offshore Qatar. This is in the form of δ13C values significantly higher than the presumed late Early Aptian marine signal. High δ13C values were recorded in early-formed inclusion-rich calcite that represents neomorphosed aragonite/marine cement (+6.6‰) and the latest precipitated blocky non-ferroan calcite cement (+8.9‰). Oxygen-isotope data suggest that the later methanogenic episode occurred during burial. In bulk rock samples from another well, δ13C values of +6.5 to +11.5‰ were determined from a 10 ft thick zone located 4 ft below the top of the Shu’aiba. In other wells for which data were available the equivalent interval of the Shu’aiba was characterised by expected marine δ13C values. Finally, δ13C values up to +9.1‰ were recorded in a localised area of dolomite replacement immediately beneath the Top Shu’aiba surface, which can be dated to after the onset of Nahr Umr Formation deposition. These are the first reported examples of methanogenic reactions affecting the Shu’aiba Formation and provide new insight into the diagenesis of this formation, which is often assumed to be dominated by meteoric processes. The evidence presented for the resetting of the carbon-isotope composition of the bulk rock has implications for the application of carbon-isotope stratigraphy to the Shu’aiba Formation.

Reservoir properties of Arab carbonates, Al Rayyan Field, offshore Qatar

Abstract Oil is present in the Upper Jurassic Arab A and Arab C carbonates of the Al Rayyan Field. The Arab A consists of porous limestone with thin units of tight dolomite at the top and bottom. Two reservoir intervals can be distinguished, separated by a slightly less permeable unit. The upper reservoir consists of stromatolites and cross-bedded peloidal-grainstones, whereas the lower reservoir consists predominantly of ooliticgrainstones. The less permeable unit comprises moderately cemented, cross-bedded peloidal-grainstones. Higher porosity and permeability generally occurs in the coarser grained, cross-bedded grainstones, where pores are mostly primary and intergranular; lower permeability is characteristic of grainstones with moderately developed early cement. Porosity is enhanced at some levels by the presence of leached intragranular pores, but these have little effect on permeability. The Arab C is strongly stratified and completely dolomitized. Three reservoir intervals can be recognized, separated by less permeable layers of poorer quality rock. The upper reservoir consists of partially leached and moderately cemented, cross-bedded bioclastic-peloidal-grainstones. Porosity is high because of the presence of leached intragranular pores in addition to primary intergranular pores but permeability is relatively low because of the presence of early cement. The main reservoir comprises loosely compacted and lightly cemented, cross-bedded peloidal-grainstones. Porosity is lower than that in the upper reservoir because leached intragranular pores are generally absent, but permeability is higher because cementation is relatively light. The lower reservoir is made up of peloidal-grainstones and coarse-grained bioclastic-grainstones. The upper and main reservoirs are separated by a thick interval of relatively tight, thinly bedded, strongly cemented peloidal-grainstones, whereas the main and lower reservoirs are separated only by a thin bed of tight, nodular anhydrite. The pore types and cements observed in the Arab C are similar to those of the Arab A, but dolomitization has resulted in an enhancement of permeability and capillary pressure properties compared to those of the Arab A. Thus, the overall water saturation of the Arab C is lower than that of the Arab A, and the displacement pressures and irreducible water saturations are also significantly lower than those of Arab A carbonates.

Abstract: Timing of Porosity Generation in Lower Cretaceous Reservoirs (Shuaiba and Kharib Formations), Block 5, Offshore Qatar

Abstract: Timing of Porosity Generation in Lower Cretaceous Reservoirs (Shuaiba and Kharib Formations), Block 5, Offshore Qatar

Abstract: Timing of Porosity Generation in Lower Cretaceous Reservoirs (Shuaiba and Kharaib Formations), Block 5, Offshore Qatar

Abstract: Timing of Porosity Generation in Lower Cretaceous Reservoirs (Shuaiba and Kharaib Formations), Block 5, Offshore Qatar

Field Experience With Multilaterals in the Idd El Shargi North Dome Field, Qatar

Summary This paper describes how one operator used the latest multilateral drilling technology to improve the profitability of the Idd El Shargi North Dome (ISND) field, offshore Qatar (Fig. 1). Dual openhole laterals have been employed to simultaneously exploit the Shuaiba A and B oil reservoirs. In each well drilled to date, the secondary wellbore has been cased off at the lateral junction following drilling of the fullbore lateral section. A mechanical junction has been used to ensure long-term mechanical integrity and re-entry capability following completion. To date, this technology has been used on five wells in the ISND field (IS-74, IS-75, IS-76, IS-77, and IS-80). Approximately 10 additional complex-drainage-architecture wells are planned in 1997 to further develop this field.

Optimized Bit and Motor Usage Offshore Qatar

This article is a synopsis of paper SPE 39249, "Optimized Bit and Motor Usage Offshore Qatar," by Michael A. Simpson, SPE, Ahmed Fakhro, SPE, and Ahmed Al-Bakri, Qatar General Petroleum Corp., by originally presented at the 1997 SPE/IADC Middle East Drilling Technology Conference, held in Manama, Bahrain, 23-25 November.