To see the other types of publications on this topic, follow the link: Oil reservoir simulation.
Journal articles on the topic 'Oil reservoir simulation'
Create a spot-on reference in APA, MLA, Chicago, Harvard, and other styles
Consult the top 50 journal articles for your research on the topic 'Oil reservoir simulation.'
Next to every source in the list of references, there is an 'Add to bibliography' button. Press on it, and we will generate automatically the bibliographic reference to the chosen work in the citation style you need: APA, MLA, Harvard, Chicago, Vancouver, etc.
You can also download the full text of the academic publication as pdf and read online its abstract whenever available in the metadata.
Browse journal articles on a wide variety of disciplines and organise your bibliography correctly.
1
Anonymous. "Oil reservoir simulation package." Eos, Transactions American Geophysical Union 70, no. 26 (1989): 676. http://dx.doi.org/10.1029/eo070i026p00676-03.
Full text
2
Ghassemzadeh, Shahdad, Maria Gonzalez Perdomo, Manouchehr Haghighi, and Ehsan Abbasnejad. "Deep net simulator (DNS): a new insight into reservoir simulation." APPEA Journal 60, no. 1 (2020): 124. http://dx.doi.org/10.1071/aj19093.
Full textAbstract:
Reservoir simulation plays a vital role as a diagnostics tool to better understand and predict a reservoir’s behaviour. The primary purpose of running a reservoir simulation is to replicate reservoir performance under different production conditions; therefore, the development of a reliable and fast dynamic reservoir model is a priority for the industry. In each simulation, the reservoir is divided into millions of cells, with fluid and rock attributes assigned to each cell. Based on these attributes, flow equations are solved through numerical methods, resulting in an excessively long processing time. Given the recent progress in machine learning methods, this study aimed to further investigate the possibility of using deep learning in reservoir simulations. Throughout this paper, we used deep learning to build a data-driven simulator for both 1D oil and 2D gas reservoirs. In this approach, instead of solving fluid flow equations directly, a data-driven model instantly predicts the reservoir pressure using the same input data of a numerical simulator. Datasets were generated using a physics-based simulator. It was found that for the training and validation sets, the mean absolute percentage error (MAPE) was less than 15.1% and the correlation coefficient, R2, was more than 0.84 for the 1D oil reservoirs, while for the 2D gas reservoir MAPE < 0.84% and R2 ≈1. Furthermore, the sensitivity analysis results confirmed that the proposed approach has promising potential (MAPE < 5%, R2 > 0.9). The results agreed that the deep learning based, data-driven model is reasonably accurate and trustworthy when compared with physics-derived models.
3
Ayache, Simon V., Violaine Lamoureux-Var, Pauline Michel, and Christophe Preux. "Reservoir Simulation of Hydrogen Sulfide Production During a Steam-Assisted-Gravity-Drainage Process by Use of a New Sulfur-Based Compositional Kinetic Model." SPE Journal 22, no. 01 (August 3, 2016): 080–93. http://dx.doi.org/10.2118/174441-pa.
Full textAbstract:
Summary Steam injection is commonly used as a thermal enhanced-oil-recovery (EOR) method because of its efficiency for recovering hydrocarbons, especially from heavy-oil and bitumen reservoirs. Reservoir models simulating this process describe the thermal effect of the steam injection, but generally neglect the chemical reactions induced by the steam injection and occurring in the reservoir. In particular, these reactions can lead to the generation and production of the highly toxic and corrosive acid gas hydrogen sulfide (H2S). The overall objective of this paper is to quantitatively describe the chemical aquathermolysis reactions that occur in oil-sands reservoirs undergoing steam injections and to provide oil companies with a numerical model for reservoir simulators to forecast the H2S-production risks. For that purpose, a new sulfur-based compositional kinetic model has been developed to reproduce the aquathermolysis reactions in the context of reservoir modeling. It is derived from results gathered on an Athabasca oil sand from previous laboratory aquathermolysis experiments. In particular, the proposed reactions model accounts for the formation of H2S issued from sulfur-rich heavy oils or bitumen, and predicts the modification of the resulting oil saturate, aromatic, resin, and asphaltene (SARA) composition vs. time. One strength of this model is that it is easily calibrated against laboratory-scale experiments conducted on an oil-sand sample. Another strength is that its calibration is performed while respecting the constraints imposed by the experimental data and the theoretical principles. In addition, in this study no calibration was needed at reservoir scale against field-production data. In the paper, the model is first validated with laboratory-scale simulations. The thermokinetic modeling is then coupled with a 2D reservoir simulation of a generic steam-assisted gravity drainage (SAGD) process applied on a generic Athabasca oil-sand reservoir. This formulation allows investigating the H2S generation at reservoir scale and quantifying its production. The H2S- to bitumen-production ratio against time computed by the reservoir simulation is found to be consistent with production data from SAGD operations in Athabasca, endorsing the proposed methodology.
4
Taggart, I. J., and H. A. Salisch. "FRACTAL GEOMETRY, RESERVOIR CHARACTERISATION AND OIL RECOVERY." APPEA Journal 31, no. 1 (1991): 377. http://dx.doi.org/10.1071/aj90030.
Full textAbstract:
Reservoir heterogeneity is a dominant factor in determining large-scale fluid flow behaviour in reservoirs. Engineering estimates of oil production rates need to acknowledge and incorporate the effect of such heterogeneities. This work examines the use of fractal-based scaling techniques aimed at characterising heterogeneous reservoirs for simulation purposes. Well log data provide suitable fine-scale information for estimating the fractal dimension of reservoirs as well as providing known end- point data for interwell property value interpolation. Fractal techniques allow this interpolation to be performed in a manner which reproduces the same correlation structure as that found in the original well logs. Conditional simulation in these property fields allows the interaction between reservoir heterogeneity and fluid flow to be studied on a range of scales up to the interwell spacing. Analysis of results allows the calculation of effective reservoir properties which characterise the reservoir in terms of large-scale performance.
5
Lee, Ji Ho, and Kun Sang Lee. "Multiphase, Multicomponent Simulation for Flow and Transport during Polymer Flood under Various Wettability Conditions." Journal of Applied Mathematics 2013 (2013): 1–8. http://dx.doi.org/10.1155/2013/101670.
Full textAbstract:
Accurate assessment of polymer flood requires the understanding of flow and transport of fluids involved in the process under different wettability of reservoirs. Because variations in relative permeability and capillary pressure induced from different wettability control the distribution and flow of fluids in the reservoirs, the performance of polymer flood depends on reservoir wettability. A multiphase, multicomponent reservoir simulator, which covers three-dimensional fluid flow and mass transport, is used to investigate the effects of wettability on the flow process during polymer flood. Results of polymer flood are compared with those of waterflood to evaluate how much polymer flood improves the oil recovery and water-oil ratio. When polymer flood is applied to water-wet and oil-wet reservoirs, the appearance of influence is delayed for oil-wet reservoirs compared with water-wet reservoirs due to unfavorable mobility ratio. In spite of the delay, significant improvement in oil recovery is obtained for oil-wet reservoirs. With respect to water production, polymer flood leads to substantial reduction for oil-wet reservoirs compared with water-wet reservoirs. Moreover, application of polymer flood for oil-wet reservoirs extends productive period which is longer than water-wet reservoir case.
6
Dogru, A. H., H. A. Sunaidi, L. S. Fung, W. A. Habiballah, N. Al-Zamel, and K. G. Li. "A Parallel Reservoir Simulator for Large-Scale Reservoir Simulation." SPE Reservoir Evaluation & Engineering 5, no. 01 (February 1, 2002): 11–23. http://dx.doi.org/10.2118/75805-pa.
Full textAbstract:
Summary A new parallel, black-oil-production reservoir simulator (Powers**) has been developed and fully integrated into the pre- and post-processing graphical environment. Its primary use is to simulate the giant oil and gas reservoirs of the Middle East using millions of cells. The new simulator has been created for parallelism and scalability, with the aim of making megacell simulation a day-to-day reservoir-management tool. Upon its completion, the parallel simulator was validated against published benchmark problems and other industrial simulators. Several giant oil-reservoir studies have been conducted with million-cell descriptions. This paper presents the model formulation, parallel linear solver, parallel locally refined grids, and parallel well management. The benefits of using megacell simulation models are illustrated by a real field example used to confirm bypassed oil zones and obtain a history match in a short time period. With the new technology, preprocessing, construction, running, and post-processing of megacell models is finally practical. A typical history- match run for a field with 30 to 50 years of production takes only a few hours. Introduction With the development of early parallel computers, the attractive speed of these computers got the attention of oil industry researchers. Initial questions were concentrated along these lines:Can one develop a truly parallel reservoir-simulator code?What type of hardware and programming languages should be chosen? Contrary to seismic, it is well known that reservoir simulator algorithms are not naturally parallel; they are more recursive, and variables display a strong dependency on each other (strong coupling and nonlinearity). This poses a big challenge for the parallelization. On the other hand, if one could develop a parallel code, the speed of computations would increase by at least an order of magnitude; as a result, many large problems could be handled. This capability would also aid our understanding of the fluid flow in a complex reservoir. Additionally, the proper handling of the reservoir heterogeneities should result in more realistic predictions. The other benefit of megacell description is the minimization of upscaling effects and numerical dispersion. The megacell simulation has a natural application in simulating the world's giant oil and gas reservoirs. For example, a grid size of 50 m or less is used widely for the small and medium-size reservoirs in the world. In contrast, many giant reservoirs in the Middle East use a gridblock size of 250 m or larger; this easily yields a model with more than 1 million cells. Therefore, it is of specific interest to have megacell description and still be able to run fast. Such capability is important for the day-to-day reservoir management of these fields. This paper is organized as follows: the relevant work in the petroleum-reservoir-simulation literature has been reviewed. This will be followed by the description of the new parallel simulator and the presentation of the numerical solution and parallelism strategies. (The details of the data structures, well handling, and parallel input/output operations are placed in the appendices). The main text also contains a brief description of the parallel linear solver, locally refined grids, and well management. A brief description of megacell pre- and post-processing is presented. Next, we address performance and parallel scalability; this is a key section that demonstrates the degree of parallelization of the simulator. The last section presents four real field simulation examples. These example cases cover all stages of the simulator and provide actual central processing unit (CPU) execution time for each case. As a byproduct, the benefits of megacell simulation are demonstrated by two examples: locating bypassed oil zones, and obtaining a quicker history match. Details of each section can be found in the appendices. Previous Work In the 1980s, research on parallel-reservoir simulation had been intensified by the further development of shared-memory and distributed- memory machines. In 1987, Scott et al.1 presented a Multiple Instruction Multiple Data (MIMD) approach to reservoir simulation. Chien2 investigated parallel processing on sharedmemory computers. In early 1990, Li3 presented a parallelized version of a commercial simulator on a shared-memory Cray computer. For the distributed-memory machines, Wheeler4 developed a black-oil simulator on a hypercube in 1989. In the early 1990s, Killough and Bhogeswara5 presented a compositional simulator on an Intel iPSC/860, and Rutledge et al.6 developed an Implicit Pressure Explicit Saturation (IMPES) black-oil reservoir simulator for the CM-2 machine. They showed that reservoir models over 2 million cells could be run on this type of machine with 65,536 processors. This paper stated that computational speeds in the order of 1 gigaflop in the matrix construction and solution were achievable. In mid-1995, more investigators published reservoir-simulation papers that focused on distributed-memory machines. Kaarstad7 presented a 2D oil/water research simulator running on a 16384 processor MasPar MP-2 machine. He showed that a model problem using 1 million gridpoints could be solved in a few minutes of computer time. Rame and Delshad8 parallelized a chemical flooding code (UTCHEM) and tested it on a variety of systems for scalability. This paper also included test results on Intel iPSC/960, CM-5, Kendall Square, and Cray T3D.
