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Collaborating Authors
Nuevo Leon
Challenges and Practices for Recovering Stuck Coiled Tubing Pipe
Hassig Fonseca, S. (SLB (Corresponding author)) | Torres, R. (SLB) | Liu, Z. (SLB) | Jahn, F. (SLB) | Tagarot, G. (SLB) | Baca, S. (SLB) | Guevara, H. (SLB) | Botan, J. (SLB) | Villacres, C. (SLB) | Boas, J. (SLB)
Summary Stuck coiled tubing (CT) is a main operational risk leading to delays, deferred production, or even the loss of a well. Despite general commonalities, each CT recovery can face unique challenges, including managing high pressure, working under limited spatial or lifting constraints, establishing well control, or handling a cable inside the CT. This study consolidates learnings and proposes a general workflow for a basic stuck pipe scenario, rig up, recovery pressure control equipment (RPCE) and well control, CT free point evaluation, bottomhole assemblies (BHAs) and workflows for cutting and freeing the CT pipe downhole, and recovery of the CT at the surface. A consolidation of published case studies provides specific examples of the hardware, workflows, and operational considerations. In addition, the presentation of a recent case study extends the discussion to the challenges introduced by the presence of a cable in the stuck CT and its respective solution. The case study reviews the planning and execution of a CT recovery, including the use of decision trees to guide the decision-making process. It details fit-for-purpose hardware for safely anchoring the cable; packoffs for accessing, tensioning, and recovering it with slickline (SLK); an opening for deploying the wireline (WL) cutting BHA; and valves for pressure testing and well control. That workflow successfully freed 6,818 ft of stuck CT and allowed recovery of the pipe without a workover rig on location, eliminating 11 days of rig time during subsequent tubing pulling. This is the first such documented recovery case worldwide based on a thorough literature review.
- Asia > Middle East (1.00)
- North America > United States > Texas (0.47)
- North America > United States > Mississippi > Mallalieu Field (0.89)
- North America > Mexico > Tamaulipas > Burgos Basin > Burgos Field (0.89)
- North America > Mexico > Nuevo Leon > Burgos Basin > Burgos Field (0.89)
- North America > Mexico > Coahuila > Burgos Basin > Burgos Field (0.89)
ABSTRACT The Port Isabel passive margin foldbelt covers 17,000ย km of the northwestern deepwater U.S. Gulf of Mexico. Seven oil exploration wells have been drilled in the area from 1996 to 2007, yielding a single uncommercial gas discovery. The 5โ7ย km thick Oligo-Miocene section prevents drilling from penetrating the underlying Paleogene and Mesozoic source rocks. Accommodation space for the Oligo-Miocene section is created by the collapse of a paleo-salt wall, leading to linked fault systems in the upper decollement to the east. We use 13 exploration wells to construct 1D and map-based 2D basin models to investigate the burial and thermal history of three inferred source rock horizons (Paleogene, Turonian, and Tithonian). We interpret a 2D seismic data grid tied to four wells to constrain stratigraphic depths and thicknesses of the younger and shallower Wilcox source rock horizons, and the Jurassic and Cretaceous source rock horizons. Our results indicate that vitrinite reflectance is a proxy for the thermal stress levels reached by the source rocks as supported by maps of hydrocarbon charge access. We conclude that all three source rock intervals have reached varying degrees of maturity, expelled hydrocarbons in late Paleogene to mid-Neogene, and likely continue expelling hydrocarbons to the present-day at a reduced rate. The deposition of the Oligocene and Middle Miocene sedimentary section has buried the underlying source intervals and likely brought them into the gas/condensate window in the present-day. Our mapping of the extensive seismic reflection grid reveals four-way structural closures, three-way stratigraphic traps, and salt truncation structures associated with amplitude anomalies which may support our predictions for maturity in the underlying source rocks. Our thermal stress maps predict that the modeled source rocks are mature and our charge access models for the available wells constrain migration patterns, although the timing of the early hydrocarbon charge and late trap formation remain significant risk factors.
