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BP
ABSTRACT Over the past few decades, distributed acoustic sensing (DAS) data acquisition has seen great improvements from better interrogators, engineered fiber, and lessons learned from subsea installation and acquisition. This has given us confidence that DAS cables can be installed in wells with subsea trees to be used as receivers for vertical seismic profile (VSP) seismic imaging. VSP imaging for deepwater fields has been demonstrated to provide better illumination and higher-frequency seismic data. Permanent DAS cable installation can be used to acquire highly repeatable time-lapse (4D) data. DAS cables have been installed in a number of subsea wells on two deepwater oil fields with the intention of covering the crest of these fields with high-frequency seismic data. A system has been developed to allow for DAS acquisition on these offshore subsea wells with long-distance tie backs using permanently installed interrogators on the floating platforms and engineered fiber in the wells. On each of these fields, a DAS cable has now been installed, and subsequently, a zero offset (ZO) DAS VSP has been acquired for verification and commissioning. These ZO DAS VSP acquisitions indicate high-fidelity installations resulting in DAS VSP data with excellent data quality. These first subsea DAS acquisitions indicate great promise, and further installations and acquisitions are planned with the ultimate goal of providing high-frequency seismic images over the crest of these fields to reduce the uncertainty in decisions around reservoir management and future infill drilling.
- Europe (1.00)
- North America > United States > Gulf of Mexico > Central GOM (0.96)
- North America > United States > Texas (0.68)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 882 > Thunder Horse South Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 822 > Thunder Horse Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 778 > Thunder Horse South Field (0.99)
- (18 more...)
Digital rock advances from a material point method approach for simulation of frame moduli and a sedimentary petrology-inspired method for creation of synthetic samples through simulation of deposition and diagenesis
Lander, Robert H. (Geocosm LLC) | Cook, Jennie E. (BP) | Guilkey, James (University of Utah) | Kerimov, Abdulla (BP) | Bonnell, Linda M. (Geocosm LLC) | Goodwin, Laurel B. (University of Wisconsin)
ABSTRACT We compare hydromechanical simulation results that use two alternative sources of 3D digital rock input: micro-CT analysis and โsynthetic rocksโ created by using a newly developed process simulation methodology that more rigorously reflects knowledge from sedimentary petrology compared with previous efforts. We evaluate the performance of these alternative representations using St. Peter Sandstone samples where โdryโ static bulk modulus (K) and shear modulus (G) are simulated using a new extension of the material point method that resolves contacts using high-resolution surface meshes and considers three alternative contact modeling approaches: โpurely frictional,โ โfully bonded,โ and โcohesive zones.โ We evaluate the model performance on two samples from the data set with multiple static moduli measurements (sample 1_2: porosity 24.6ย vol%, K 10.2โ14.7ย GPa, and G 11.6โ14.0ย GPa; sample 11_2: porosity 12.4ย vol%, K 13.5โ24.6ย GPa, and G 12.8โ17.9ย GPa). Purely frictional results underpredict measured modulus values, whereas fully bonded results overpredict them. Measured values are most closely approximated by results with cohesive zones that consider sets of discrete spring-like features at contacts. In contrast, shear modulus results from finite-element model simulations on structured grids tend to be significantly greater than measured values, particularly for samples with <18ย vol% porosity. Permeability values from digital rock-physics simulations for the studied samples are within factors of 2โ5 of conventional core analysis measurements (2860 and 58 mD for samples 1_2 and 11_2, respectively). We determine that the process modeling approach (1)ย accurately reproduces the measured rock microstructure parameters from thin-section analysis, (2)ย leads to simulation results for dry static moduli and permeability with accuracy comparable to simulations that use micro-CT samples, and (3)ย provides a rigorous basis for predicting diagenetically induced variations in hydromechanical properties over the range from unconsolidated sand to indurated rock.
- Africa (0.92)
- North America > United States > Utah (0.67)
- North America > United States > Michigan > Arenac County (0.45)
- Research Report > New Finding (0.93)
- Research Report > Experimental Study (0.67)
- Geology > Sedimentary Geology (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Petrology (0.85)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.52)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 193 > Block 34/11 > Kvitebjรธrn Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 193 > Block 34/11 > Kvitebjรธrn Field > Cook Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 193 > Block 34/11 > Kvitebjรธrn Field > Brent Group (0.99)
- (2 more...)
