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Collaborating Authors
Pioneer Natural Resources
Comparing the Results of a Full-Scale Buckling Test Program to Actual Well Data: New Semi-Emprical Buckling Model and Methods of Reducing Buckling Effects
Mitchell, Sarah (WWT International Inc.) | Moore, Norman Bruce (WWT International Inc.) | Franks, James (Pioneer Natural Resources) | Liu, Gefei (Pegasus Vertex Inc.) | Yang, Yanghua (Pegasus Vertex Inc.)
Abstract Buckling and its effects are topics of economic and technical interest as ERD and horizontal wells become critical to maximizing recoverable reserves, particularly in the Continental United States and Alaska. Previous work has resulted in important discoveries about drill string buckling, but to date, little testing has been done on actual drill pipe in a controlled manner, particularly in measuring drill string whirl. As a result, there can be disparities between theoretical predictions of buckling effects versus actual field results. These disparities can result in unrealistically high friction factors required to bring calculated values close to actual data, or in many cases, operational difficulties such as high torque, low ROP, drill string failures, inability to maintain directional control, or reach the planned depth can result. To learn more about drill string behavior in buckling conditions, a full-scale buckling test fixture was developed to evaluate the effects of buckling on 2 โ โ, 3 ยฝโ, and 4-inch drill pipe while sliding and rotating inside 7 inch casing. The test fixture incorporated a variety of sensors and cameras to characterize torque, drag, vibration, and drill string deformation under buckling loads. As part of the test program, low friction non-rotating protectors were also tested to measure performance under buckling conditions. The test results show that drill string buckling occurs at far lower loads than predicted by current models, possibly caused by minor deformations inherent in real drill pipe. The results also show that for a given amount of torque or drag, protectors increased the available compressive load by 20 to 30% and substantially reduced vibration caused by drill string whirl. The test results were used to develop a new Semi-Empirical Buckling Model that predicts contact forces resulting from drill string buckling and also the torque and drag effects of drill string whirl. This model was then incorporated into torque and drag modeling software where it was compared against actual data from a large number and variety of wells. The results show an ability to more accurately predict torque, drag, and vibration caused by buckling and whirl.
A Pilot Test of Continuous Bottom Hole Pressure Monitoring for Production Optimization of Coalbed Methane in the Raton Basin
Rotramel, Jennifer (Pioneer Natural Resources) | Bell, Morris (Pioneer Natural Resources)
Abstract Pioneer Natural Resources (Pioneer) operates over 2200 Coalbed Methane (CBM) wells in the Raton Basin in Colorado. The wells produce out of two formations: the upper Raton and the lower Vermejo Formations. Many of the wells in the basin are completed in only one formation, with two wells on each pad; each well is completed in one of the formations. A number of the wells in the basin are completed in both formations and have commingled production. Pressure drawdown is critical in coalbed methane production, particularly in wells with large commingled perforation intervals; this is accomplished by lowering the gathering pressures and lowering the annular producing gas-water interface (fluid level) of the wells down below the perforation intervals. Pioneer uses acoustic measurement tools to determine the fluid level in the majority of the wells. However, in some of the wells, particularly the commingled wells, the acoustic tool is unable to measure the fluid level. A different method to determine the fluid level is to measure the bottom hole pressure and calculate the fluid level using a downhole pressure gauge. To test pressure gauges in the Raton basin, three wells with large perforation intervals were chosen for a pilot test. Pioneer also chose three companies with different components for comparison. The system was designed to be durable and mobile; it was also designed to connect to the existing production monitoring system. The installations for the three wells were successful, though, there were two gauge failures and several pump failures. After the failures were analyzed, and the production of the wells had stabilized with the fluid below the perforations, two of the gauges were moved to other wells. The intermittent acoustic measurements were compared with the pressure gauge information and the two tracked closely; this increased the confidence in the acoustic measurements when values can be obtained. Several of the goals of the pilot project were achieved, including developing the successful system as planned and obtaining reliable bottom hole pressures. There were additional unexpected results from the project; the failure analysis of the pumps lead to a solution for pump problems in the field, and the results provided Pioneer with a visual training tool for the field employees. It is too early to determine if the gauges could be used to more efficiently manage the commingled wells in the field, but a larger dataset of wells may improve the understanding.