7
Kaliszewski, A. B. "RESERVOIR SIMULATION FOR RESERVOIR MANAGEMENT." APPEA Journal 26, no. 1 (1986): 397. http://dx.doi.org/10.1071/aj85034.
Full textAbstract:
The Hutton reservoir in the Merrimelia Field (Cooper-Eromanga Basin) was the subject of a 3-D reservoir simulation study. The primary objective of the study was to develop a reservoir management tool for evaluating the performance of the field under various depletion options.The study confirmed that the ultimate oil recovery from this strong water drive reservoir was not adversely affected by increasing total fluid offtake rate. However, any decisions regarding changes to the depletion scheme such as increasing production rates, if based solely on computer simulation results, should be viewed with caution. Careful monitoring of any changes to the depletion philosophy and checking of actual data against simulation predictions are essential to ensure that oil production rate and ultimate recovery are optimised.The model assisted in evaluating the economics of development drilling. While the simulation results are dependent on the validity of geological mapping, the model was useful in confirming that, due to very high transmissibility in the Hutton reservoir, additional wells would only accelerate production rather than increase ultimate recovery. The issue of drilling wells thus became one of balancing the benefits of accelerating production against the geological risk associated with that well.Interaction between the reservoir engineer and various disciplines, particularly development geology, is critical in the development and application of a good working simulation model. This was found to be especially important during the history matching phase in the study. If engineers and development geologists can learn more of the others' discipline and appreciate the role that each has to play in simulation studies, the validity of such models can only be improved.The paper addresses a number of the pitfalls commonly encountered in application of reservoir simulation results.
8
Towler, B. F. "RESERVOIR SIMULATION IN THE MEREENIE FIELD." APPEA Journal 26, no. 1 (1986): 428. http://dx.doi.org/10.1071/aj85037.
Full textAbstract:
The Mereenie Field in the Amadeus Basin was discovered in 1964 and contains an estimated 240 million barrels of oil and 480 billion (USA) cubic feet of gas in three formations. The field commenced production at 1500 barrels of oil per day from seven wells in September 1984. The structure is large and elongated and the oil in the permeable sands appears as a rim round the structure. This paper describes a reservoir simulation study initiated to evaluate the recovery of oil from wells sited on the north and south flanks of the anticline where the steep dips cause the oil rim to become very narrow.Ten studies were made on a 21 × 15 cell pattern model using a three phase semi-implicit black oil reservoir simulator. The ten runs compared oil recovery and gas/oil ratio as a function of formation dip, bottom hole flowing pressure, gas injection and water injection. These showed that the flank wells could be expected to recover 300 000 stock tank barrels of oil from primary and secondary operations which represents about 25 per cent of the oil in place for wells sited on half mile spacings. However the wells will experience high gas/oil ratios and a steep decline in oil rate.
9
Xu, Zhongyi, Linsong Cheng, Renyi Cao, and Sidong Fang. "Simulation of Counter-Current Imbibition in SRVs of Tight Oil Reservoir." Journal of Clean Energy Technologies 6, no. 4 (July 2018): 339–43. http://dx.doi.org/10.18178/jocet.2018.6.4.485.
Full text
10
Tong, Kai Jun, Yan Chun Su, Li Zhen Ge, Jian Bo Chen, and Ling Ling Nie. "Numerical Simulation of the Buried Hill Reservoir in Bohai Bay." Applied Mechanics and Materials 448-453 (October 2013): 4003–8. http://dx.doi.org/10.4028/www.scientific.net/amm.448-453.4003.
Full textAbstract:
Buried hill reservoir fracture description and reservoir simulation technology have been a hot research, but also is one of the key issues that restrict the efficient development of such reservoirs. Based on JZ buried hill reservoir which heterogeneity is strong, some wells water channeling fast and difficult to control the situation for fracture affect, a typical block of dual medium reservoir numerical models which was comprehensive variety of information, discrete fracture characterization and geological modeling is established. The fractured reservoir numerical model is simulated through Eclipse software to seek the law of remaining oil distribution. Through the reservoir geological reserves and production history matching, the remaining oil distribution of main production horizon is forecasted. On this basis, the results of different oilfield development adjustment programs are predicted by numerical simulation.
11
Li, Hangyu, and Louis J. Durlofsky. "Upscaling for Compositional Reservoir Simulation." SPE Journal 21, no. 03 (June 15, 2016): 0873–87. http://dx.doi.org/10.2118/173212-pa.
Full textAbstract:
Summary Compositional flow simulation, which is required for modeling enhanced-oil-recovery (EOR) operations, can be very expensive computationally, particularly when the geological model is highly resolved. It is therefore difficult to apply computational procedures that require large numbers of flow simulations, such as optimization, for EOR processes. In this paper, we develop an accurate and robust upscaling procedure for oil/gas compositional flow simulation. The method requires a global fine-scale compositional simulation, from which we compute the required upscaled parameters and functions associated with each coarse-scale interface or wellblock. These include coarse-scale transmissibilities, upscaled relative permeability functions, and so-called α-factors, which act to capture component flow rates in the oil and gas phases. Specialized near-well treatments for both injection and production wells are introduced. An iterative procedure for optimizing the α-factors is incorporated to further improve coarse-model accuracy. The upscaling methodology is applied to two example cases, a 2D model with eight components and a 3D model with four components, with flow in both cases driven by wells arranged in a five-spot pattern. Numerical results demonstrate that the global compositional upscaling procedure consistently provides very accurate coarse results for both phase and component production rates, at both the field and well level. The robustness of the compositionally upscaled models is assessed by simulating cases with time-varying well bottomhole pressures that are significantly different from those used when the coarse model was constructed. The coarse models are shown to provide accurate predictions in these tests, indicating that the upscaled model is robust with respect to well settings. This suggests that one can use upscaled models generated from our procedure to mitigate computational demands in important applications such as well-control optimization.
12
Coats, K. H., L. K. Thomas, and R. G. Pierson. "Compositional and Black Oil Reservoir Simulation." SPE Reservoir Evaluation & Engineering 1, no. 04 (August 1, 1998): 372–79. http://dx.doi.org/10.2118/50990-pa.
Full text
13
Ramírez, A., A. Romero, F. Chavez, F. Carrillo, and S. Lopez. "Mathematical simulation of oil reservoir properties." Chaos, Solitons & Fractals 38, no. 3 (November 2008): 778–88. http://dx.doi.org/10.1016/j.chaos.2007.01.028.
Full text
14
Asadullah, M., P. Behrenbruch, and S. Pham. "RESERVOIR SIMULATION—UPSCALING, STREAMLINES AND PARALLEL COMPUTING." APPEA Journal 47, no. 1 (2007): 199. http://dx.doi.org/10.1071/aj06013.
Full textAbstract:
Simulation of petroleum reservoirs is becoming more and more complex due to increasing necessity to model heterogeneity of reservoirs for accurate reservoir performance prediction. With high oil prices and less easy oil, accurate reservoir management tools such as simulation models are in more demand than ever before. The aim is to capture and preserve reservoir heterogeneity when changing over from a detailed geocellular model to a flow simulation model, minimising errors when upscaling and preventing excessive numerical dispersion by employing variable and innovative grids, as well as improved computational algorithms.For accurate and efficient simulation of large-scale models there are essentially three choices: upscaling, which involves averaging of parameters for several blocks, resulting in a coarser model that executes faster; the use of streamline simulation, which uses a more optimal grid, combined with a different computational algorithm for increased efficiency; and, the use of parallel computing techniques, which use superior hardware configurations for efficiency gains. With uncertainty screening of various multiple geostatistical realisations and investigation of alternative development scenarios— now commonplace for determining reservoir performance—computational efficiency and accuracy in modelling are paramount. This paper summarises the main techniques and methodologies involved in considering geocellular models for flow simulation of reservoirs, commenting on advantages and disadvantages among the various possibilities. Starting with some historic comments, the three modes of simulation are reviewed and examples are given for illustrative purposes, including a case history for the Bayu-Undan Field, Timor Sea.