- North America > United States > Texas (1.00)
- North America > Mexico (1.00)
- North America > United States > Gulf of Mexico > Western GOM (0.86)
- Phanerozoic > Cenozoic > Paleogene > Oligocene (1.00)
- Phanerozoic > Cenozoic > Neogene > Miocene (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (1.00)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.94)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (21 more...)
ABSTRACT The Port Isabel passive margin foldbelt covers 17,000ย km of the northwestern deepwater U.S. Gulf of Mexico. Seven oil exploration wells have been drilled in the area from 1996 to 2007, yielding a single uncommercial gas discovery. The 5โ7ย km thick Oligo-Miocene section prevents drilling from penetrating the underlying Paleogene and Mesozoic source rocks. Accommodation space for the Oligo-Miocene section is created by the collapse of a paleo-salt wall, leading to linked fault systems in the upper decollement to the east. We use 13 exploration wells to construct 1D and map-based 2D basin models to investigate the burial and thermal history of three inferred source rock horizons (Paleogene, Turonian, and Tithonian). We interpret a 2D seismic data grid tied to four wells to constrain stratigraphic depths and thicknesses of the younger and shallower Wilcox source rock horizons, and the Jurassic and Cretaceous source rock horizons. Our results indicate that vitrinite reflectance is a proxy for the thermal stress levels reached by the source rocks as supported by maps of hydrocarbon charge access. We conclude that all three source rock intervals have reached varying degrees of maturity, expelled hydrocarbons in late Paleogene to mid-Neogene, and likely continue expelling hydrocarbons to the present-day at a reduced rate. The deposition of the Oligocene and Middle Miocene sedimentary section has buried the underlying source intervals and likely brought them into the gas/condensate window in the present-day. Our mapping of the extensive seismic reflection grid reveals four-way structural closures, three-way stratigraphic traps, and salt truncation structures associated with amplitude anomalies which may support our predictions for maturity in the underlying source rocks. Our thermal stress maps predict that the modeled source rocks are mature and our charge access models for the available wells constrain migration patterns, although the timing of the early hydrocarbon charge and late trap formation remain significant risk factors.
- North America > United States > Texas (1.00)
- North America > Mexico (1.00)
- North America > United States > Gulf of Mexico > Western GOM (0.86)
- Phanerozoic > Cenozoic > Paleogene > Oligocene (1.00)
- Phanerozoic > Cenozoic > Neogene > Miocene (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (1.00)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.94)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (21 more...)
Evaluation of CO2 and Slickwater Fracturing for the Burgos Basin of Mexico
Silva-Escalante, C. F. (National Autonomous University of Mexico, UNAM, Mexico City, Mexico) | Camacho-Velazquez, R. G. (National Autonomous University of Mexico, UNAM, Mexico City, Mexico) | Gรณmora-Figueroa, A. P. (National Autonomous University of Mexico, UNAM, Mexico City, Mexico) | Sharma, Mukul M. (University of Texas at Austin, Austin, Texas, United States of America.)
Abstract This work aims to evaluate the fracture geometry and production scenarios comparing several fracturing fluids, such as slickwater and carbon-based fracturing fluids (CBFF), including two binary mixtures as approximations to anthropogenic CO2 resulting from carbon capture (oxyfuel, pre-combustion, and post-combustion). Reservoir flow modeling simulations show that CBFF is the best potential waterless fracturing fluid option for fracturing unconventional shale reservoirs in the Burgos Basin. We conducted fracturing simulations to obtain the fracture geometry resulting from pure CO2, gelled CO2, foamed CO2, as well as the binary mixtures CO2 (95% mol)-N2 (5% mol), and CO2 (95% mol)-H2 (5% mol) and compared the results to conventional slickwater fracturing. Data and information for this study come from a gas well in the Burgos Basin in Mexico. A compositional fracturing simulation model is used to obtain the fracture geometry and the conditions under which the CO2 fracturing would be optimal based on a sensitivity analysis of the critical parameters described in this work. We created a reservoir simulation model to generate production scenarios and compare the well performance of wells fractured with pure CO2 and slickwater. The impact of water blockage effects on well productivity is shown to be important. Results show that pure CO2, CO2-N2, and CO2-H2 create fracture geometries that are similar to slickwater fracturing. Pure CO2 provides the highest production due to the absence of water blockage effects. Other carbon-based fracturing fluids also represent an opportunity for implementing CO2 to optimize well performance reducing water blockage and water consumption for sustainably fracturing conventional and unconventional reservoirs.