- North America > United States > Colorado (1.00)
- North America > United States > New Mexico > Colfax County (0.83)
- North America > United States > New Mexico > Raton Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Bell Field (0.97)
Monitoring Reservoir Performance in Highly Prolific Deepwater Gulf of Mexico Gas Wells
Chu, Wei-Chun (Pioneer Natural Resources) | Gray, W. M. (Pioneer Natural Resources)
Abstract The deepwater Gulf of Mexico contains numerous gas fields with highly prolific wells that have the potential to deliver exceptional profitability to an Operator. This paper presents a case history of the utilization of real-time well surveillance data to assess well performance, reservoir drive mechanism, and original gas-in-place ("OGIP") in a small discovery. The significant implications for in-depth production data analysis, material balance applications, and dynamic reservoir modeling techniques are also emphasized. Interpretation of discovery well flow performance established the flow potential of a prolific gas producer corresponding to its associated down-hole and surface conditions in what was originally thought to be a single well subsea tieback development. Indepth analysis of the initial pressure and production data offered an early estimate of OGIP providing indications of reservoir compartmentalization before the reservoir drive interpretation of OGIP for the field was fully understood and enabled monitoring of aquifer invasion. Accurate, continuous surface and down-hole surveillance facilitated interpretation of reservoir depletion and in conjunction with sequential, unscheduled shut-ins during the production life of this subsea tieback, the true geometry of the structure was revealed and the impact of aquifer encroachment was quantified.
Real Time Proactive Optimal Well Placement using Geosignal and Deep Images
Bittar, Michael S. (Halliburton Energy Services Group) | Chemali, Roland E. (Halliburton Sperry Drilling Services) | Pitcher, Jason L. (Halliburton Energy Services Group) | Cook, Robert (Pioneer Natural Resources) | Knutson, Craig (Pioneer Natural Resources)
Abstract Modern oil field drilling operations through complex reservoirs can be extremely challenging because geological models are often limited to the resolution of seismic data. Often, these reservoirs have significant variations that cannot be fully anticipated before drilling. Efforts toward maximizing production from these complex reservoirs through optimal well placement require increasingly sophisticated geosteering and formation evaluation capabilities. Advances in directional logging-while-drilling (LWD) resistivity measurements improved real-time geosteering by providing discrete azimuthal measurements, deep images, and distance to the formations from above, below, and to the side of the sensor while drilling horizontally or at high-inclination angles through the reservoir. Distance-to-bed boundaries calculation is achieved by means of the geosignal, a new geosteering signal. Derived in real time, the geosignal is azimuthally sensitive and strongly dependent on the distances to boundaries. These novel measurements, combined with well steering software, enable geosteering engineers to steer the well not only on resistivity variations but also on direct deep resistivity images and on azimuthal geosignal. Boundaries are identified as they approach the well from above, below, and any direction around the sensor. A complete picture improves the understanding of the reservoir's geology and aids in placing the well in thin reservoirs. It also improves the capability of steering the well through the most productive part of the reservoir while maintaining a desired distance from adjacent formations. This paper describes the planning and execution of a typical well placement operation accomplished with this new technology. New interpretation methods specific to deep images are illustrated on real data and many examples are shown. The paper also provides details about the workflow of geosteering based on this new azimuthal deep-reading technology and discusses the benefits and limitations, lessons learned, pitfalls, and best practices. Finally, field examples from around the world are included to show the usefulness of this new technology for well placement and formation evaluation in various types of hydrocarbon reservoirs. Introduction The oil and gas exploration and production industry is increasingly migrating to high-angle wells, especially in offshore operations. The partial departure from vertical wells began in the 1980s and has accelerated in recent years because the technological advances have made it easier and less risky to drill extended reach wells in many types of reservoirs. There are multiple advantages of high-angle wells and horizontal wells. A horizontal well generally yields the same initial production as that of several vertical wells combined, which significantly reduces the surface infrastructure requirements. In an offshore field development, a single platform can launch multiple high-angle wells in many directions, covering vast areas that would otherwise require multiple platforms with vertical wells. During the life of the field, if properly placed, horizontal wells enable a more efficient sweep of the producible hydrocarbon than vertical wells, leading to higher volumes of ultimate oil and gas recovery. In addition to cost savings and increased revenue, horizontal wells offer a reduced footprint for a given hydrocarbon production, significantly reducing the effect on the environment.