15
Siripatrachai, Nithiwat, Turgay Ertekin, and Russell T. Johns. "Compositional Simulation of Hydraulically Fractured Tight Formation Considering the Effect of Capillary Pressure on Phase Behavior." SPE Journal 22, no. 04 (March 6, 2017): 1046–63. http://dx.doi.org/10.2118/179660-pa.
Full textAbstract:
Summary Compositional reservoir simulation plays a vital role in the development of conventional and unconventional reservoirs. Two major building blocks of compositional simulation are phase-behavior and fluid-transport computations. The oil and gas reserves and flow of reservoir fluids are strongly dependent on phase behavior. In conventional reservoirs, capillary pressure is relatively small and is typically ignored in phase-behavior calculations. The approach is accepted as the norm to perform phase-equilibria calculation to estimate the oil and gas in place and fluid properties. However, large capillary pressure values are encountered in tight formations, such as shales, and therefore, its effects should not be ignored in phase-equilibria calculations. Many parameters and uncertainties contribute to the accuracy of the estimation and simulation results. In this research, the focus is on the effect of capillary pressure, and neglecting the effects of capillary pressure on phase behavior can lead to an inaccurate estimation of original oil in place (OOIP) and original gas in place (OGIP) as well as recovery performance because of the inherent assumption of equal phase pressures in the phase-equilibria calculation. Understanding of the effect of capillary pressure on phase behavior in tight reservoirs is by no means complete, especially by use of compositional simulation for hydraulically fractured reservoirs. In this paper, we develop a new compositional reservoir simulator capable of modeling discrete fractures and incorporating the effect of capillary pressure on phase behavior. Large-scale natural and hydraulic fractures in tight rocks and shales are modeled with a technique called the embedded-discrete-fracture model (EDFM), where fractures are modeled explicitly without use of local-grid refinement (LGR) or an unstructured grid. Flow of hydrocarbons occurs simultaneously within similar and different porosity types. Capillary pressure is considered in both flow and flash calculations, where simulations also include variable pore size as a function of gas saturation to accurately reflect temporal changes in each gridblock during the simulation. We examine the effect of capillary pressure on the OOIP and cumulative oil production for different initial reservoir pressures (above and below the bubblepoint pressure) on Bakken and Eagle Ford fluids. The importance of capillary pressure on both flow and flash calculations from hydraulically fractured horizontal wells during primary depletion in fractured tight reservoirs by use of two fluid compositions is demonstrated. Phase-behavior calculations show that bubblepoint pressure is suppressed, allowing the production to remain in the single-phase region for a longer period of time and also altering phase compositions and fluid properties, such as density and viscosity of equilibrium liquid and vapor. The results show that bubblepoint suppression is larger in the Eagle Ford shale than for Bakken. On the basis of the reservoir fluid and model used for the Bakken and Eagle Ford formations, when capillary pressure is included in the flash, we found an increase in OOIP up to 4.1% for the Bakken crude corresponding to an initial reservoir pressure of 2,000 psia and 46.33% for the Eagle Ford crude corresponding to an initial pressure of 900 psia. Depending on the initial reservoir pressure, cumulative primary oil production after 1 year increases because of the capillary pressure by approximately 9.0 to 38.2% for an initial reservoir-pressure range from 2,000 to 3,500 psia for Bakken oil and 7.2 to 154% for an initial reservoir-pressure range from 1,500 to 3,500 psia for Eagle Ford oil. The recovery increase caused by capillary pressure becomes more significant when reservoir pressure is far less than bubblepoint pressure. The simulation results with hydraulically fractured wells give similar recovery differences. For the two different reservoir settings in this study, at initial reservoir pressure of 5,500 psia, cumulative oil production after 1 year is 3.5 to 5.2% greater when capillary pressure is considered in phase-behavior calculations for Bakken. As initial reservoir pressure is lowered to 2,500 psia, the increase caused by capillary pressure is up to 28.1% for Bakken oil for the case studied. Similarly, at initial reservoir pressure of 2,000 psia, the increase caused by capillary pressure is 21.8% for Eagle Ford oil.
16
Magner, T. N. "ECONOMIC BENEFITS OF THE KUTUBU RESERVOIR MANAGEMENT STRATEGY." APPEA Journal 35, no. 1 (1995): 121. http://dx.doi.org/10.1071/aj94008.
Full textAbstract:
In spite of all the of the studies and analyses conducted since the initial oil discovery in 1986, considerable uncertainty existed over the expected performance of the Kutubu reservoirs prior to initial production. Extensive use of reservoir simulation during the field development helped overcome technical challenges in the development phase. Continued modelling work has increased understanding of reservoir behaviour, identified additional development opportunities and further enhanced field economics.Since First Oil in June 1992, over 100 MMSTB of light, sweet Kutubu crude oil have been produced and exported {through October 1994). At present, the field produces approximately 120,000 STBO/D from 27 vertical wells and two horizontal wells. Reservoir pressure maintenance is provided by gravity-stable re-injection of produced gas into five wells.On the whole, the reservoirs have met or exceeded expectations to date. This is in part due to the effective planning and implementation of a strategy to manage the Kutubu reservoirs. This reservoir management strategy combines an aggressive program of reservoir surveillance, data collection, computer simulation and continuous reassessment of previous assumptions.
17
Hou, Dali, Yang Xiao, Yi Pan, Lei Sun, and Kai Li. "Experiment and Simulation Study on the Special Phase Behavior of Huachang Near-Critical Condensate Gas Reservoir Fluid." Journal of Chemistry 2016 (2016): 1–10. http://dx.doi.org/10.1155/2016/2742696.
Full textAbstract:
Due to the special phase behavior of near-critical fluid, the development approaches of near-critical condensate gas and near-critical volatile oil reservoirs differ from conventional oil and gas reservoirs. In the near-critical region, slightly reduced pressure may result in considerable change in gas and liquid composition since a large amount of gas or retrograde condensate liquid is generated. It is of significance to gain insight into the composition variation of near-critical reservoir during the depletion development. In our study, we performed a series ofPVTexperiments on a real near-critical gas condensate reservoir fluid. In addition to the experimental studies, a commercial simulator combined with the PREOS model was utilized to study retrograde condensate characteristics and reevaporation mechanism of condensate oil with CO2injection based on vapor-liquid phase equilibrium thermodynamic theory. The research shows that when reservoir pressure drops below a certain pressure, the variation of retrograde condensate liquid saturation of the residual reservoir fluid exhibits the phase behavior of volatile oil.
18
Li, Kewen, Changhui Cheng, Changwei Liu, and Lin Jia. "Enhanced oil recovery after polymer flooding by wettability alteration to gas wetness using numerical simulation." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 73 (2018): 33. http://dx.doi.org/10.2516/ogst/2018029.
Full textAbstract:
Polymer flooding, as one of the Enhanced Oil Recovery (EOR) methods, has been adopted in many oilfields in China and some other countries. Over 50% oil remains undeveloped in many oil reservoirs after polymer flooding. It has been a great challenge to find approaches to further enhancing oil recovery when polymer flooding is over. In this study, a new method was proposed to increase oil production using gas flooding with wettability alteration to gas wetness when polymer flooding has been completed. The rock wettability was altered from liquid- to gas-wetness during gas flooding. An artificial oil reservoir was constructed and many numerical simulations have been conducted to test the effect of wettability alteration on the oil recovery in reservoirs developed by water flooding and followed by polymer flooding. Production data from different scenarios, water flooding, polymer flooding after water flooding, gas flooding with and without wettability alteration after polymer flooding, were calculated using numerical simulation. The results demonstrate that the wettability alteration to gas wetness after polymer flooding can significantly enhance oil recovery and reduce water cut effectively. Also studied were the combined effects of wettability alteration and reservoir permeability on oil recovery.
19
Xu, Jianping, Yuanda Yuan, Qing Xie, and Xuegang Wei. "Research on the application of molecular simulation technology in enhanced oil-gas recovery engineering." E3S Web of Conferences 233 (2021): 01124. http://dx.doi.org/10.1051/e3sconf/202123301124.
Full textAbstract:
In recent years, molecular simulations have received extensive attention in the study of reservoir fluid and rock properties, interactions, and related phenomena at the atomistic scale. For example, in molecular dynamics simulation, interesting properties are taken out of the time evolution analysis of atomic positions and velocities by numerical solution of Newtonian equations for all atomic motion in the system. These technologies assists conducting “computer experiments” that might instead of be impossible, very costly, or even extremely perilous to carry out. Whether it is from the primary oil recovery to the tertiary oil recovery or from laboratory experiment to field test, it is difficult to clarify the oil displacement flow mechanism of underground reservoirs. Computer molecular simulation reveals the seepage mechanism of a certain oil displacement at the microscopic scale, and enriches the specific oil displacement flow theory system. And the molecular design and effect prediction of a certain oil-displacing agent were studied, and its role in the reservoir was simulated, and the most suitable oil-displacing agent and the best molecular structure of the most suitable oil-displacing agent were obtained. To give a theoretical basic for the development of oilfield flooding technology and enhanced oil/gas recovery. This paper presents an overview of molecular simulation techniques and its applications to explore enhanced oil/gas recovery engineering research, which will provide useful instructions for characterizing the reservoir fluid and rock and their behaviors in various oil-gas reserves, and it greatly contribute to perform optimal operation and better design of production plants.
20
Faleh, Almanar, and Jalal A. Al-Sudani. "Estimation of Water Breakthrough Using Numerical Simulation." Association of Arab Universities Journal of Engineering Sciences 26, no. 3 (August 31, 2019): 73–81. http://dx.doi.org/10.33261/jaaru.2019.26.3.009.
