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Collaborating Authors
Occidental Petr. Qatar Ltd.
Carbon Capture and Sequestration: Overview and Offshore Aspects
Liner, Christopher (U. of Houston) | McCurdy, Paul J.A. (Occidental Petr. Qatar Ltd.) | Noyes, Kyle Carter (Occidental Petroleum Corp.)
Abstract Although this talk is about carbon dioxide (CO2), our starting point is energy. From the EIA Annual Energy Outlook (EIA, 2009) we find petroleum liquids, coal, and natural gas dominate the United States (US) energy mix. This energy picture is mirrored around the world. Most projections are that the energy load is going to increase in lock step with the current 1.2% world population growth. Jeffrey Stewart of Lawrence Livermore National Lab (LLNL) has been publishing diagrams illustrating this energy mix (Figure 1). If you are not used to looking at Stewart diagrams, they appear rather chaotic. But they are full of information about US and world energy use. For the US in 2002, the Stewart diagram shows net energy use of 97 quads (a quad is 10 BTU). It breaks down such interesting details as domestic and import oil input and oil usage divided between transportation (65%), industrial (10%), and residential (5%) fuels, as well as non-fuel use (13%). For each category of energy use, there is a certain amount of energy loss: usable energy and unused energy lost in the form of heat. We see that none of these energy applications is alarmingly efficient, but oil in transportation use is alarmingly inefficient with 80% of the energy lost.
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Metals & Mining > Coal (0.95)
Multi-Component Seismic Applications for Maximizing Efficiency and Production
Maili, Eduard (Occidental Petroleum of Qat) | Negulescu, Carmen (Occidental Petr. Qatar Ltd.)
Summary Carbonate reservoirs are often very heterogeneous and their properties are frequently difficult to understand. The presence of faults and intense natural fractures further increases the complexity that becomes very challenging for reservoir management and field development. This is the case of the Shuaiba reservoir in Idd El Shargi North Dome (ISND) Field in offshore Qatar. The field was discovered in 1960 and was first produced in 1964. The oil is produced from multiple reservoirs, primarily carbonate, on a salt induced faulted anticline. After 1995, when Occidental Petroleum assumed the operatorship role under a Production Sharing Agreement with the State of Qatar, an extensive horizontal well drilling and waterflood campaign resulted in a substantial production increase from the primary Arab and Shuaiba reservoirs. This paper will focus on the Shuaiba development results. New technologies have been applied to effectively manage the Shuaiba waterflood and continuously increase the oil recovery factor in this complex reservoir. The practical aspects of multi-component seismic technology described in this paper can be applied in any complex fractured reservoir for improving efficiency and increasing recovery. During 2003โ2005, Qatar Petroleum and Oxy acquired and processed a large 4C3D seismic survey over Idd El Shargi field (Fig.1). This technology uses multi-component phones and cross-spread acquisition geometry to record both compressional and shear (converted) waves. The survey ensured full azimuth coverage to offsets up to 3000 m, equivalent to an offset/depth ratio of two for the main target zone, achieving a nominal fold of 240 in the natural bin size, or a trace density of more than 2.7 million traces per square kilometer. The data were processed through a flow that carefully preserved the azimuthal anisotropy (Angerer et al, 2006).