- Europe > Norway (0.68)
- North America > United States > Texas (0.68)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.47)
- Europe > Norway > North Sea > PL 169 > Block 25/8 > Breidablikk Field > Statfjord Formation (0.99)
- Europe > Norway > North Sea > PL 169 > Block 25/8 > Breidablikk Field > Lista Formation (0.99)
- Europe > Norway > North Sea > PL 169 > Block 25/8 > Breidablikk Field > Hod Formation (0.99)
- (5 more...)
Advances in Geosteering Technology: From Simple to Complex Solutions
Pitcher, J.. (Halliburton) | Clegg, N.. (Halliburton) | Burinda, C.. (Halliburton) | Cook, R.. (Pioneer Natural Resources) | Knutson, C.. (Pioneer Natural Resources) | Scott, M.. (StatoilHydro) | Lรธseth, T.. (StatoilHydro)
Abstract The industry today is challenged to maximize recovery from existing assets, requiring increasingly complex and challenging reservoirs to be drilled and geosteered. Consequently, reservoir management efforts aimed at maximizing production through optimal wellbore placement require increasingly sophisticated geosteering capabilities. In geologically simple reservoirs, conventional geosteering techniques use simple logging-while-drilling (LWD) sensors to help wellsite geologists place wells in the optimal productive zones. As geological complexity increases, more sophisticated techniques and tools are required to assist a team effort in placing the well. These tools and techniques require the integration of structure maps, LWD measurements and interpretation, and wellbore survey information to determine the location of the wellbore within the reservoir and the structure of the reservoir. This analysis then leads to the decision process about where to steer the well to meet the required objectives. This paper discusses the use of an advanced geosteering system that uses all available geosteering technology, from the simple systems to the advanced sensors, in complex reservoir situations. The planning and execution of well placement jobs performed with this technology in several diverse reservoirs are explained. This paper also provides details about simple geosteering systems through advanced well placement techniques, based on the latest LWD technology, as well as lessons learned, pitfalls to avoid, and best practices and challenges in using these systems. Field examples are included to demonstrate the application of this technology for well placement.
- Geology > Structural Geology (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (0.99)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.34)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field > Kuparuk Field > Kuparuk Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 104 > Block 30/9 > Oseberg Field > Tarbert Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 104 > Block 30/9 > Oseberg Field > Oseberg Formation (0.99)
- (4 more...)
