Summary Massively parallel single-instruction, multiple-data (SIMD) computers have shown much promise in solving numerically intensive problems ranging from molecular modeling to computational fluid dynamics. Much of the research on the use of parallel computing for reservoir simulation, however, has been parallel computing for reservoir simulation, however, has been limited to coarse-grain, shared memory computers or medium-grain hypercubes. We report here on research performed on a massively parallel SIMD computer with 65,536 processors. This work addresses issues in machine architecture, programming environment, and formulation of a reservoir simulator programming environment, and formulation of a reservoir simulator on SIMD computers. Towards this end, a three phase, three dimensional, IMPES compositional simulator was developed in Fortran 8X. Problems associated with reservoir simulation on SIMD computers such as an appropriate data structure for the SIMD architecture, the treatment of multiple fluid phases, data communication, and the matrix solution are addressed in this paper. In addition, table lookup poses a unique problem for SIMD computers because storage of large tables on each processor is impractical, as is the use of the front-end computer to perform this function. The problem is overcome through a novel use of local memory access. We found that massively parallel computers can be used to run very large reservoir models and that the cost of data transfer between processors need not be prohibitive. Reservoir models with two hydrocarbon components and up to 2,097,152 grid blocks were successfully run using this simulator. Computational speeds on the order of one giga FLOPS were achieved for the generation of the Jacobian mix and the matrix solution using 65,536 processors. Introduction The current trend for improving supercomputer performance is to increase the intrinsic speed of the individual processors and/or to add more processors. As clock speed approaches the maximum physical limit for semiconductors, the addition of more processors is physical limit for semiconductors, the addition of more processors is the more promising direction. Parallel computers, in particular those with distributed memory, have generated much interest for numerically intensive applications. These parallel computers hold the promise of being more cost effective than supercomputers with shared memory, and have the potential to solve much larger problems.
Unconventional oil reservoirs such as the Eagle Ford have had tremendous success over the last decade, but challenges remain as flow rates drop quickly and recovery factors are low; thus, enhanced oil recovery methods are needed to increase recovery. Interest in cyclic gas injection has risen as a number of successful pilots have been reported; however, little information is available on recovery mechanisms for the process. This paper evaluates oil swelling caused by diffusion and advection processes for gas injection in unconventional reservoirs. To accurately evaluate gas penetration into the matrix, the surface area of the hydraulic fractures needs to be known, and in this work, three different methods are used to estimate the area: volumetrics, well flow rates and linear fluid flow equations. Fick's law is used to determine the gas penetration depth caused by diffusion, and the linear form of Darcy's law is used to find the amount from advection. Then, with the use of swelling test information from lab tests, we are able to approximate the amount of oil recovery expected from cyclic gas injection operations. During the gas injection phase, gas from the fractures can enter the matrix by both advection (Darcy driven flow) and diffusion. We estimate that over 200 million scf of gas can enter the matrix during a 100 day injection/soak period. Using typical reservoir and fluid parameters, it appears that 40% is due to diffusion and 60% is due to advection. Sensitivity analysis shows that these numbers vary considerable based on the parameters used. Analytical models also show that during a 100 day production timeframe, over 14,000 stock tank barrels (STB) of oil can be produced due to huff-n-puff gas injection. Both gas injection and oil recovery amounts are compared to recent Eagle Ford gas injection pilot data, and the model results are consistent with the field pilot data. By determining the relative importance of the different recovery mechanisms, this paper provides a better understanding of what is happening in unconventional reservoirs during cyclic gas injection. This will allow more efficient injection schemes to be designed in the future.
In multistage fracturing of unconventional formations such as the Eagle Ford shale, wells are traditionally stimulated by fracturing several perforation clusters simultaneously. While the technique is operationally efficient, there is evidence from production logs, microseismic monitoring, and other measurements that several clusters produce below expectations or do not produce at all. This condition is to a degree because stages penetrate zones with stress heterogeneities, and consequently, fractures propagate unevenly from all of the clusters. Evenly fracturing all clusters in heterogeneous zones is challenging in long horizontal sections penetrating heterogeneous reservoirs. Furthermore, efforts to improve well economics result in reducing completion time by extending the length of each stage even further to decrease the number of interventions required for completing the well. To address this challenge, a new sequenced fracturing technique has been developed based on a novel composite fluid comprising of degradable fibers and multi-sized particles that diverts the remaining stimulation fluids to understimulated regions of the wellbore. The composite fluid is delivered downhole at high-concentration, to create temporary plugs in clusters already stimulated thereby creating diversion with a minor amount of material. The solids degrade completely after the fracturing treatment has been completed, leaving no residual formation or fracture conductivity damage. The channel fracturing technique (Gillard et al. 2010) was chosen as the preferred fracturing method for use in tandem with the composite fluid. This technique has been reported to increase effective fracture length while reducing risk of screenout with respect to other conventional methods. The new composite fluid was used in a campaign where its effects were monitored with microseismic instruments. A case study presents field experiments where wells from the same pad are fractured in a similar fashion with and without diversion. In one application, with similar water and fluid volumes, the well treated with this technique produced more than 15% per stage than its conventionally treated offset well. The signature of the composite fluid, clearly visible on all measurement techniques, has proven consistent across stages of various lengths and wells having different characteristics.