Abstract The industry is continuously challenged to improve the efficiency and safety of operations. This is evident over the last 30 years in the development and improvement of measurements acquired while drilling. However, this has, in general, until now not been applied to well integrity measurements such as casing integrity and cement evaluation, which have traditionally been acquired utilizing wireline deployment. This paper will show the results of a new drillpipe-deployed tool that can be run in parallel with existing well operations. The results from two differing North Sea wells will be compared to traditionally acquired wireline-deployed tools and will demonstrate that these measurements and the resultant interpretation can successfully be acquired on drillpipe. This allows for much improved efficiency of operations and, in fact, the ability to acquire this important data in well conditions and environments where it is difficult or, in some cases, impossible to log with conventional wireline techniques. Two wells were selected with different degrees of difficulty in terms of measurement acquisition and showing different well trajectories and mud types. Both wells were logged with both the new drillpipe-deployed technology and traditional wireline technology, allowing a direct comparison of the techniques and tools and paving the way for acceptance of the new drillpipe-conveyed technology. The new drillpipe-conveyed tool can be run anytime drillpipe is utilized in the well. A radial distribution of ultrasonic transducers arranged on the circumference of a drill collar allows for full azimuthal interpretation of the casing and cement while rotating the drillpipe. Analysis of the acquired data allows for the interpretation of caliper thickness and an evaluation of the material in the annular space behind the casing. In addition, the tool can provide casing collar location in real time and has the ability to orient downhole devices such as whipstocks, perforating guns, and oriented cutters. The two well examples conclusively demonstrate that the tool can be run in parallel with existing operations to minimize rig time and eliminate the need for a dedicated, standalone wireline operation. Also, the cement evaluation interpretation was comparable to the equivalent wireline technology. We will investigate which measurements and applications the new tool can be used for and where there may be further room for improvement.
- North America > United States > Texas (0.28)
- Europe > United Kingdom > North Sea (0.24)
- Europe > Norway > North Sea (0.24)
- (2 more...)
Over the last decade Distributed Acoustic Sensing (DAS) data acquisition has seen great improvements from better interrogators, engineered fiber and lessons learned from subsea installation and acquisition. This has given us confidence that DAS cables can be installed in wells with subsea trees to be used as receivers for Vertical Seismic Profile (VSP) seismic imaging. VSP imaging for deepwater fields has shown to provide better illumination and higher frequency seismic data. Permanent DAS cable installation can be used to acquire highly repeatable time lapse (4D) data. DAS cables were installed in a number of subsea wells on two deepwater oil fields with the intention to cover the crest of these fields with high frequency seismic data. A system was developed to allow for DAS acquisition on these offshore, subsea wells with long distance tie backs using permanently installed interrogators on the floating platforms and engineered fiber in the wells. On each of these fields a DAS cable has now been installed and a subsequently a zero offset (ZO) DAS VSP was acquired for verification and commissioning. These ZO DAS VSP acquisitions showed high fidelity installations resulting in DAS VSP data with excellent data quality. These first subsea DAS acquisitions show great promise and further installations and acquisitions are planned with the ultimate goal of providing high frequency seismic images over the crest of these fields to reduce the uncertainty in decisions around reservoir management and future infill drilling.
- Europe (0.68)
- North America > United States > Texas (0.68)
- North America > United States > Gulf of Mexico > Central GOM (0.30)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 822 > Thunder Horse Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 778 > Thunder Horse Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 826 > Mad Dog Field (0.99)
- (12 more...)