Full textAbstract:
Water coning is one of the most important phenomena that affect the oil production from oil reservoirs having bottom water aquifers. Empirical model has been developed based on numerical simulator results verified for wide range variation of density difference, viscosity ratio, perforated well interval, vertical to horizontal permeability ratio and well to reservoir radius ratio; the effect of all these parameters on breakthrough time of raising water have been recorded for five different oil flow rate. Since, the model reflects the real situations of reservoir-aquifer zone systems; in which the aquifer has a specific strength to support the reservoir pressure drop depending on its characteristics and water properties. Moreover, the numerical model has been constructed using very fine grids near the wellbore especially in vertical direction, so that very accurate results can be obtained. and (625)runs were performed to generate the breakthrough time model using the numerical simulator verifying all parameters affecting on breakthrough time. The results show that water coning is complex phenomena that depends on all reservoir and fluid properties; the dynamic critical flow rates affected simultaneously by both of the displacing fluid zones. The results show that the breakthrough time of the presented formula provides extreme accuracy with many numerical simulator cases of same reservoir and fluid properties; thus, the suggested formula can be considered as an alternative, quick and easy use tool than numerical simulation models, which consumes time and efforts.
21
Ypma, J. G. J. "Analytical and Numerical Modeling of Immiscible Gravity-Stable Gas Injection Into Stratified Reservoirs." Society of Petroleum Engineers Journal 25, no. 04 (August 1, 1985): 554–64. http://dx.doi.org/10.2118/12158-pa.
Full textAbstract:
Abstract A two-dimensional (2D) analytical model is presented for gas/oil gravity drainage in a homogeneous, dipping reservoir. The sensitivity of gas/oil gravity drainage to key variables such as injection rate, oil relative permeability, and permeability anisotropy can be determined quickly with this model. Example calculations show that miscible-like recovery efficiencies are possible with immiscible gas injection into high-permeability dipping reservoirs with light oil. A procedure based on the analytical model has been developed to simulate immiscible gas injection into highly stratified reservoirs accurately. This simulation procedure allows a great deal of geological detail to be incorporated into reservoir models, because it permits relatively coarse grids. Application of the simulation procedure to a reservoir containing many discontinuous shales reveals that the presence of shales may favorably affect the recovery efficiency of an immiscible gas-injection process. Introduction Gas injection increasingly is being applied as a secondary or tertiary recovery process. High-permeability, light-oil reservoirs with a reasonable reservoir dip are particularly suitable candidates for gas injection. In these reservoirs, a gravity-stable injection scheme is often possible, leading to high sweep efficiencies. If the injection process is carried out at sufficiently high pressure, process is carried out at sufficiently high pressure, favorable phase behavior between reservoir fluid and injection gas can contribute significantly to the recovery of oil. Miscibility, however, is by no means always necessary to obtain high displacement efficiencies. Even in the case of an entirely immiscible displacement, a high displacement efficiency is possible if gravity drainage is the dominant production mechanism. Laboratory experiments have shown that, the residual oil saturation after gas invasion, is virtually zero in highly permeable sandstone cores containing connate water. The ultimate recovery of an immiscible process is then close to 100%. Whether oil saturations process is then close to 100%. Whether oil saturations in the gas-invaded zone will approach the residual value within the lifetime of a particular reservoir depends on the rate of gravity drainage for this reservoir. This problem, which is the main subject of this paper, has been studied by both analytical means and numerical simulation. In the following, first a 2D analytical model is introduced for gas/oil gravity drainage in a homogeneous, dipping reservoir. The model combines aspects from both one-dimensional (1D) vertical Buckley-Leverett drainage theory and Dietz' segregated flow theory for dipping reservoirs. Assumptions underlying the model have been verified by 2D cross-sectional simulations. Second, a procedure based on the analytical gravity-drainage procedure based on the analytical gravity-drainage model has been developed to simulate immiscible secondary gas injection into a highly stratified reservoir accurately. This is illustrated with an example of gas injection into a reservoir containing discontinuous shale layers. Analytical Model for Gravity Drainage Description of the Model. In this section, an approximate analytical model is formulated for immiscible, gravity-stable gas/oil displacement in a homogeneous, dipping layer. Fig. 1 shows a schematic cross section of the draining reservoir with some relevant flow characteristics. In this model, oil is assumed to be produced from downdip wells near the oil/water contact at a rate that ensures a gravity-stable displacement, while gas is injected in updip wells near the crest to fill the voidage. This causes the gas/oil contact (GOC) to move downward gradually. Behind the GOC some oil will be left, the amount of which depends on the oil relative permeability and on the tilt and rate of descent of the GOC. The gas-invaded region will continue to produce oil by after-drainage; this oil will collect at the bottom of the reservoir in a thin oil layer, which flows to the producers with the along-dip component of gravity as driving force. To make the essentially 2D model amenable to analytical calculation, the following assumptions are introduced.The model has infinite gas mobility.The model has negligible gas/oil capillary pressure. pressure.The GOC moves at a constant velocity, v GOC, x, and at a constant tilt angle, given by Dietz' theory for gravity-stable segregated flow in dipping reservoirs (evaluated for infinite gas mobility) as.............(1)with u max, x being the maximum along-dip gravity drainage ratei.e., in the direction of bulk fluid flow. This rate is defined as..............(2) SPEJ p. 554
22
Liu, Zhen Yu, Tian Tian Cai, Hu Zhen Wang, and Cheng Yu Zhang. "Numerical Simulation of Stimulated Volume in Low-Permeability Reservoir." Advanced Materials Research 734-737 (August 2013): 1415–19. http://dx.doi.org/10.4028/www.scientific.net/amr.734-737.1415.
Full textAbstract:
There is an increasing focus on the effective methods to develop low-permeability reservoirs, especially for ultra-low permeability reservoirs. It is hard to achieve the expected stimulation effect only on the traditional single fracturing, because of the poor supply ability from the matrix to fracture in low-permeability reservoirs. Volume stimulating to reservoir, achieving short distance from matrix to fracture because of producing fracture network. So the volume fracturing technology proposed for increasing oil or gas production, this technology is suitable for low porosity and low permeability reservoir. The conventional simulation method can't describe the complex fracture network accurately,but this paper established hydraulic fracturing complex fracture model based on the finite element numerical simulation method , making the simulated complex fracture more close to the real description,it can accurately describe the flow state in the reservoir and cracks.It has an important reference value to the low permeability reservoirs.
23
Tahir, Muhammad, Wei Liu, Asadullah Memon, Hongtao Zhou, Wei Liu, Atif Zafar, Ubedullah Ansari, Imran Akbar, Zhen Yang, and Rui Zhu. "Simulating the strategies of oil field development for enhanced oil recovery." Thermal Science 24, Suppl. 1 (2020): 411–22. http://dx.doi.org/10.2298/tsci200620261t.
Full textAbstract:
Many years have passed in oil field development but primary challenges faced by the X reservoir are the rapid decline of formation pressure and the significant solution gas released from the formation, which impairs production. Based on these challenges, a compositional simulation model of the X reservoir was constructed and run to establish the future development plans. The basic reservoir data collection and processing, quality assurance of the data, characteristic pressure-volume-temperature (PVT) matching by ECLIPSE PVTi, and simulation of various adjustment strategies to forecast development plans, as well as data sensitivity analysis and optimization has been included in this study. In addition, to establish a desirable development plan, the simulation model is set up in great consistency with the geological model resulted from the seismic and logging interpretations. Also, emphases are paid on establishing matches with the reported lab data from production wells by PVTi. Results revealed that the specific reservoir development plan intends to reinstate or maintain formation pressure of the X reservoir. All design and optimization studies are set to comprehend the reservoir with the numerical model.
24
Kurganov, D. V. "OIL RESERVOIR CLASSIFICATION FOR ULTIMATE OIL RECOVERY ESTIMATION BY MEANS OF MACHINE LEARNING." Izvestiya of Samara Scientific Center of the Russian Academy of Sciences 22, no. 5 (2020): 106–13. http://dx.doi.org/10.37313/1990-5378-2020-22-5-106-113.
Full textAbstract:
Oil recovery estimation is the most important tasks after calculation of oil in place and thereafter in oil development plans. There are a lot of appropriate methods for such estimation - displacement coefficient, sweep efficiency, waterflood efficiency, using final well water cut, with respect to fluid mobilities, reservoir thickness and porosity, absolute and relative permeability. Often such parameters are taken from similar nearest reservoirs due to lack of the data. Reservoir simulation is another method for oil recovery estimation although it has many shortcomings. Oil recovery estimation presented in this paper is based on widely known k-means unsupervised machine learning algorytms. Silhouette technics is used for choosing main clusters. Parameter euristics based on local Volga-Ural region data is diveded by clusters for oil recovery. Reservoir classification methodology can dramatically improve ultimate recovery estimation.
25
Zhao, Yang, Shu Tao Lu, Han Gao, and Ying Gong. "Numerical Simulation Research on Improving Effect of Steam Flooding by Using High Permeability Belt." Applied Mechanics and Materials 483 (December 2013): 635–38. http://dx.doi.org/10.4028/www.scientific.net/amm.483.635.
Full textAbstract:
Development of the reservoir in A block of Liaohe Oilfield present compound rhythmreservoirs, high permeability layer among the reservoir, according to the realsituation that high permeability layer exist, for the efficient utilization of producingremaining oil by horizontal well, that need to optimize locations, trajectory, lengthof horizontal well. A fine geological model which reflects the characteristicsof the reservoir in studied area was constructed with Petrel and CMG software. Optimizelocations, trajectory, length of horizontal well and vapor injection parametersupon the history matching. The research result shows that steam override, afterreaching high permeability layer, the steam makes fast breakthrough in highpermeability layer, keeping on upward heating the reservoirs with large contactarea. Finally the reservoirs can be uniformly swept in the vertical direction. Thenumerical simulation accurately predicts the optimized horizontal well can effectiveexpoit the residual oil.