- North America > United States > Texas (1.00)
- North America > Mexico > Tamaulipas (0.81)
- North America > Mexico > Nuevo Leรณn (0.81)
- North America > Mexico > Coahuila (0.81)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.72)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (10 more...)
First Industrial High-Power Laser Perforation Deployment
Batarseh, Sameeh I. (EXPEC Advanced Research Center, Aramco, Dhahran, Saudi Arabia) | Alerigi, Damian P. San Roman (EXPEC Advanced Research Center, Aramco, Dhahran, Saudi Arabia) | Marshall, Scott (Foro Energy Inc., Houston, TX, United States of America) | Graves, Ramona (Colorado School of Mines, Golden, CO, United States of America)
Abstract This paper presents the industry's first high-power laser field perforation and deploymentโa successful high-power laser technology application. The innovative technology could perforate a well without affecting the substrate integrity and damage. The technology is safe, efficient, and cost-effective, providing a long-term alternative to shaped charge guns. High-power laser technology has been tested and proven to effectively perforate in all rocks, regardless of strength and composition, including carbonate, shale, sandstones, and others. The success of the past two decades of intensive research has led to the development of the first high-power laser field system. The system's design is enclosed, providing safe and environmentally friendly operation; it consists of a laser energy generator, nitrogen tank, coiled tubing, and tool. The device's function is to control the size and shape of the beam that focuses on the targeted formation. The perforation process is done by utilizing the power of a laser to melt, spall, or vaporize the formation. The laser perforation tool can perforate through the casing, cementing into the formation. The technology was deployed in a cased well. The well is logged pre- and post-laser perforation, and the coiled tubing is used to connect the fiber optics cable with the optical bottom hole assembly (oBHA). The tool can perform multiple perforations in a single trip, with the azimuthal orientation controlled by rotating the head of the device. Laser perforation creates a nondamaging controlled perforation tunnel penetrating casing, cement, and formation, and it is stress independent.
- North America > United States > Texas (0.28)
- Asia > Middle East > Saudi Arabia (0.28)
- North America > Mexico > Tamaulipas > Burgos Basin (0.99)
- North America > Mexico > Nuevo Leon > Burgos Basin (0.99)
- North America > Mexico > Coahuila > Burgos Basin (0.99)
Tackling Breakdown and Proppant Placement Issues in a Deep, High-Pressure/High-Temperature Volcanic Reservoir: Lessons Learned Through Multistage Fracturing Campaigns in Minami-Nagaoka Gas Field, Japan
Kidogawa, Ryosuke (INPEX Corporation, Tokyo, Japan) | Yoshida, Nozomu (INPEX Corporation, Tokyo, Japan) | Kaneko, Masayuki (INPEX Corporation, Tokyo, Japan) | Takatsu, Kyoichi (INPEX Corporation, Tokyo, Japan) | Kubota, Ayumi (INPEX Corporation, Tokyo, Japan) | Boucher, Andrew (Fenix Consulting Delft BV, Delft, The Netherlands) | Shaoul, Josef (Fenix Consulting Delft BV, Delft, The Netherlands) | Tkachuk, Inna (Fenix Consulting Delft BV, Delft, The Netherlands) | Spitzer, Winston J. (Fenix Consulting Delft BV, Delft, The Netherlands) | De Pater, Hans (Fenix Consulting Delft BV, Delft, The Netherlands)
Abstract Fracturing treatments are often challenging in high-pressure/high-temperature, tectonically stressed areas with heterogeneous and complex lithology. This study presents case histories of two multistage fracturing campaigns executed on a tight gas formation in a deep volcanic reservoir onshore Japan. This work begins by highlighting the technical difficulties experienced during the first campaign, reviews the countermeasures developed over the course of the decade between campaigns, and finishes lessons learned from execution and evaluation of the second campaign. A root-cause analysis was undertaken to understand the poor treatment results from the first campaign where stages were defined by no formation breakdown, poor injectivity or early screen-out. It included re-evaluation of core/petrophysical interpretation, stress model and net pressure history matching, and development of injectivity index diagnostic plots. The findings were used to identify updated technologies and workflows for the second campaign with consideration of limitations in the