Abstract Characterizing reservoir architecture and fluid property distributions at the early exploration and appraisal stage are critical for reservoir assessment, planning and management. Particularly for thinly laminated reservoirs, identification of hydrocarbon-bearing zones and determination of the flow unit sizes have profound impact on long term production predictions. In this paper, a case study is presented that integration of reservoir fluid property distribution with other logs leads to accurate reservoir understanding. In this method, downhole fluid analysis (DFA) is used to identify key production parameters of reservoir fluids in real time and at downhole conditions. DFA results are combined with other logs to develop a view of reservoir architecture especially pinpointing thin pay zones with low resistivity, which could be treated as wet by open-hole logs. Indeed, 19 DFA stations were performed in this particular well and represents a typical number of DFA stations per well in this field (another well in this field had significantly more DFA stations that established a world record). The results of the improved interpretation are confirmed by subsequent well test data. The case study indicates that the methodology of integrating DFA with other logs provides a powerful and cost effective approach for reservoir understanding and assessment at the exploration stage, which is invaluable for optimal reservoir management and development planning. Introduction An accurate description of reservoir architecture and fluid properties at the early stage of exploration and development cycle is critically important for reservoir management. Particularly for thinly laminated reservoirs, volumetric and fluid properties of each pay zone may vary significantly. Additionally, lithology effects and highly saline formation water can cause suppression of resistivity log response, and as a result, hydrocarbon-bearing zones may not be identified with confidence from resistivity and CMR logs. Therefore, in thinly laminated and low resistivity reservoirs, an accurate view of each individual flow unit and its fluid properties is the key for drainage volume estimation, production strategy and prediction, as well as completion and surface facility designs. In this circumstance the only way to know what fluid will flow from each lamination is to flow and analyze the fluid from each lamination. Traditional drill stem tests (DST) and well tests have been used to determine formation permeability, detect compartmentalization and boundaries, as well as obtain representative formation fluid samples. However, in deepwater or other high cost wells, traditional DST's becomes extraordinary expensive and environmentally unfriendly. Furthermore, interpretation of traditional well test on highly laminated reservoir can be complicated due to commingled fluid flow from multi zones, especially when the primary goal is to characterize individual pay zones. Formation tester tools prove to be a reliable way of acquiring formation pressures and fluid samples. Particularly with introduction of the focused sampling technique, high quality representative fluid samples can be obtained with less time compared to conventional sampling probes (Dong et al., 2005; Del Campo et al., 2006; O'Keefe et al., 2006). Additionally, development of downhole fluid analysis (DFA) enables formation tester tools to analyze reservoir fluid properties in real time, at downhole conditions and without the need of acquiring fluid samples. DFA provides the capability of scanning reservoir fluids and unveiling fluid property distributions at an unlimited number of station depths. Additionally, a fluid prediction model has been developed to facilitate using fluid property distributions to better understand reservoir architecture and fluid equilibrium. Furthermore, formation tester tools can conduct Interval Pressure Transient Tests (IPTT), also referred as Vertical Interference Tests (VIT) or mini-DST. The IPTT with formation tester tools is similar to traditional DST's in principle but with a smaller investigation depth at tens of feet; by this means permeabilities of individual layers can be obtained (Elshahawi et al., 2008).
- Asia (0.94)
- North America > United States > Texas (0.47)
- Geology > Geological Subdiscipline (0.69)
- Geology > Rock Type (0.50)
A Case Study Examining a Cost Effective Gel System for Water Shutoff in a Low-Pressure Layer
Major, Chad Russell (Pioneer Natural Resources) | Hines, Don Nicholas (Pioneer Natural Resources) | Gould, John H. (Gel Technologies Corp.) | Pender, Dan B. (Gel Technologies Corp.)