26
Shen, Yedi, and Zhongli Ma. "Acoustics Tomography Simulation for Probing Oil Reservoir." IOP Conference Series: Earth and Environmental Science 310 (September 5, 2019): 032069. http://dx.doi.org/10.1088/1755-1315/310/3/032069.
Full text
27
Matthai, Stephan K. "Reservoir Simulation: Mathematical Techniques in Oil Recovery." Geofluids 8, no. 4 (November 2008): 344–45. http://dx.doi.org/10.1111/j.1468-8123.2008.00220.x.
Full text
28
Ketineni, Sarath Pavan, Subhash Kalla, Shauna Oppert, and Travis Billiter. "Quantitative Integration of 4D Seismic with Reservoir Simulation." SPE Journal 25, no. 04 (April 23, 2020): 2055–66. http://dx.doi.org/10.2118/191521-pa.
Full textAbstract:
Summary Standard history-matching workflows use qualitative 4D seismic observations to assist in reservoir modeling and simulation. However, such workflows lack a robust framework for quantitatively integrating 4D seismic interpretations. 4D seismic or time-lapse-seismic interpretations provide valuable interwell saturation and pressure information, and quantitatively integrating this interwell data can help to constrain simulation parameters and improve the reliability of production modeling. In this paper, we outline technologies aimed at leveraging the value of 4D for reducing uncertainty in the range of history-matched models and improving the production forecast. The proposed 4D assisted-history-match (4DAHM) workflows use interpretations of 4D seismic anomalies for improving the reservoir-simulation models. Design of experiments is initially used to generate the probabilistic history-match simulations by varying the range of uncertain parameters (Schmidt and Launsby 1989; Montgomery 2017). Saturation maps are extracted from the production-history-matched (PHM) simulations and then compared with 4D predicted swept anomalies. An automated extraction method was created and is used to reconcile spatial sampling differences between 4D data and simulation output. Interpreted 4D data are compared with simulation output, and the mismatch generated is used as a 4D filter to refine the suite of reservoir-simulation models. The selected models are used to identify reservoir-simulation parameters that are sensitive for generating a good match. The application of 4DAHM workflows has resulted in reduced uncertainty in volumetric predictions of oil fields, probabilistic saturation S-curves at target locations, and fundamental changes to the dynamic model needed to improve the match to production data. Results from adopting this workflow in two different deepwater reservoirs are discussed. They not only resulted in reduced uncertainty, but also provided information on key performance indicators that are critical in obtaining a robust history match. In the first case study presented, the deepwater oilfield 4DAHM resulted in a reduction of uncertainty by 20% of original oil in place (OOIP) and by 25% in estimated ultimate recoverable (EUR) oil in the P90 to P10 range estimates. In the second case study, 4DAHM workflow exploited discrepancies between 4D seismic and simulation data to identify features necessary to be included in the dynamic model. Connectivity was increased through newly interpreted interchannel erosional contacts, as well as subseismic faults. Moreover, the workflow provided an improved drilling location, which has the higher probability of tapping unswept oil and better EUR. The 4D filters constrained the suite of reservoir-simulation models and helped to identify four of 24 simulation parameters critical for success. The updated PHM models honor both the production data and 4D interpretations, resulting in reduced uncertainty across the S-curve and, in this case, an increased P50 OOIP of 24% for a proposed infill drilling location, plus a significant cycle-time savings.
29
Ladron de Guevara-Torres, Juan Ernesto, Fernando Rodriguez-de la Garza, and Agustin Galindo-Nava. "Gravity-Drainage and Oil-Reinfiltration Modeling in Naturally Fractured Reservoir Simulation." SPE Reservoir Evaluation & Engineering 12, no. 03 (May 31, 2009): 380–89. http://dx.doi.org/10.2118/108681-pa.
Full textAbstract:
Summary The gravity-drainage and oil-reinfiltration processes that occur in the gas-cap zone of naturally fractured reservoirs (NFRs) are studied through single porosity refined grid simulations. A stack of initially oil-saturated matrix blocks in the presence of connate water surrounded by gas-saturated fractures is considered; gas is provided at the top of the stack at a constant pressure under gravity-capillary dominated flow conditions. An in-house reservoir simulator, SIMPUMA-FRAC, and two other commercial simulators were used to run the numerical experiments; the three simulators gave basically the same results. Gravity-drainage and oil-reinfiltration rates, along with average fluid saturations, were computed in the stack of matrix blocks through time. Pseudofunctions for oil reinfiltration and gravity drainage were developed and considered in a revised formulation of the dual-porosity flow equations used in the fractured reservoir simulation. The modified dual-porosity equations were implemented in SIMPUMA-FRAC (Galindo-Nava 1998; Galindo-Nava et al. 1998), and solutions were verified with good results against those obtained from the equivalent single porosity refined grid simulations. The same simulations--considering gravity drainage and oil reinfiltration processes--were attempted to run in the two other commercial simulators, in their dual-porosity mode and using available options. Results obtained were different among them and significantly different from those obtained from SIMPUMA-FRAC. Introduction One of the most important aspects in the numerical simulation of fractured reservoirs is the description of the processes that occur during the rock-matrix/fracture fluid exchange and the connection with the fractured network. This description was initially done in a simplified manner and therefore incomplete (Gilman and Kazemi 1988; Saidi and Sakthikumar 1993). Experiments and theoretical and numerical studies (Saidi and Sakthikumar 1993; Horie et al. 1998; Tan and Firoozabadi 1990; Coats 1989) have allowed to understand that there are mechanisms and processes, such as oil reinfiltritation or oil imbibition and capillary continuity between matrix blocks, that were not taken into account with sufficient detail in the original dual-porosity formulations to model them properly and that modify significantly the oil-production forecast and the ultimate recovery in an NFR. The main idea of this paper is to study in further detail the oil reinfiltration process that occurs in the gas invaded zone (gas cap zone) in an NFR and to evaluate its modeling to implement it in a dual-porosity numerical simulator.
30
Kortekaas, T. F. M. "Water/Oil Displacement Characteristics in Crossbedded Reservoir Zones." Society of Petroleum Engineers Journal 25, no. 06 (December 1, 1985): 917–26. http://dx.doi.org/10.2118/12112-pa.
Full textAbstract:
Kortekaas, T.F.M., SPE, Shell Research B.V. Abstract Festoon crossbedding is a typical sedimentary structure in sandstone reservoirs. It is especially common in fluvial deposits. The important elements are the foreset laminae, which vary in permeability, and the bottomsets of lower permeability. To understand the complex, direction-dependent displacement characteristics of a crossbedded reservoir zone, we first conducted numerical simulations on a centimeter scale in a small part of a water-wet crossbedded reservoir zone. The simulations indicate that, during water/oil displacement, considerable amounts of movable oil initially are left behind in the higher-permeability foreset laminae with fluid flow perpendicular to the foreset laminae, while with flow parallel to the foreset laminae the displacement efficiency is good. To describe the displacement characteristics on a reservoir scale, we developed a procedure for calculating direction-dependent pseudo relative-permeability and capillary-pressure curves to be used as input for the simulations of water/oil displacement in a crossbedded reservoir zone. On a reservoir scale, the displacement characteristics in a water-wet crossbedded reservoir zone are slightly more favorable with the main fluid flow perpendicular to the foreset laminae. perpendicular to the foreset laminae. In addition, the sensitivity of the displacement characteristics to moderate reductions in interfacial tensions (IFT's) and to increases in water viscosity was investigated, both on a centimeter scale and on a reservoir scale. The simulations indicate the potential for substantial improvement in recovery from crossbedded reservoir zones if diluted surfactant or polymer is added to the drive water. Introduction Detailed studies of the effect of reservoir heterogeneities on water/oil displacement characteristics have been conducted on a well-to-well (layering) scale and on a pore scale, but few studies on an intermediate scale have been done. Therefore, we embarked on a study of the effect of centimeter-scale heterogeneities on water/oil displacement characteristics. We studied festoon crossbedding, one of the typical sedimentary structures in sandstone reservoirs, particularly common in fluvial deposits. A schematic particularly common in fluvial deposits. A schematic representation of a small part of a crossbedded reservoir zone is given in Fig. 1A. The important elements are the foreset laminae, which vary in permeability, and the bottom-sets, which are of lower permeability. The width of the foreset laminae is exaggerated in Fig. 1A; typically it is a few centimeters. First, we will discuss a mathematical simulation study in a very limited area of a water-wet crossbedded reservoir zone (1.97 × 26.2 × 0.66 ft [0.6 × 8 × O.2 m]). After a brief discussion of the water/oil displacement characteristics near a single permeability transition, we present the water/oil displacement characteristics in some cross sections of a simplified model (Fig. 1B) of a small part of a crossbedded reservoir zone. In addition, their sensitivity to moderate reductions in IFT's and increases in water viscosity are discussed. Second, we describe the effect of crossbedding on water/oil displacement characteristics on a reservoir scale, discuss a procedure for calculating dynamic, direction-dependent pseudo relative-permeability and capillary-pressure curves, and present the results of a reservoir-scale mathematical simulation study, including the pseudo-properties. Also, the sensitivity of the results to changes pseudo-properties. Also, the sensitivity of the results to changes in IFT and water viscosity is discussed. One-Dimensional Water/Oil Displacement Characteristics Near an Abrupt Permeability Transition Permeability Transition suppose we have a one-dimensional (1D) system consisting of two zones with different absolute, but identical relative, permeabilities. Furthermore, the system is horizontal and contains oil and connate water. The Buckley-Leverett first-order partial differential equation describes the water/oil displacement in each zone.In the absence of capillary and gravitational forces, the water fractional flow Fwo) is given byEq. 1, together with Eq. 2, usually leads to a sharp shock front: at each location, water saturation will instantaneously jump from connate water to shock-front saturation when the water arrives. SPEJ p. 917
31
Cusandei, Rodrigo Mendes Batista. "SAGD process: a match up simulation and grid sensitivity analysis." Latin American Journal of Energy Research 1, no. 1 (June 26, 2014): 21–29. http://dx.doi.org/10.21712/lajer.2014.v1.n1.p21-29.