target well drilled +10 years before and uncompleted. Finally, details of field execution and post-job logging results are presented to verify effectiveness of proposed techniques and extract lessons learned for future operations. The breakdown and injectivity issues of the first campaign appear to be tied to the initiation interval location and facies, where initiating in a massive lava facies was most problematic due to high stress and extreme tortuosity. Uncertainty in the propped height from the net pressure history matches showed room for optimization in treatment design. In the second campaign, with mitigation plans for breakdown issues, premature screen-outs and detection of propped height in place, nine fracture stages were attempted. Eight stages achieved successful breakdown with careful target selection and weighted brine. Two conventional treatments with crosslinked gel were placed in the intervals with high injectivity and, as a field trial, two slickwater treatments with high viscosity friction reducer were placed in intervals to deal with low injectivity. Issues with high apparent net pressure due to tortuosity continued, comparable to the first well, and efforts to further reduce treating pressure for future campaigns continues. Logging of the non-radioactive traceable proppant pumped revealed thin propped heights while production logging showed contribution from the zones treated with slickwater indicating it may be a viable solution for this type of challenging reservoir. This work highlights a series of technical issues and possible solutions of multistage fracturing in a volcanic reservoir, validated through field execution. Proposed solutions partially solved the challenges, but at the same time they open further questions for future campaigns. This study can serve as a reference for fracturing operations in challenging analogue reservoirs.
- North America > United States > Texas (1.00)
- Asia > Japan > Chลซbu > Niigata Prefecture (0.40)
- Overview (0.46)
- Research Report > New Finding (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Volcanology (0.91)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.46)
- North America > United States > Texas > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- North America > United States > Louisiana > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- North America > United States > Arkansas > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- (9 more...)
The Port Isabel passive margin foldbelt covers 17,000 km2 of the northwestern, deepwater U.S. Gulf of Mexico (GOM). Seven oil exploration wells were drilled in the area from 1996 to 2007, yielding a single, uncommercial gas discovery. The 5-7 km thick Oligo-Miocene section prevented drilling from penetrating the underlying Paleogene and Mesozoic source rocks. Accommodation space for the Oligo-Miocene section was created by the collapse of a paleo-salt wall, leading to linked fault systems in the upper decollement to the west. We used 13 exploration wells to construct 1D and map-based 2D basin models to investigate the burial and thermal history of three inferred source rock horizons (Paleogene, Turonian, and Tithonian). We interpreted a 2D seismic data grid tied to four wells to constrain stratigraphic depths and thicknesses, younger and shallower Wilcox source rock horizons, and interpreted Jurassic and Cretaceous source rock horizons. Our results show vitrinite reflectance as a proxy for the thermal stress levels reached by the source rocks combined with maps of hydrocarbon charge access. We conclude that all three source rock intervals reached varying degrees of maturity and expelled hydrocarbons in late Paleogene to mid-Neogene and likely continue expelling hydrocarbons to the present-day at a reduced rate. The deposition of the Oligocene and Middle Miocene sedimentary section buried the underlying source intervals and likely brought them into the gas/condensate window at present-day. Our mapping of the seismic grid revealed four-way structural closures, three-way stratigraphic traps, and salt truncation structures associated with amplitude anomalies which may support our predictions for maturity in the underlying source rocks. Thermal stress maps predict source rocks have matured. There arises a need to investigate the hydrocarbon migration model, including assessing charge access for each well. The timing of late trap formation and early hydrocarbon charge remains a risk factor.