- Geology > Structural Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.46)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > Idd El Shargi Field (0.99)
- Asia > Middle East > Saudi Arabia > Thamama Group > Kharaib Formation (0.98)
- Asia > Middle East > Qatar > Thamama Group > Shu'aiba Formation (0.96)
High Angle Directional Drilling with 9-5/8-in. Casing in Offshore Qatar
Avery, Michael John (Occidental Petr. Qatar Ltd.) | Al-Hadad, Ali Khalil (Qatar Petroleum) | Stephens, Jeffrey Tod (Oxy) | Turki, Mounir (Tesco Corporation) | Abed, Malek (Schlumberger D&M)
Abstract Programs which require drilling through unstable formations at high angle before entering the productive zone for a horizontal well are becoming more common. Casing while drilling is becoming a powerful method in mitigating both lost circulation as well as wellbore stability issues in offshore directional wells. Occidental Petroleum of Qatar Ltd. (OPQL) is faced with this task in drilling horizontal Shuaiba wells offshore Qatar. The unstable Nahr Umr shale formation lies directly above the Shuaiba payzone and is typically drilled with 12 ยผ-in. bits. The Nahr Umr shale tends to break up shortly after drilling, leading to stuck bottom hole assemblies (BHA) and difficulty running 9 5/8-in. casing. Exposure time with the Nahr Umr is often lengthened due to the requirement of continuous angle building and turning to land near horizontal. This paper details the directional casing while drilling (DCwD) developments that have been accomplished offshore Qatar and the various advantages of the process. Due to recent advancements in tool design, it is now possible to circulate, rotate, and reciprocate the casing during BHA retrieval and setting operations, all without modifications to the rig. These advantages coupled with the versatility of rotary steerable systems allow for a much more flexible process and enables defensive measures to be taken in the event of unforeseen complications. Introduction OPQL's offshore operation in the Idd El Shargi North Dome (ISND), Qatar, currently drills a number of horizontal production and injection wells in the Shuaiba limestone formation. Directly above the Shuaiba is the Nahr Umr formation, which is composed of a non-reactive, but unstable, kalonitic shale. The 12 ยผ-in. section is conventionally drilled about 80 ft into the Shuaiba (20 ft TVD) at up to 86 degrees inclination, and a 9 5/8-in., 47 ppf, L-80 casing string is run and cemented to isolate the shale and sand while drilling the 8 ยฝ-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 in on the drillstring and BHA, packing it off and making it practically impossible to retrieve. Until recently, the primary action in dealing with severe losses was to attempt to retrieve the BHA as quickly and as safely possible to avoid stuck pipe and the loss of the assembly. The intention was to run back in the hole with a simple rotary BHA and try to cure the losses so that drilling in the section could continue. However, in most cases to date, the collapse of the shale occurs rapidly and without warning with the drill string packing-off on the way out of the hole. The BHA is usually lost with a high economic impact on the well. The probability of this happening is directly related to the inclination angle of the well. Wells in alternate horizons that are vertical or at lower angles do not have this problem. The Shuaiba exploitation strategy, however, depends on landing wells at near horizontal angles so that long sections can be drilled in the reservoir.
- Asia > Middle East > Qatar (1.00)
- Asia > Middle East > Oman > Central Oman (0.44)
- Asia > Middle East > Qatar > Thamama Group > Shu'aiba Formation (0.99)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > Idd El Shargi Field (0.99)
- Asia > Middle East > Oman > Central Oman > South Oman Salt Basin > Nahr Umr Formation (0.99)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
Increasing Production and Injection in Multilateral Horizontal Wells in Naturally Fractured Carbonate Reservoirs by Rigless Intervention - A Case Study, Offshore, Qatar
Lisigurski, Omar (Occidental Petr. Qatar Ltd.) | Ferdiana, Wemphy (Occidental Petr. Qatar Ltd.) | Haro, Carlos Fabian (Occidental Oil & Gas Corporation) | Maili, Eduard (Oxy)