Full textAbstract:
The use of fuel from bitumen has become highly demanded in the past years not only in Canada, but in many other countries, and it will still be one of the main sources of energy in the next decades. Also, new technologies for the exploration of these reserves are also being highly stimulated to achieve the huge amount of oil found in these reservoirs. For oil sands in Canada, the SAGD process is vastly used by all companies. It involves two horizontal parallels wells, usually located 5 meters apart from one another, one for the injection of steam, and the other for the producer of the heated oil. In this paper, two cases were analyzed, one is a match up reservoir simulation with a previous case paper, and the other is a grid sensitivity analysis for a new reservoir model. All the simulations were performed by CMG STARS simulator. For the match up case, it is noticed that every parameter is important in order to have similar plots in both simulations. Some parameters were used as default values; therefore, some results were slightly different. For the grid sensitivity case, the grid distribution plays a role in the results. Although the results were slightly shifted to one another, it can be seen that, the finer is the reservoir, the more detailed the results are. Plots such as cumulative oil, water and oil rates were shown in order to give a complete conclusion about the model in analysis.
32
WANG, XIXIN, JIAGEN HOU, YUMING LIU, PEIQIANG ZHAO, KE MA, DONGMEI WANG, XIAOXU REN, and LIN YAN. "OVERALL PSD AND FRACTAL CHARACTERISTICS OF TIGHT OIL RESERVOIRS: A CASE STUDY OF LUCAOGOU FORMATION IN JUNGGAR BASIN, CHINA." Fractals 27, no. 01 (February 2019): 1940005. http://dx.doi.org/10.1142/s0218348x1940005x.
Full textAbstract:
Lucaogou tight oil reservoir, located in the Junggar Basin, Northwest of China, is one of the typical tight oil reservoirs. Complex lithology leads to a wide pore size distribution (PSD), ranging from several nanometers to hundreds of micrometers. To better understand PSD and fractal features of Lucaogou tight oil reservoir, the experiment methods including scanning electron microscope (SEM), rate-controlled mercury injection (RMI) and pressure-controlled mercury injection (PMI) were performed on the six samples with different lithology. The results indicate that four types of pores exist in Lucaogou tight oil reservoir, including dissolution pores, clay dominated pores, microfractures and inter-granular pores. A combination of PMI and RMI was proposed to calculate the overall PSD of tight oil reservoirs, the overall pore radius of Lucaogou tight oil reservoir ranges from 3.6[Formula: see text]nm to 500[Formula: see text][Formula: see text]m. The fractal analysis was carried out based on the PMI data. Fractal dimension (Fd) values varied between 2.843 and 2.913 with a mean value of 2.88. Fd increases with a decrease of quartz content and an increase of clay mineral content. Samples from tight oil reservoirs with smaller average pore radius have stronger complexity of pore structure. Fractal dimension shows negative correlations with porosity and permeability. In addition, fractal characteristics of different tight reservoirs were compared and analyzed.
33
Al Awami, Bassam A., Kesavalu Hemanthkumar, Fatema H. Al-Awami, and Mansour MohammedAli. "Application of Stream Conversion Methods to Generate Compositional Streams From the Results of a Multi-Million Cell Black Oil Simulation Study of the Shaybah Field." SPE Reservoir Evaluation & Engineering 8, no. 04 (August 1, 2005): 310–14. http://dx.doi.org/10.2118/84361-pa.
Full textAbstract:
Summary Detailed compositional simulation of a giant reservoir with many components is not practical. However, detailed multimillion-cell black-oil simulation of giant reservoirs is now quite feasible. In this work, we apply an efficient method to generate the compositional rates from a black-oil simulation of the giant Shaybah field. In situations in which the reservoir recovery mechanism is not dominated by compositional effects, an equation-of-state (EOS) -based stream-conversion method can be used. This stream-conversion method relies on the fact that when laboratory pressure/volume/temperature (PVT) data measured on available well-stream compositions are used to generate the black-oil PVT tables, some of the compositional information is lost. The stream-conversion model retains this valuable compositional information and applies it to each producing-wellcompletion in the black-oil simulation at every timestep. As proof of the concept, the stream-conversion method was applied to a black-oil simulation and to a limited (eight-component) compositional simulation to generate a 17-component compositional stream, and the results were compared to the respective full EOS compositional simulation for a relatively small sector (250,000 cells) of the giant Shaybah field. The compositional stream rates are in excellent agreement with the stream-converted black-oil results. As would be expected, the computational costs of using the EOS-based compositional simulator (with 17 components) are in excess of 40times the black-oil-simulation time for the small-sector model. In general, the stream-conversion method can be used to generate the dynamically varying compositional streams from any black-oil simulation for use in the design and operation of surface facilities and in calculating the amounts of a certain cut[e.g., natural gas liquids (NGL)] from the production streams. Introduction Recent advances in parallel-reservoir-simulation technology have made it feasible to model the performance of giant hydrocarbon reservoirs with simulation models that retain the full geologic-model resolution. The semultimillion-cell simulation/geologic models, when carefully conditioned to engineering data, lend themselves to rapid history matching, despite their size. More importantly, they are used actively in optimizing field development with more confidence and in day-to-day reservoir management. The above-mentioned multimillion-cell simulation models use a black-oil treatment of the hydrocarbon fluids. Where compositional treatment of the hydrocarbon fluids is desired, a conventional full EOS-based compositional simulation of a giant hydrocarbon reservoir with many components is not yet practical. In this work, we apply an efficient method to generate the compositional rates from a black-oil simulation of the giant Shaybah field. The theoretical basis for this method is presented in detail in Ref. 7. Herein, we present only the pertinent information to elucidate its application in this work.
34
Al-Rumhy, M., A. Al-Bemani, and F. Boukadi. "Effect of Compositional Grading On reservoir Performance." Sultan Qaboos University Journal for Science [SQUJS] 1, no. 1 (January 1, 1996): 37. http://dx.doi.org/10.24200/squjs.vol1iss1pp37-45.
Full textAbstract:
In reservoirs with thickness exceeding fifty meters, compositional guiding has been found to cause significant variation in performance. Main fluid properties, governing the magnitude of reservoir performance, such as density; formation volume factor and fluid viscosity experience variation due to varying fluid composition along the hydrocarbon column. These variations cause erroneous estimation of stock-tank oil in place and may infer reservoir engineers to consider inappropriate secondary oil recovery methods, for example. In the presence of gravity segregation within the oil column, heavy ends will form a heavy oil blanket in the lower part of the reservoir. Such a scenario may result in poor displacement and an earlier breakthrough when water drive is the dominant fluid flow mechanism. In this paper reservoir performance due to varying reservoir fluid composition has been examined using reservoir simulation analysis and recommendations for better characterization of reservoir fluid sampling are outlined.
35
Ghedan, Shawket G., Bertrand M. Thiebot, and Douglas A. Boyd. "Modeling Original Water Saturation in the Transition Zone of a Carbonate Oil Reservoir." SPE Reservoir Evaluation & Engineering 9, no. 06 (December 1, 2006): 681–87. http://dx.doi.org/10.2118/88756-pa.
Full textAbstract:
Summary Accurately modeling water-saturation variation in transition zones is important to reservoir simulation for predicting recoverable oil and guiding field-development plans. The large transition zone of a heterogeneous Middle East reservoir was challenging to model. Core-calibrated, log-derived water saturations were used to generate saturation-height-function groups for nine reservoir-rock types. To match the large span of log water saturation (Sw) in the transition zone from the free-water level (FWL) to minimum Sw high in the oil column, three saturation-height functions per rock type (RT) were developed, one each for the low-, medium-, and high-porosity range. Though developed on a different scale from the simulation-model cells, the saturation profiles generated are a good statistical match to the wireline-log-interpreted Sw, and bulk volume of water (BVW) and fluid volumetrics agree with the geological model. RT-guided saturation-height functions proved a good method for modeling water saturation in the simulation model. The technique emphasizes the importance of oil/brine capillary pressures measured under reservoir conditions and of collecting an adequate number of Archie saturation and cementation exponents to reduce uncertainties in well-log interpretation. Introduction The heterogeneous carbonate reservoir in this study is composed of both limestone and dolomite layers frequently separated by non-reservoir anhydrite layers (Ghedan et al. 2002). Because of its heterogeneity, this reservoir, like other carbonate reservoirs, contains long saturation-transition zones of significant sizes. Transition zones are conventionally defined as that part of the reservoir between the FWL and the level at which water saturation reaches a minimum near-constant (irreducible water saturation, Swirr) high in the reservoir (Masalmeh 2000). For the purpose of this paper, however, we define transition zones as those parts of the reservoir between the FWL and the dry-oil limit (DOL), where both water and oil are mobile irrespective of the saturation level. Both water and oil are mobile in the transition zone, while only oil is mobile above the transition zone. By either definition, the oil/water transition zone contains a sizable part of this field's oil in place. Predicting the amount of recoverable oil in a transition zone through simulation depends on (among other things) the distribution of initial oil saturation as a function of depth as well as the mobility of the oil in these zones (Masalmeh 2000). Therefore, the characterization of transition zones in terms of original water and oil distribution has a potentially large effect on reservoir recoverable reserves and, in turn, reservoir economics.