Abstract An innovative system consisting of three different Chromium Carboxylate Acrylamide Polymer (CCAP) gels is being used in place of conventional cement squeezes in the Upper Spraberry formation located in West Texas. The application of the CCAP gel to shut off water production by abandoning the Upper Spraberry formation has resulted in increased oil production, lower workover costs and reduced lease operating expense (LOE) in the majority of the wells that have been treated to date. A typical Spraberry Trend Area well consists of the Upper and Lower Spraberry and Dean formations. After fracture stimulation, the intervals are produced by beam pump. Reservoir characteristics and the completion configuration cause the Upper Spraberry formation to be more susceptible to water encroachment. Because the Upper Spraberry has low reservoir pressure, conventional squeeze cementing is difficult. The hydrostatic pressure resulting from a column of cement will further breakdown the formation requiring high cement volumes and/or multiple squeeze attempts in order to successfully shut off the interval. As an alternative to conventional cement squeezes, gel treatments with volumes between 700 and 1,000 barrels using three different gel systems are used to successfully shut off the Upper Spraberry formation. One hundred eight wells have been treated to date. Many of the wells initially treated in 2003 are still benefiting from the gel treatment, maintaining oil production with lower water/oil ratios. Gel treatments have been successful in increasing or restoring oil production, and reducing operating expense and workover cost. Increases in gel treatment cost have been minimal over the years compared to that of cement. The gel treatments have proven to be a cost-effective, long-term alternative for conventional cement squeezes. Introduction The Spraberry Trend in West Texas was discovered in 1948 and has since been significantly developed. A typical completion includes the Upper and Lower Spraberry formations and the Dean formation. The reservoir characteristics and completion configuration cause the Upper Spraberry to water out, requiring a shutoff treatment. As it is a low pressure formation, cement squeezing is difficult, with high cement volumes and/or multiple squeezes to achieve shut-off. Chromium Carboxylate Acrylamide Polymer (CCAP) gels have been used as a cost-effective substitute for cement squeezes resulting in reduced WOR's, reduced cost and increased oil production in the treated wells. Field Description The productive area within the Spraberry Trend Field covers over 2,500 square miles (6,475 sq. km.) of the Midland Basin of west Texas (Figure 1). The original gross interval ranges from 1000 to 1500 feet of Permian-aged formations comprised of submarine fans and basin plane deposits with interbedding of shale, sandstone, siltstone, and limestone.
- North America > United States > Texas > Midland County (1.00)
- North America > United States > Texas > Martin County (1.00)
- North America > United States > Texas > Howard County (1.00)
- North America > United States > Texas > Dawson County (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (31 more...)
Predicting Undulating-Well Performance
Kamkom, Rungtip (Texas A&M University) | Zhu, Ding (Texas A&M University) | Bond, Andrew J. (Pioneer Natural Resources)
Summary Undulating wells are one of the alternatives to horizontal wells in field developments for extremely low-vertical-permeability formations. Undulating wells offer higher reservoir exposure, and they do not depend on vertical permeability as much as horizontal wells do. This makes an undulating well trajectory sometimes more attractive than horizontal wells. In this paper, we will present two different approaches to predicting undulating-well performance:an analytical model that uses a segmented vertical-well model with a slanted skin factor to account for the effect of undulation and a more-comprehensive model that evaluates undulating-well performance in a parallelepiped reservoir on the basis of a line-source solution. The analytical model is simple and works well under certain formation- and well-structure conditions. The line-source model is more flexible on permeability assumptions and well location. We compared the results of the two approaches to identify the conditions in which the analytical model can be applied. Field examples are used in the paper to illustrate optimizing undulating-well performance by the model. The Cosmopolitan field, Cook Inlet Alaska, and the Oooguruk field, North Slope, Alaska, are planned for development with undulating horizontal wells. Both reservoirs are challenged with relatively low permeability, low kV / kH ratios, and moderate-viscosity oil. Undulating horizontal wells are needed to overcome these issues and deliver commercial production rates. The performance model developed in this study demonstrated the additional value of an undulating well over a conventional horizontal well, which provided key support in the well-design and field-development plans. Introduction Undulating wells are wells that are not perfectly horizontal. Wells with a certain degree of undulation sometimes are used instead of horizontal wells in reservoir development to overcome limitations of horizontal wells. For example, when the vertical permeability of a formation is too low for horizontal wells to be attractive economically, undulating wells reduce the dependency on vertical permeability and become an alternative to produce from low-vertical-permeability formations. Moreover, undulating wells increase reservoir-exposure area and, therefore, improve well productivity. The main purpose of designing undulating wells is to increase the well productivity by minimizing the dependence on vertical permeability and/or increasing the reservoir-exposure area. We can divide undulating wells into two main categories: unintentionally undulating and intentionally undulating. Usually, unintentional undulation occurs because of drilling control or formation structure. In general, the unintentional undulating wells have various inclined angles. On the other hand, the intentional undulating wells have more controllable inclination angles and wellbore trajectory because the wellbore trajectory is designed to improve well performance Although undulating wells can increase well productivity, the advantages of undulating wells are not always guaranteed, especially for two-phase-flow wells, because of the complexity of wellbore structures and formation properties. The well performance and wellbore flow should be studied carefully when designing undulating wells. In this paper, we present two models to predict undulating-well performance by applying (1) an analytical solution or (2) a 2D line-source solution. The models can be applied for homogeneous and anisotropic formations. The line-source solution is compared with the analytical model, and the conditions for each model are identified. We will also discuss the wellbore potential and the effect of well trajectories on the well performance.