Abstract Due to the complexity and cost of stimulating horizontal multilateral wells in an offshore environment, all aspects of this project type must be considered prior to project implementation. Utilizing all technical disciplines to understand the reservoir characteristics and select intervention candidates greatly influences the chance of success for any project. During 2006โ2008, 39 wells (19 producers, 17 water injectors and 3 gas injectors) were stimulated in the Shuaiba reservoir in Idd El Shargi North Dome Field, offshore Qatar, resulting in production increases as high as 50% and injection increases as high as 100% in some wells. The wells were stimulated by rigless coiled tubing. A new tool that allows coiled tubing to enter each lateral in multilateral wells was used for these projects. This successful acid stimulation workover program utilized the fundamentals of engineering, geology, geophysics, and petrophysics and applied them with field operations. The screening methods developed led to further workover activity and new drilling development with anticipated reserve and production increases. Introduction Idd El Shargi North Dome (ISND) field was discovered in 1960. ISND is located approximately 55 miles east of Doha, Qatar. ISND is a shallow offshore field, located in water depths ranging between 100 and 150 feet (Fig 1). ISND production is dominated by the Jurassic Arab and Cretaceous Shuaiba carbonate formations, although Jurassic Uwainat (carbonate) and Cretaceous Nahr Umr (clastic) are also developed. Production began in 1964, and Occidental Petroleum of Qatar Ltd. (OPQL) entered into a production sharing agreement with the State of Qatar to operate and develop the field in 1994. The Shuaiba reservoir is the largest of the ISND reservoirs in terms of oil in place but the recovery factor is very low. The Shuaiba reservoir is a densely fractured and highly faulted, low permeability carbonate reservoir. Various well configurations such as single lateral horizontals and multilateral horizontal completions have been used to develop this reservoir. A liftboat unit was contracted in 2006 for data acquisition and rigless stimulation. The successful stimulation campaign explained in this paper is the result of utilizing all technical disciplines to understand the reservoir characteristics for selecting underperforming candidates and designing the stimulation. In this paper, an actual field example is used to show how candidate wells can be identified and how the intervention design can be prepared utilizing a multidisciplinary team effort (geophysicists, geologists, petrophysicists, reservoir and operations engineers). In addition, the paper will explain one technology that can be used to stimulate horizontal multilateral wells without a drilling/workover rig. The methodology described in this paper can be applied to any field that has horizontal and multilateral wells, especially those fields containing naturally fractured carbonate reservoirs. Reservoir Description The Shuaiba formation is extensively faulted and fractured due to domal uplift and regional tectonic events. Shuaiba is a high porosity and low permeability reservoir where large and small scale fracturing has created enhanced permeability regions and pathways in an otherwise tight matrix reservoir. The Shuaiba formation consists of four layers: Shuaiba A, B, C and D and is bounded by two shales: Nahr Umr (above) and Hawar (below). Shale barriers vertically separate the layers, although communication occurs through fractures and faults. Shuaiba A, B, and D are most productive and Shuaiba A is the most prolific, containing the highest percentage of the total Shuaiba oil in place. The Hawar Shale located below Shuaiba D closes the Shuaiba sequence. Immediately below the Hawar Shale is the Kharaib series of carbonate layers. These productive intervals are similar in nature to the Shuaiba D and are in pressure communication with the Shuaiba layers through fractures and faults.
- Asia > Middle East > Qatar > Arabian Gulf (0.68)
- Asia > Middle East > Qatar > Ad-Dawhah > Doha (0.24)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > Idd El Shargi Field (0.99)
- Asia > Middle East > Qatar > Thamama Group > Shu'aiba Formation (0.97)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.94)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.94)
Entering Multilateral Wells Using Coiled Tubing
Proctor, Robert John (BJ Services Inc.) | Grant, Ryan (BJ Services Company) | Marron, Andrew James (Occidental Petr. Qatar Ltd.) | Cubas Alvarez, Danny Paul (Occidental Petr. Qatar Ltd.)