- North America > United States > Texas (1.00)
- North America > Mexico (1.00)
- North America > United States > Gulf of Mexico > Western GOM (0.85)
- Phanerozoic > Cenozoic > Paleogene (1.00)
- Phanerozoic > Cenozoic > Neogene > Miocene (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (1.00)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.68)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.68)
- Geophysics > Seismic Surveying > Seismic Processing (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (22 more...)
Utilizing Geochemical, Petrophysical, and Geomechanical Analysis to Optimize Stimulation Design in Pimienta Formation
Betancourt, Douglas J. (Central University of Venezuela) | Rabe, Claudio (Baker Hughes) | Iqbal, Omer (Arizona State University) | Salazar, Jesus P. (Baker Hughes) | Hoxha, Besmir (Baker Hughes)
Abstract Shale plays have become even more important as governments are encouraging domestic production in order to increase energy security. However, these plays are complex and require detailed characterization to design a optimum production strategy. For example, designing an appropriate stimulation program requires a detailed rock elastic, porosity, permeability, brittleness, TOC evaluation, sealing/fault proximity evaluation, natural fracture characterization (Salazar et al, 2022; Salazar et al., 2021; Rabe et al., 2021; Salazar et al., 2017). To achieve this goal, the reservoir characterization must include proppant type and concentration, the injection rate and treatment size, horizontal spacing optimization, and well trajectory design. This paper presents a case study of an integrated characterization of the productivity potential of light crude oil in the carbonate-shale of the Pimienta formation in the Titoniense Upper Jurassic layer. The study involved extensive laboratory tests, logs, and field measurements to characterize the reservoir and to outline a suitable hydraulic fracturing design. The reservoir characterization included lithofacies and pore classification using X-ray Diffraction, Scanning Electron Microscopy and thin sections. The petrophysical model included the facies model, porosity, water saturation and permeability analysis. Geochemical analysis included vitrinite reflectance, thermal maturity analysis, total organic content (TOC) and the hydrogen index. The rock physics and geomechanical analysis included brittleness analysis, Poissonโs Ratio, Youngโs Modulus, acoustic impedance analysis, and rock strength. The results indicated an expected TOC of approximately 2.3%, type II, with a thermal maturity ranging between 0.85 and 1.1%. The mineralogy analysis indicated that mudstone, wackestone and packstone constituted 72% of the carbonate and 11% of clay containing illite, montmorillonite, glauconite and kaolinite. Permeability in the reservoir ranged between 1,600 to 2,000 nD, with total porosity ranging between 5.2 and 9.6%, a median Youngโs Modulus of 40^106 Gpa and static Poissonโs Ratio around 0.25. The geochemical analysis indicated a kerogen type II to III (gas-to-oil prone). The results shows that the best interval for stimulation was located in the calcareous limestone facies composed predominantly of wackestone with high brittleness (67%) and fracability index.
- North America > United States (1.00)
- South America (0.94)
- North America > Mexico > Tamaulipas (0.29)
- Phanerozoic > Cenozoic > Paleogene (0.94)
- Phanerozoic > Mesozoic (0.89)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- (3 more...)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying (0.94)
- Oceania > New Zealand > North Island > East Coast Basin > Whangai Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > Mexico > Veracruz > Tampico-Misantla Basin (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Geochemical characterization (1.00)
Challenges and Best Practices for Recovering Stuck Coiled Tubing Pipe Conveying a Cable
Hassig Fonseca, Santiago (SLB) | Torres, Richard (SLB) | Liu, Zhanke (SLB) | Jahn, Felix (SLB) | Tagarot, Gary (SLB) | Baca, Santiago (SLB) | Guevara, Hugo (SLB) | Botan, Jacqueline (SLB) | Villacres, Cristina (SLB) | Boas, Jeanette (SLB)
Abstract Stuck coiled tubing (CT) is a main operational risk leading to delays, deferred production, or even loss of a well. Despite general commonalities, each CT recovery can face unique challenges including managing high pressure, working under limited spatial or lifting constraints, establishing well control, or handling a cable inside the CT. This study consolidates learnings and proposes a general workflow for a basic stuck pipe scenario, rig-up, recovery pressure control equipment and well control, CT free point evaluation, bottomhole assemblies (BHAs) and workflows for cutting and freeing the CT pipe downhole, and recovery of the CT at surface. A consolidation of published case studies provides specific examples of the hardware, workflows, and operational considerations. In addition, presentation of a recent case study extends the discussion to the challenges introduced by the presence of a cable in the stuck CT and its respective solution. This case study reviews the planning and execution of a CT recovery, including the use of decision trees to guide the decision-making process. It details fit-for-purpose hardware for safely anchoring the cable; packoffs for accessing, tensioning, and recovering it with slickline; an opening for deploying the wireline cutting BHA; and valves for pressure testing and well control. That workflow successfully freed 6,818 ft of stuck CT and allowed recovering the pipe without a workover rig on location, eliminating 11 days of rig time during subsequent tubing pulling. This is the first documented such recovery case worldwide based on a thorough literature review.