- North America > United States > Texas (1.00)
- North America > United States > Alaska > Kenai Peninsula Borough > Cook Inlet (0.34)
- North America > United States > Alaska > North Slope Borough > Beaufort Sea (0.25)
- Asia > Middle East > Qatar > Arabian Gulf (0.24)
- North America > United States > Alaska > North Slope Basin > Oooguruk Field > Kuparuk Formation > Nuiqsut Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Oooguruk Field > Kuparuk Formation > Kuparuk C Formation (0.99)
- North America > United States > Alaska > Cook Inlet Basin > Cosmopolitan Field (0.99)
Characterization of the Sligo (Lower Cretaceous - Aptian) Platform Margin In South Texas: Understanding Facies Distributions Using 3D Seismic And Modern Analogs
Modica, Christopher J. (Pioneer Natural Resources) | Katz, David J. (Pioneer Natural Resources)
Summary: The Sligo platform margin in South Texas was a dominantly aggradational barrier reef type margin. As a result, facies belts tend to be fairly narrow in a depositional dip direction and fairly extensive, but not necessarily continuous, along depositional strike. Historical production information fails to demonstrate a correlation between net pay thickness from wire line logs and ultimately recovered hydrocarbon volumes. These data defy the common assumption, virtually taken for granted in most cases, that more log pay in a given wellbore predicts more reserves, or can fairly be said to predict well performance at all. To explain this, we propose a complex, non-layered reservoir model that may have resulted from eustatic sea level fall, subaerial exposure, and karstification of the Sligo platform margin along the lines of the island karst model (Mylroie and Carew, 1995) Introduction: The Sligo Formation is contemporaneous with an expansive series of carbonate platforms that framed the ancestral Gulf of Mexico during the late Barremian and early Aptian. Contemporaneous platforms include the Yucatan Platform and the prolific Golden Lane Platform in Mexico. In South Texas, our study area, the platform was a broad reef-rimmed shelf. The primary reef building organisms during the Barremian and Aptian were thick-walled recumbent caprinid rudists. Coral co tended to be smallish and were secondary constituents. B and frame-building organisms such as skeletal algaes and stromatoporoids likely played an important role but seem to have been largely restricted to somewhat deeper and lower energy outer reef or reef wall settings, and are rarely captured in cores (cf. Kirkland et al., 1987). The Sligo platform was ultimately drowned in the Aptian and is overlain by marine shale (Pearsall/Pine Island Fm.). The drowning event coincides with OAE I (Oceanic Anoxic Event #1) of Arthur and Shlanger (1979). Drowning related to sea level rise and encroachme basinal oxygen-minimum zone onto the platform is further supported by a rudist extinction event (Steuber and Loser, 2000) and a radiogenic Strontium depletion episode (Lehmann et al., 2000). The shift in isotope ratio was the result of accelerated rates of seafloor spreading and thermal subsidence. These data suggest that the Sligo/Pearsall boundary represents a relatively rapid drowning surface rather than a transgressive surface where we might have expected more gradational backstepping facies relationships. The Sligo reef play in South Texas was "hot" in the 1980s and most existing wells in the trend were drilled during this decade. At this time the play was dependent on very limited well control and primarily driven with 2D seismic data. Success rates were less than 50%, repeatability was not achieved, and the play lost favor. Part of the reason, asid from geotechnical considerations, was probably to do with natural gas price regimes that were much weaker than we currently enjoy. There have been only a very few wells drilled since that time, and only these few had the benefi relatively modern 3D seismic data.