Abstract Coiled tubing is utilized to enter horizontal wells for the purpose of performing general remedial well operations. Common operations performed include but are not limited to stimulation treatments, solvent treatments, cleanouts and water shut-off. In today's oilfield, many horizontal well plans incorporate the drilling of multiple laterals. Entering multiple laterals, in one well, using coiled tubing, requires guidance. Advanced completion designs may facilitate such guidance. However, in the case of open hole multi-lateral wells a guidance system is not incorporated in the completion design. This paper will discuss a reliable commercially available technology, developed for the purpose of entering open hole multilateral wells using coiled tubing. The paper will review bottom hole assembly functionality, development of this technology and applications. In addition, offshore case histories of wells entered using multi-lateral entry guidance technology will be summarized. Introduction Open hole, horizontal multilaterals exist in a number of fields throughout the world and have proved cost-effective to drill, delivering high rate wells in the short term. However, longer term, as the production declines and the water cut increases in the well, typical intervention operations are required: water conformance, stimulation, production logging and water shutoff to mention only a few. Open hole, horizontal multi-laterals are typically not designed for enabling interventions into the laterals during the lifecycle of the well. The usual method of intervention would require a drilling or workover rig to pull the completion and then use jointed pipe to guide the tools into the desired lateral, typically using a bent piece of pipe. However, the high rig rates, long workover times, limited rig availability, the inherent operational risks and the high potential for formation damage make workovers with a rig very costly. Alternatively, well interventions could be done through-tubing with coiled tubing, a much cheaper method of conveyance than jointed pipe. However, for coiled tubing to enter all the laterals in a open hole, horizontal multilateral well, a guidance system would be required as coiled tubing has no inherent steering capability. Presently today there is a reliable commercially available solution to enter multilateral wells using coiled tubing, the Lateral Entry Guidance System. Lateral Entry Guidance System: Solution to enter multilaterals Using Coiled Tubing The challenge of entering open hole multilateral wells is not a simple problem. Consideration was given to the problem with respect to how complex should the tool string be. Effective tool design should be "simple is best". For this reason, a tool was designed to ensure that laterals may be entered without electronic telemetry systems. Simple tools are easily introduced and implemented on a global basis thereby enabling access of this important technology to all operating regions. The lateral entry guidance system is a fluid activated tool. This enables the tool to be run on virtually any coiled tubing unit. In fact, the tool may also be run on jointed pipe if required.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- Information Technology > Architecture > Real Time Systems (0.47)
- Information Technology > Information Management > Search (0.46)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Search (0.46)
- Information Technology > Artificial Intelligence > Natural Language > Information Retrieval (0.46)
Abstract The objective of this paper is to provide insight on the design of downhole gas separators based on laboratory studies of various designs. A downhole gas separator, also known as a gas anchor, may be installed below the pump to separate free gas from the produced liquid. The gas that is separated downhole is produced through the casing-tubing annulus and the liquid is produced through the tubing. Unfortunately inefficient gas anchors are common and an acceptable guide for their optimum design does not exist. Laboratory testing of downhole gas separators has been ongoing since January 2005 at the University of Texas at Austin using an instrumented full scale model of a wellbore and separator constructed with clear acrylic pipe to visualize the fluid mechanics of the separation process. An air and water mixture is injected through the well's perforations. The air and water flow rate measurements are used to measure and define a performance plot of each separator design. Both continuous and intermittent flow conditions were applied in the tests. The separator designs that were tested differ in entry port configuration, size of dip tube and relative position of the separator with respect to the well's perforations. Based on the results of the tests, a new separator design that includes the effect of centrifugal forces to separate the gas and liquid phases was developed. The results show that, for the conditions in the laboratory, 100% separation was achieved whenever the entry ports were located 1 to 2 feet below the bottom-most casing perforation. The entry port geometry does not appear to have a significant impact on the separator efficiency as long as sufficient flow area is present. The efficiency of all gravity driven separators was limited by the liquid velocity inside the separator annulus. When the liquid velocity inside the separator averaged approximately 6 in/s or less, an almost to complete gas separation was achieved. On the other hand, the centrifugal separator had a liquid capacity 70% greater than any of the gravity driven static downhole gas separators. Introduction Effectively separating free gas from liquid at the bottom of the well optimizes the performance of any pumping system. This insures that only liquid enters the pump and all the gas flows up the casing-tubing annulus. The most effective gas separator is the casing annulus, since its large volume provides the best opportunity for gas-liquid gravity separation to occur. When the pump intake is set below the perforations all the gas will be produced through the casing. Nevertheless, when the pump intake cannot be set below the perforations, a downhole gas separator (also known as a gas anchor) is installed below the pump. Gas anchors are usually built by operators with material that is readily available and with a simple construction, hence the name 'Poor-boy'. Many gas anchors constructed this way are inefficient, and unfortunately, there is no reliable methodology for building an effective gas anchor. This paper provides a better understanding of the variables that affect the performance of downhole gas separators based on the analysis of laboratory results. Different gas anchor designs were tested in a full scale laboratory well with a water and air mixture injected into its perforations. The injection rates ranged from approximately 150 BPD to 750 BPD for water and from 15 to 120 MMCFD for air. In addition, the flow rate of air that entered through the separator was measured. Using these water and air flow rate measurements, we obtained performance curves of each separator design. All the separators tested were six feet long. Three separator designs used gravity forces to separate the gas from the liquid and had a 5.5 ft long dip tube. The fourth design was a static (no rotating parts) centrifugal separator with a wire reinforced PVC hose as a spiraled dip tube inside the separator. The separator designs were tested for continuous and intermittent flow to simulate the effect of artificial lift selection (electrosubmersible and progressing cavity pumping versus sucker rod pumping). We studied the effect of variations on entry port configuration, dip tube diameter, and entry port position relative to the casing perforations.