36
Batalov, S. A., V. E. Andreev, V. M. Lobankov, and V. Sh Mukhametshin. "Numerical simulation of the oil reservoir with regulated disturbances. Oil recovery stability simulation." Journal of Physics: Conference Series 1333 (October 2019): 032007. http://dx.doi.org/10.1088/1742-6596/1333/3/032007.
Full text
37
Wu, Jun Lai, Yue Tian Liu, and Hai Ning Yang. "Parameters Optimization of Stereoscopic Horizontal Well Patterns by Using Numerical Reservoir Simulation." Advanced Materials Research 433-440 (January 2012): 2602–6. http://dx.doi.org/10.4028/www.scientific.net/amr.433-440.2602.
Full textAbstract:
Well pattern is the most important affecting factor to the ultimate recovery for an oilfield development. Many researches are reported on areal well pattern, which is widely used in conventional reservoirs development such as low permeability reservoirs, heavy oil reservoirs, multi-layer sandstone reservoirs, etc. In this paper, according to the geological characteristics of fractured buried hill reservoir of Liaohe Oilfield, we firstly present the concept of stereoscopic well patterns and compare it with common areal water flooding. By using numerical reservoir simulation method, we design and optimize the parameters of 5-spot stereoscopic horizontal well patterns, including payzone thickness and horizontal well length under different anisotropic factors of fracture permeability. This can be successfully applied on the development of MM block fractured buried hill reservoir of Liaohe Oilfield.
38
Rita, Novia. "Analisis Sensitivitas Salinitas dan Adsorbsi Injeksi Surfaktan-Polimer Menggunakan Simulasi Reservoir Pada Reservoir Berlapis Lapangan NA." Journal of Earth Energy Engineering 5, no. 2 (October 12, 2016): 1–17. http://dx.doi.org/10.22549/jeee.v5i2.476.
Full textAbstract:
Increasing the time, the condition of the oil in reservoir increasingly difficult for production to the surface, this is caused by diminishing reservoir pressure and the condition of a viscous oil. While the technology used can no longer urged oil to surface. NA field is a field that is old, the production process is done on the field NA has been through the stages of primary and secondary recovery, where this stage is not optimal in increasing oil production on the field. While OOIP on the field is still economically viable. Of screening criteria that has been done on NA Field, the oil production stage to do next is to EOR method. The EOR methods that can be applied is by chemical injection method of surfactant and polymer. Before the surfactant and polymer injection method performed on NA Field, the first done through the stages of planning reinjection reservoir simulation. Fields of reservoir simulation models NA will be analyzed four skenarios conducted for sensitivity to salinity and adsorption of surfactant-polymer. Skenario 1 simulation with values varying salinity, Skenario 2 adsorption value simulation with different surfactants, Skenario 3 sensitivity to polymer adsorption, Skenario 4 see changes impairment influences the permeability to polymer injection. The results of all four skenarios simulations obtained optimum value of cumulative production of 72 548 STB with a recovery factor (RF) of 30.9% at the price of 0.075 surfactant salinity mEq / ml, adsorption of surfactant 0.3 mEq / ml, 0.1 wt polymer adsorption % cuft, and changes in permeability due to 80wt% polymer solution cuft.
39
Goldthorpe, W. H., and J. K. Drohm. "APPLICATION OF THE BLACK OIL PVT REPRESENTATION TO SIMULATION OF GAS CONDENSATE RESERVOIR PERFORMANCE." APPEA Journal 27, no. 1 (1987): 370. http://dx.doi.org/10.1071/aj86032.
Full textAbstract:
Special attention must be paid to the generation of PVT parameters when applying conventional black oil reservoir simulators to the modelling of volatile oil and gas-condensate reservoirs. In such reservoirs phase behaviour is an important phenomenon and common approaches to approximating this, via the black oil PVT representation, introduce errors that may result in prediction of incorrect recoveries of surface gas and condensate. Further, determination of production tubing pressure drops for use in such simulators is also prone to errors. These affect the estimation of well potentials and reservoir abandonment pressures.Calculation of black oil PVT parameters by the method of Coats (1985) is shown to be preferred over conventional approaches, although the PVT parameters themselves lose direct physical meaning. It is essential that a properly tuned equation of state be available for use in conjunction with experimental data.Production forecasting based on simulation output requires further processing in order to translate the black oil surface phase fluxes into products such as sales gas, LPG and condensate. For gas-condensate reservoirs, such post-processing of results from the simulation of depletion or cycling above the dew point is valid. In principle it is invalid for cycling below the dew point but in practice it can still provide useful information.
40
Sauvageau, Mathieu, Erwan Gloaguen, Maxime Claprood, René Lefebvre, and Martin Bêche. "Multimodal reservoir porosity simulation: An application to a tight oil reservoir." Journal of Applied Geophysics 107 (August 2014): 71–79. http://dx.doi.org/10.1016/j.jappgeo.2014.05.007.
Full text
41
Chen, Qing, Morten Kristensen, Yngve Bolstad Johansen, Vladislav Achourov, Soraya S. Betancourt, and Oliver Mullins. "Analysis of Lateral Fluid Gradients From DFA Measurements and Simulation of Reservoir Fluid Mixing Processes Over Geologic Time." Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description 62, no. 1 (February 1, 2021): 16–30. http://dx.doi.org/10.30632/pjv62n1-2021a1.
Full textAbstract:
Downhole fluid analysis (DFA) is one pillar of reservoir fluid geodynamics (RFG). DFA measurements provide both vertical and lateral fluid gradient data. These gradients, especially the asphaltene gradient derived from accurate optical density (OD) measurements, are critical in thermodynamic analysis to assess equilibration level and identify RFG processes. Recently, an RFG study was conducted using DFA and laboratory data from an oil field in the Norwegian North Sea. Fluid OD gradients show equilibrated asphaltenes in most of the reservoir, with a lateral variation of 20%. This indicates connectivity, which is confirmed by three years of production data. Two outliers are off the asphaltene equilibrium curve implying isolated sections, one each on the extreme east and west flank. Their asphaltene fraction varies by a factor of six. Such a difference reveals that different charge fluids entered the reservoir, and the equilibrated asphaltenes are the result of an after-charge mixing process. Meanwhile, different gas-oil contacts (GOCs) exist in the reservoir, indicating a lateral solution-gas gradient. Geochemistry analysis shows the same level of mild biodegradation in all the fluid samples, including those from two isolated sections. This means that biodegraded oil spills into the whole reservoir with little or no in-reservoir biodegradation. Furthermore, lateral asphaltene gradients at different times after charge have been preserved; it was a factor of six in asphaltenes content initially and is now 20% in the present day. This unique data set provides a valuable constraint to simulate reservoir fluid after-charge mixing processes to present day, aiming to investigate the factors impacting the evolution of lateral composition gradients in geologic time in a connected reservoir. Numerical simulations were performed over geologic time in reservoirs filled by oil with a lateral density gradient, which imitates the lateral compositional gradients in the gas-oil ratio (GOR) and asphaltenes measured in the above oil field. Simulations show that this lateral gradient creates lateral differential pressures and causes a countercurrent fluid flow forming a convection cell. In reservoirs with realistic vertical-to-horizontal aspect ratios, such fluid flows are not rapid, and lateral gradients can be partially retained in moderate geologic times. Additionally, diffusion was included in the simulation. The reservoir model was initialized with two GOCs producing subtle lateral GOR and density gradients. The simulated mixing process transports gas from higher GOR regions to lower GOR regions and reduces the GOC difference. However, the flux of solution gas transport is small. Consequently, we conclude that lateral GOR and asphaltene gradients can persist for moderate geologic time, which is consistent with observation from the field.
42
Jassim, Ayat Ahmed, Abdul Aali Al-dabaj, and Aqeel S. AL-Adili. "Water Injection for Oil Recovery in Mishrif Formation for Amarah Oil Field." Iraqi Journal of Chemical and Petroleum Engineering 21, no. 1 (March 29, 2020): 39–44. http://dx.doi.org/10.31699/ijcpe.2020.1.6.
Full textAbstract:
The water injection of the most important technologies to increase oil production from petroleum reservoirs. In this research, we developed a model for oil tank using the software RUBIS for reservoir simulation. This model was used to make comparison in the production of oil and the reservoir pressure for two case studies where the water was not injected in the first case study but adding new vertical wells while, later, it was injected in the second case study. It represents the results of this work that if the water is not injected, the reservoir model that has been upgraded can produce only 2.9% of the original oil in the tank. This case study also represents a drop in reservoir pressure, which was not enough to support oil production. Thus, the implementation of water injection in the second case study of the average reservoir pressure may support, which led to an increase in oil production by up to 5.5% of the original oil in the tank. so that, the use of water injection is a useful way to increase oil production. Therefore, many of the issues related to this subject valuable of study where the development of new ideas and techniques.
43
Wu, Yun Qiang, Jing Song Li, Xin Hong Zhang, Jian Zhou, and Tong Jing Liu. "Numerical Simulation of Low-Permeability Fractured Reservoirs on Imbibition." Advanced Materials Research 712-715 (June 2013): 792–95. http://dx.doi.org/10.4028/www.scientific.net/amr.712-715.792.
Full textAbstract:
Low permeability fractured reservoir is a special reservoir with complex fracture distribution and dense matrix. Low permeability fractured reservoir always have small porosity, low pore pressure and permeability. Therefore, low permeability fractured reservoir has low oil recovery efficiency. Besides, the developing complex process and higher costs lead to lower economic benefit. Low permeability fractured reservoir production mechanisms in the fracture system mainly by the capillary force of water into the matrix. Therefore, the hydrophilic blocks of dense, self-priming effect of capillary water is the main mechanism of oil. In this study, numerical simulation, the establishment of a dual media model analysis showed that the capillary suction from the oil production rate and the final volume flow channel structure, the capillary force, viscosity of crude oil and other factors.