Summary This paper shows the results of a 2-year study on the quality of cement-grade bentonite now available commercially. A comparison of laboratory-designed slurries with field-blend samples shows drastic alteration of cement-slurry performance from poor blending procedures and/or poor-quality bentonite, which could cause catastrophic consequences. Evidence from microscopic examination, chemical-quality procedures, and cement-slurry performance data shows a failure rate approaching 50% among more than 150 samples tested from field stocks. Laboratory data on cement-slurry performance with bentonite that passed and failed the current API specification test are presented. Introduction Problems with bentonite quality and difficulties in determining Problems with bentonite quality and difficulties in determining quality variations among manufacturers' plants and service-company stock points continue to occur. The important considerations in the use of a premium bentonite are the properties that good bentonite gives a lightweight cementing system: zero free water, good fluidloss control, good rheological properties, adequate compressive strengths for filler cement, and cost-effectiveness. The API Specification for Materials and Testing for Well Cements defines bentonite as "a natural material consisting principally of the clay mineral, montmorillonite. It is dried and ground, principally of the clay mineral, montmorillonite. It is dried and ground, but otherwise untreated in processing. No beneficiating agents or other material shall be added to bentonite used in well cements." Additives have been used widely to improve the performance of the bentonite temporarily in drilling fluids to meet API specifications. It has become apparent that treated bentonite is also being used in cementing applications as API cement-grade bentonite. Past API specifications on cement-grade bentonite were violated by the addition of polyacrylamides to increase the yield of lowgrade bentonites. The polyacrylamide concentrations were so small that detection by sophisticated analytical techniques was impossible, but the yield of bentonite was beneficiated so that the bentonite appeared to pass the specification test. The current API specification test fails this type of beneficiated bentonite. API Specifications on Bentonite Beneficiating agents have long been forbidden by the description of cement-grade bentonite. In the past, enforcement of this specification has been difficult because of the shortcomings of classic analytical techniques mentioned earlier. Because of viscosity and filtration problems resulting from the use of beneficiated bentonite, the API Committee on Drilling Fluids (Committee 13) developed a test procedure that uses sodium hex-ametaphosphate to screen bentonite for beneficiation. This screening test has been accepted by the Committee on Well Cements. The test does not detect beneficiating agents directly but involves measuring properties of a bentonite slurry (such as plastic viscosity, yield point, and fluid-loss control) both before and after treatment with a solution of sodium hexametaphosphate to ensure that they fall within specified ranges. The sodium hexametaphosphate negates the beneficiating effects of added polymers and allows the detection of treated bentonite.
Unconventional oil reservoirs have taken a prominent role in the United States as a source of crude oil. Different methodologies to estimate reserves for shale gas and coal bed methane have, thus far, proved to be reliable, but no simple yet accurate workflow has been generally accepted to forecast production and estimate reserves for shale oil. To fill this gap in technology, we proposed and validated a workflow that integrates analytical methods with empirical methods. The final methodology is both easily applied and accurate. In developing the final workflow, we evaluated several alternatives, most of which proved to be unsuitable. We also investigated the use of a filter to eliminate outliers in a systematic way, as proposed by Rastogi (2014).The workflow was successfully applied to three of four volatile oil wells in the Eagle Ford shale, with similar results. The analytical model that best matched the wells is called the Stimulated Reservoir Volume (SRV) Bounded Model. We tested this and other models using a new field production analysis tool software. While accurate, this modeling approach is too time consuming for routine use. We found that a simple empirical approach that led to the same results as the analytical model was a 3-segment Arps decline model. The early flow regime was transient linear for all the wells; thus an Arps ЉbЉ parameter of two was appropriate. When boundary-influenced flow (BIF) appeared later, b-values of 0.2 were found appropriate. The initial decline rate (Di) value during BIF was modified in mid-segment leading to a distinct third segment. Our workflow also led to reliable forecasts of production (to date) of the gas-oil ratio for the three wells.
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