Solving the Puzzle: Eliminating Screenouts from Tight Gas Reservoir Operation
Al Shueili, A. (BP) | Al Salmi, H. (BP) | Jaboob, M. (BP) | Al Qassabi, M. (BP) | Kayumov, R. (SLB) | Kurniadi, S. D. (SLB)
Abstract Development of the tight gas Khazzan Field in Sultanate of Oman has progressed through many years of extensive learning. Massive hydraulic fracturing operations became a key part of the completions in the Barik reservoir. Fracturing design was optimized with time, eventually achieving a fit-for-purpose fracturing design. However, when activities moved towards the south, increase in reservoir gross thickness was encountered, and implementation of the standard fracturing design led to increased number of screenouts. Many parameters were examined to discover the root cause of the increased screenout rate, such as changes in pumping schedules, changed reservoir properties, fracture execution data, completion details, and many others. After the thorough analysis, it was found that lack of hydraulic width played the major role in most of the screenouts. Multiple solutions to resolve the lack of hydraulic width were considered: increase in gel loading, increase in pumping rate, optimizing pad volume, changing completion strategy, reducing job size, reducing proppant concentration, etc. After thorough consideration, it was found that removing the larger proppant might be an optimum solution for this challenge. The standard fracturing design typically included 70% of smaller ceramic 20/40 and 30% of larger 16/30 ceramic proppant. Performed production analysis has shown that some reduction in fracture conductivity by removing 16/30 proppant will have minimum negative effect on well productivity in conditions of the tight gas Barik reservoir. The results of this change have exceeded expectations: screenout rate has declined from 38% to 0% while post-fracturing production has shown the same gas rates as those with larger proppant. This paper shows how a simple but properly evaluated solution has regained the success of proppant fracturing operations in Sultanate of Oman.
- Asia > Middle East > Oman > Central Oman > Barik Formation (0.99)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Arabian Basin > Rub' al-Khali Basin > Block 61 EPSA > Block 61 > Khazzan-Makarem Field > Khazzan Field > Miqrat Formation (0.99)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Arabian Basin > Rub' al-Khali Basin > Block 61 EPSA > Block 61 > Khazzan-Makarem Field > Khazzan Field > Buah Formation (0.99)
- (15 more...)
Wave equation traveltime Kirchhoff with real data applications
Jin, Hu (BP) | Bashkardin, Vladimir (BP) | Jilek, Petr (BP) | Kumar, Chandan (BP) | Liu, Han (BP) | Etgen, John (BP) | Vyas, Madhav (BP) | Xia, Ganyuan (BP)
In recent years, Full-waveform inversion (FWI) has found wide application as a method for building high-resolution models. However, migration gathers are still needed for verifying the quality of the velocity model and for performing post-migration processing and amplitude-versus-offset analysis. Conventional Kirchhoff migration produces offset image gathers, but because the migration is based on ray tracing it fails to generate accurate images for velocity models produced by FWI that have large velocity contrasts. Smoothing high-resolution models to stabilize the ray tracing is one approach for solving this problem, but it is often not accurate enough, especially for subsalt areas. We would also rather not smooth out the details that we built using FWI at great computational expense. Wave-equation traveltime Kirchhoff (WETK) computes its traveltimes by propagating low-frequency waves instead of ray tracing. WETK produces more reliable offset gathers and image stacks without the need for smoothing the high-resolution velocity models. This paper shows two real data examples from Gulf of Mexico (GoM) to demonstrate the advantages of the method. We show that WETK produces more accurate offset gathers than conventional Kirchhoff migration, requiring less computation time than the crosscorrelation-based wave-equation Kirchhoff migrations that have been previously proposed.
- North America > United States (0.35)
- North America > Mexico (0.24)
- Geophysics > Seismic Surveying > Seismic Processing > Seismic Migration (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (1.00)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 822 > Thunder Horse Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 778 > Thunder Horse Field (0.99)
Bayesian discriminative classification with kernel density estimation for rock and fluid property characterization of seismic elastic inversion results
Wolf, Kevin (BP) | Zhang, Jingfeng (BP) | Walker, Matt (BP) | Paramo, Pedro (BP) | Winterbourne, Jeff (BP) | Biswas, Reetam (BP) | Roy, Atish (BP) | Decalf, Carole (BP)
We describe the second half of a new workflow, Bayesian Integrated Reservoir Characterization, or BIRCh (Paramo etย al. 2023, Biswas et. al 2023, Walker et. al., 2023). The second half consists of Bayesian classification of Vp, Vs and density estimates from a Bayesian seismic inversion scheme. The result is probabilistic estimates of rock and fluid properties. We apply the method to a dataset from Egypt, showing robust estimates of subsurface properties and uncertainties are obtained. The results account for the irreducible uncertainties both in seismic inversion and rock property estimation from elastic data. This allows alternative scenarios to be described which can explain observed data and are consistent with prior geologic knowledge of the area.