- North America > United States > Texas > Live Oak County (0.16)
- North America > United States > Texas > Bee County (0.16)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous > Barremian (0.75)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous > Aptian (0.54)
- Geology > Geological Subdiscipline (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Reef Environment (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.56)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Pawnee Field (0.99)
- North America > United States > Texas > Sligo Field > Sligo Formation (0.99)
- North America > United States > Louisiana > Sligo Field > Sligo Formation (0.99)
- (2 more...)
Identification of Bypassed Pays in Low-Resistivity, Thinly-Bedded, Sand-Shale Sequences in the Ghdames Basin of North Africa through Use of the Wireline Formation Tester
Chu, Wei-Chun (Pioneer Natural Resources) | Welch, Paul M. (Pioneer Natural Resources)
Abstract This paper presents a discussion on the use of the Wireline Formation Tester (WFT) to identify oil-bearing intervals in a reservoir section that contains thinly-laminated, low-resistivity pay sections in the Ghadames Basin of southern Tunisia. Pay zones previously bypassed by conventional log analysis have been conclusively determined as oilbearing through use of the tool. Three field examples are discussed on the use of the Downhole Fluid Analyzer (DFA) to determine hydrocarbon type and in-situ GOR for three different hydrocarbon phase environments. The paper also discusses, again through use of field examples, how analysis of the post-DFA pressure response could be used to determine zonal producibility. This zonal producibility from the WFT is then compared to conventional well-test productivity. A close agreement exists between the WFT and conventional well-test productivity estimates. Thus, it eliminates the need for zones to be conventionally tested to determine productivity. Finally, the paper provides a method to significantly reduce the time necessary to collect representative fluid samples through proper monitoring of the DFA data stream. Introduction Oil production has been established from several sand bodies within the Silurian Acacus formation in the Ghadames Basin of southern Tunisia (Figure 1). This production comes from a thinly-laminated, sand-shale section with highly variable quality and petrophysical response, including sandstones with very low values of resistivity and induction from the open-hole logs. As a result, most hydrocarbon-bearing intervals appear to be water-bearing by conventional log analysis and in the past bypassed and considered wet. This phenomenon exists in these Acacus sandstones, due to the presence of large amounts of capillary bound water and conductive minerals such as chlorite. To conclusively determine which intervals are hydrocarbonbearing, a modular wireline formation tester (WFT) equipped with a single-probe module is used during openhole logging. The WFT identifies in-situ reservoir fluid types using a downhole fluid analyzer (DFA) and determines the GOR by measuring the methane content of the fluid. A multiple sampling module or large sample chamber is then used to collect downhole fluid samples to confirm fluid types and GORs. After identifying hydrocarbon-bearing intervals using the DFA, without the guidance of conventional log analysis, producibility of each potential pay section is calculated from a single pressure buildup following a controlled pumping period. By monitoring both fluid optical density (Crombie et al, 1998) and GOR in pay intervals of these laminated Acacus sandstones, a completion program is designed to group intervals according to GOR and water-oil ratio behind separate sliding sleeves to control production.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.61)
- Africa > Middle East > Tunisia > Berkine Basin (Trias/Ghadames Basin) (0.99)
- Africa > Middle East > Libya > Berkine Basin (Trias/Ghadames Basin) (0.99)
- Africa > Middle East > Algeria > Berkine Basin (Trias/Ghadames Basin) (0.99)