A Laboratory Study With Field Data of Downhole Gas Separators
McCoy, James N. (Echometer Company) | Podio, Anthony L. (U. of Texas Austin) | Lisigurski, Omar (Occidental Petr. Qatar Ltd.) | Patterson, John C. (ConocoPhillips) | Rowlan, Orvel Lynn (Echometer Company)
Summary Downhole gas separators are often the most inefficient part of a sucker-rodpump system. This paper presents laboratory data on the performance of fivedifferent gas-separator designs. Only continuous flow was studied. Field dataare presented on two of the designs. The field data indicate that success orfailure of the gas separator is dependent upon the fluids and wellborepressures as well as the mechanical design of the gas separator. Successful andunsuccessful examples of gas-separator performance in the field are shown alongwith field fluid data properties. Introduction Gas interference in downhole plunger pumps has been studied for severalyears. The first comprehensive analysis was presented by Clegg (1963), whodeveloped a theoretical analysis of separator performance and set some of therules of thumb that are still in use today. These guidelines were applied insubsequent studies that developed practical methods for matching separatorperformance to specific well producing conditions (Campbell and Brimhall 1989;Dottore 1994; Ryan 1992). Poor performance of downhole rod pumps and problemswith progressing cavity (PC) pump operation owing to gas prompted theundertaking of laboratory experimental studies by Robles and Podio (1999) thatincluded visual observation of separator-fluid mechanics using a full-scaleplexiglass wellbore and a conventional rod pump. The problem of downhole gasseparation recently has become of further interest in relation to dewateringlow-pressure gas wells and operating coalbed-methane wells. Patterson andLeonard (2003) studied some different downhole gas-separation designs forcoalbed-methane operations in Wyoming. In these designs, the inlet to the gasseparators was smaller than normal and, along with some baffles, was thought toallow gas to vent from inside the gas separator, obtaining good gas separationin the field installation. While field installations provide the ultimatevalidation of gas-separator performance, it is extremely difficult to isolatethe influence of each design parameter. It was these installations thatprompted the laboratory study of the gas-separator geometry to determinewhether the rules-of-thumb used by the industry for gas-separator design werevalid (Lisigurski 2004). One of the most common sources of inefficiency in oilwell pumpinginstallations (rod pumps and ESPs of PC pumps alike) is gas interference, whichprevents the pump from delivering liquid at the design rate. Although this is awell-known effect, there seems to be limited understanding of the mechanismsthat control gas interference, and this often results in the use of remedies, such as installing downhole gas separators, that are ineffective or evendetrimental to the pumping-system performance. The objectives of this paper are to give a clearer insight on the mechanismsof gas interference in pumping wells and to present the results of recentlaboratory and field studies on the flow characteristics and performance ofsome downhole gas separators. In a pumping installation, one of the principal functions of the wellbore isto operate as a two-phase (gas/liquid) separator so that the pump (which isdesigned to pump liquid) can operate efficiently. Although this concept appearsto be obvious, it seems to be totally ignored by most operators when theydesign completions and install hardware (gas anchors and the like) to combatthe effects of gas interference. In these applications, the separation of gas from liquid is achieved throughgravity separation without the introduction of other mechanisms (centrifugalforces, nozzles, etc.). Thus, the difference in density between the gas andliquid is the main driving force to be used for separation. This also impliesthat forces that oppose the effect of gravity, such as viscous drag caused byhigh fluid velocity and turbulence, will be detrimental to the separationprocess. Thus, high velocity of liquid or gas should be avoided ifpossible.