- North America > United States > Mississippi > Mallalieu Field (0.89)
- North America > Mexico > Tamaulipas > Burgos Basin > Burgos Field (0.89)
- North America > Mexico > Nuevo Leon > Burgos Basin > Burgos Field (0.89)
- North America > Mexico > Coahuila > Burgos Basin > Burgos Field (0.89)
A Method for Determination of Rock Fabric Number from Well Logs in Unconventional Tight Oil Carbonates
Azuara Diliegros, Brenda (Schulich School of Engineering, University of Calgary (Now with Pemex in Villahermosa, Tabasco, Mexico)) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary (Corresponding author))
Summary This paper develops a method for estimation of rock fabric number (RFN) from well logs in unconventional tight oil carbonates with permeability less than 0.1 md. The objective is to investigate the oil potential of a Middle Cretaceous tight carbonate in Mexico. The development of a method for these conditions is challenging as the current approach developed by Lucia (1983) has been explained for carbonates with permeability more than 0.1 md. Core data and drill cuttings available for this study are limited but provide important insights for the log interpretation and for identifying the presence of grainstone, packstone, and wackstone rocks in the unconventional tight carbonate under consideration. A crossplot of RFN vs. rp35 (pore throat radius at 35% cumulative pore volume) permits delimiting intervals with good production potential that are supported by well testing data. Information for the analysis of the Mexican carbonate comes from well logs of nine wells and two re-entry wells, four buildup tests, and a limited amount of core and drill cuttings information. All data were provided by a petroleum company and have been used, for transparency, without any modifications. An unconventional tight carbonate as defined in this paper has a permeability smaller than 0.1 md. The unconventional tight oil carbonate reservoir considered in this study includes 95% of data with permeabilities smaller than 0.1 md and only 5% with permeabilities larger than 0.1 md. The method introduced by Lucia (1983) and Jennings and Lucia (2003) for determining RFN is powerful, but they explained it only for permeabilities larger than 0.1 md, thus the need for a methodology that allows estimating from well logs the presence of grainstone, packstone, and/or wackstone in unconventional tight carbonate reservoirs with permeabilities smaller than 0.1 md. Results indicate that the RFN provides a useful approach for distinguishing grainstone, packstone, and wackstone rocks in unconventional tight carbonate reservoirs. Furthermore, rock fabric can be linked with Pickett plots to provide an integrated quantitative evaluation of RFN, porosity, water saturation, permeability, pore throat radius, and capillary pressure. This integration indicates that there is good oil potential in the Middle Cretaceous unconventional tight carbonate in Mexico.
- North America > Mexico (1.00)
- North America > United States (0.93)
- North America > Canada > Alberta (0.29)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous > Turonian (0.46)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous > Cenomanian (0.46)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous > Aptian (0.46)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous > Albian (0.46)
- North America > Mexico > Tamaulipas > Burgos Basin (0.98)
- North America > Mexico > Nuevo Leon > Burgos Basin (0.98)
- North America > Mexico > Coahuila > Burgos Basin (0.98)
- (17 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)