- Geology > Geological Subdiscipline > Geomechanics (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.32)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (0.92)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.69)
Meeting the imaging challenges at Atlantis with high-frequency elastic FWI
Hao, Alex (CGG) | Chen, Chi (CGG) | Wei, Zhiyuan (CGG) | Mei, Jiawei (CGG) | Jiang, Li (BP) | Buist, Sam (BP) | Egbue, Obi (BP) | Lopez, Luis (BP) | Tebo, Daniel (BP)
Imaging the details of the Atlantis reservoir is challenging due to its complex compartmentalization and overburden salt bodies. Even though advancements in imaging technologies, such as acoustic full-waveform inversion (FWI) and FWI Imaging, have greatly improved the reservoir images by providing a superior salt model and compensating for poor illumination, several challenges remain. These include the salt halo issue resulting from acoustic FWI (AFWI) not properly modeling the strong elastic effect around salt bodies, still sub-optimal signal-tonoise ratio (S/N), and insufficient resolution due to the limit of prior FWI frequency. To meet these challenges and further resolve the reservoir details at Atlantis, we employed elastic Time-lag FWI (E-TLFWI) and elastic FWI (EFWI) Imaging up to 30 Hz. This allows us to reduce the salt halos, enhance the subsalt S/N, and reveal crucial details of the compartmentalized reservoir. Additionally, for the subsalt high-frequency (>20 Hz) FWI Imaging at Atlantis, it is essential to utilize ocean bottom node (OBN) data with a denser node spacing that can better sample the complex wavefield and provide higher stacking power to improve the S/N. To achieve this, we have incorporated the newly acquired 2022 OBN data with a node spacing of 200x200 m that was specifically tailored for subsalt imaging at higher frequencies. This integration further improves the clarity and S/N of the images, offering unprecedented insights into the reservoir details.
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 744 > Atlantis Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 743 > Atlantis Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 742 > Atlantis Field (0.99)
- (2 more...)
Comparison of three Bayesian methods for lithofluid facies prediction using elastic properties
Zhang, Jingfeng (BP) | Wolf, Kevin (BP) | Yusifov, Anar (BP) | Walker, Matt (BP) | Paramo, Pedro (BP) | Winterbourne, Jeffrey (BP) | Biswas, Reetam (BP) | Roy, Atish (BP) | Liu, Qiang (The University of Texas at Austin) | Liu, Xingchao (The University of Texas at Austin)
One of the main objectives of seismic inversion in reservoir characterization is to predict lithofluid facies, such as gas sand, brine sand, and shale. For seismic inversion methods that explicitly generate elastic properties (Vp, Vs, and density), a critical next step is to use these properties to predict lithofluid facies. Bayesian methods utilize important prior knowledge of lithofluid facies distribution to constrain the inversion results. This paper compares three different algorithms that utilize varying degrees of the prior information and demonstrate their sensitivity to noise and transition probability matrix.
- Geology > Geological Subdiscipline > Geomechanics (0.73)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.56)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.56)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic modeling (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (0.93)
High-resolution imaging using least-squares migration in the image domain (LSMi) for a marine distributed acoustic sensing (DAS) 3D-VSP
Sayed, Ali (SLB) | Twynam, Francesca (SLB) | Bachrach, Ran (SLB) | Cavalca, Maud (SLB) | Leon, Leo (SLB) | Shadrina, Maria (SLB) | Li, Qingsong (BP) | Biswas, Reetam (BP) | Tebo, Daniel (BP) | Buist, Sam (BP)
A large-scale distributed acoustic sensing (DAS) dataset acquired during an ocean bottom node (OBN) survey was processed to produce high-resolution images of the reservoir. Novel processing workflows were deployed to prepare DAS data for migration. Reverse time migration (RTM) and Kirchhoff depth migration (KDM) kernels were used to generate complimentary images. A pre-stack Qamplitude compensation technique was implemented to improve image quality and resolution. Least-squares migration in the image domain was used to further enhance image resolution and compensate for the variable illumination effects that are unique to the 3D-VSP geometry.
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (1.00)
- Geophysics > Seismic Surveying > Seismic Processing > Seismic Migration (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying > Vertical Seismic Profile (VSP) (1.00)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 744 > Atlantis Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 743 > Atlantis Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 742 > Atlantis Field (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Near-well and vertical seismic profiles (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)