44
Ghorayeb, Kassem, and Jonathan Anthony Holmes. "Black Oil Delumping Techniques Based on Compositional Information from Depletion Processes." SPE Reservoir Evaluation & Engineering 10, no. 05 (October 1, 2007): 489–99. http://dx.doi.org/10.2118/96571-pa.
Full textAbstract:
Summary Black-oil reservoir simulation still has wide application in the petroleum industry because it is far less demanding computationally than compositional simulation. But a principal limitation of black-oil reservoir simulation is that it does not provide the detailed compositional information necessary for surface process modeling. Black-oil delumping overcomes this limitation by converting a black-oil wellstream into a compositional wellstream, enabling the composition and component molar rates of a production well in a black-oil reservoir simulation to be reconstituted. We present a comprehensive black-oil delumping method based primarily on the compositional information generated in the depletion process that is used initially to provide data for the black-oil simulation in a typical workflow. Examples presented in this paper show the accuracy of this method in different depletion processes: natural depletion, water injection, and gas injection. The paper also presents a technique for accurately applying the black-oil delumping method to wells encountering crossflow. Introduction With advances in computing speed, it is becoming more typical to use a fully compositional fluid description in hydrocarbon reservoir simulation. However, the faster computers become, the stronger the simulation engineer's tendency to build more challenging (and thus more CPU intensive) models. Compositional simulation in today's multi-million-cell models is still practically unfeasible. Black-oil fluid representation is a proven technique that continues to find wide application in reservoir simulation. However, an important limitation of black-oil reservoir simulation is the lack of detailed compositional information necessary for surface process modeling. The black-oil delumping technique described in this paper provides the needed compositional information, yet adds negligible computational time to the simulation. Delumping a black-oil wellstream consists of retrieving the detailed components' molar rates to convert the black-oil wellstream into a compositional wellstream. It reconstitutes the composition and component molar rates of the production stream. Black-oil delumping can be achieved with differing degrees of accuracy by using options ranging from setting a constant oil and gas composition for the whole run to using the results of a depletion process: constant-volume depletion (CVD), constant-composition expansion (CCE), and differential liberation (DL). The simplest method is to assign a fixed composition (component mole fraction) to stock-tank oil and gas. This could be applied over the whole reservoir, or, if the hydrocarbon mixture properties vary across the reservoir, different oil and gas compositions can be reassigned at any time during the run. Some black-oil simulators have an API tracking feature that allows oils of different properties to mix within the reservoir. The pressure/volume/temperature (PVT) properties of the oil mixture are parameterized with the oil surface density. To provide a delumping option compatible with the API tracking, stock-tank oil and gas compositions may be tabulated against the density of oil at surface conditions.
45
Gu, Qing Jie. "Simulation Study of Steam-Flooding Mechanisms and Influence Factors in Light-Oil Reservoirs after Water-Flooding." Applied Mechanics and Materials 508 (January 2014): 165–68. http://dx.doi.org/10.4028/www.scientific.net/amm.508.165.
Full textAbstract:
Steam-flooding, the most successful among enhanced recovery methods, has been applied mainly to heavy-oil reservoirs. And it is still in its infancy on light-oil reservoirs at present. This paper will take the oil-water transition zone in Saertu oilfield for example, presents a comprehensive simulation study on the use of steam-flooding after water-flood in light-oil reservoirs. Some important observations are made on this new application of the process. Relative importance of key mechanisms to oil recovery is also discussed. Guidelines are developed not only for selecting reservoir candidates for steam-flooding, but also for the factors which will effect the oil recovery in steam-flooding performance.
46
Hoffman, B. Todd, and David Reichhardt. "Recovery Mechanisms for Cyclic (Huff-n-Puff) Gas Injection in Unconventional Reservoirs: A Quantitative Evaluation Using Numerical Simulation." Energies 13, no. 18 (September 21, 2020): 4944. http://dx.doi.org/10.3390/en13184944.
Full textAbstract:
Unconventional reservoirs produce large volumes of oil; however, recovery factors are low. While enhanced oil recovery (EOR) with cyclic gas injection can increase recovery factors in unconventional reservoirs, the mechanisms responsible for additional recovery are not well understood. We examined cyclic gas injection recovery mechanisms in unconventional reservoirs including oil swelling, viscosity reduction, vaporization, and pressure support using a numerical flow model as functions of reservoir fluid gas–oil ratio (GOR), and we conducted a sensitivity analysis of the mechanisms to reservoir properties and injection conditions. All mechanisms studied contributed to the additional recovery, but their significance varied with GOR. Pressure support provides a small response for all fluid types. Vaporization plays a role for all fluids but is most important for gas condensate reservoirs. Oil swelling impacts low-GOR oils but diminishes for higher-GOR oil. Viscosity reduction plays a minor role for low-GOR cases. As matrix permeability and fracture surface area increase, the importance of gas injection decreases because of the increased primary oil production. Changes to gas injection conditions that increase injection maturity (longer injection times, higher injection rates, and smaller fracture areas) result in more free gas and, for these cases, vaporization becomes important. Recovery mechanisms for cyclic gas injection are now better understood and can be adapted to varying conditions within unconventional plays, resulting in better EOR designs and improved recovery.
47
Fubara, Franklin, Nnamdi J. Ajah, Jude U. Igweajah, Olayinka Yinka, Abdulmaliq Abdulsalam, and Paul Mogaba. "Reducing Uncertainties in Hydrocarbon Volumetric Estimation: A Case Study of Fuba Field, Onshore Niger Delta." European Journal of Engineering and Technology Research 6, no. 2 (February 19, 2021): 118–27. http://dx.doi.org/10.24018/ejers.2021.6.2.2259.
Full textAbstract:
Reducing uncertainties to the barest minimum before reserve estimation aids in making a better decision regarding field development. This study analyses uncertainty in hydrocarbon reserve estimation in Fuba Field using both scenario-based deterministic and stochastic methods. Two hydrocarbon reservoirs (A and I) were selected and mapped. Depth structure maps revealed fault supported collapsed crestal closures for both reservoirs. Uncertainty analysis was conducted using low case (P90), base case (P50), and the high case (P50) reservoir properties. On average, porosity, NTG and Sw are 31%, 89%, 10%, and 24%, 84%, 23% for A and I reservoirs. Hydrocarbon volumes recorded for the high case, base case, and low case using a deterministic versus stochastic approach are 30.52 MMSTB, 12.46 MMSTB, 4.57 MMSTB, and 18.52 MMSTB, 13.59 MMSTB, and 9.40 MMSTB for reservoir A, 58.87 MMSTB, 10.94 MMSTB, 1.51 MMSTB, and 25.56 MMSTB, 14.59 MMSTB and 7.63 MMSTB for reservoir I. While the base case was similar for both methods (stochastic and deterministic), there is a huge difference in the low and high-case hydrocarbon volumes recorded in both methods. This change could be attributed to the reservoir bulk volume with (>85%) with little contribution from oil saturation and porosity. Cross plot analysis confirms that bulk volume is the main control of the estimated stock tank original oil in place (STOIIP). Hence, a slight alteration in bulk volume will significantly affect the estimated STOIIP. It is recommended that bulk volume be given most attention when conducting reservoir simulation as this will increase simulation time, reduce simulation cost, and provide more accurate simulation results.
48
King, G. R., W. David, T. Tokar, W. Pape, S. K. Newton, J. Wadowsky, M. A. Williams, R. Murdoch, and M. Humphrey. "Takula Field: Data Acquisition, Interpretation, and Integration for Improved Simulation and Reservoir Management." SPE Reservoir Evaluation & Engineering 5, no. 02 (April 1, 2002): 135–45. http://dx.doi.org/10.2118/77610-pa.
Full textAbstract:
Summary This paper discusses the integration of dynamic reservoir data at the flow-unit scale into the reservoir management and reservoir simulation efforts of the Takula field. The Takula field is currently the most prolific oil field in the Republic of Angola. Introduction The Takula field is the largest producing oil field in the Republic of Angola in terms of cumulative oil production. It is situated in the Block 0 Concession of the Angolan province of Cabinda. It is located approximately 25 miles offshore in water depths ranging from 170 to 215 ft. The field consists of seven stacked, Cretaceous reservoirs. The principal oil-bearing horizon is the Upper Vermelha reservoir. This paper discusses the data acquisition and integration for this reservoir only. The reservoir was discovered in January 1980 with Well 57- 02X. Primary production from the reservoir began in December 1982. The reservoir was placed on a peripheral waterflood in December 1990. Currently, the Upper Vermelha reservoir accounts for approximately 75% of the production from the field. Sound management of mature waterfloods has been identified as a key to maximizing the ultimate recovery and delivering the highest value from the Block 0 Asset.1 Therefore, the objective of the simulation effort was to develop a tool for strategic and dayto- day reservoir management with the intent of managing and optimizing production on a flow-unit basis. Typical day-to-day management activities include designing workovers, identifying new well locations, optimizing injection well profiles, and optimizing sweep efficiencies. To perform these activities, decisions must be made at the scale of the individual flow units. In general, fine-grid geostatistical models are developed from static data, such as openhole log data and core data. Recent developments in reservoir characterization have allowed for the incorporation of some dynamic data, such as pressure-transient data and 4D seismic data, into the geostatistical models. Unfortunately, pressure-transient data are acquired at a test-interval scale (there are typically 3 to 4 test intervals per well, depending on the ability to isolate different zones mechanically in the wellbore), while seismic data are acquired at the reservoir scale. The reservoir surveillance program in the Takula field routinely acquires data at the flow-unit scale. These data include openhole log and wireline pressure data from newly drilled wells and casedhole log and production log (PLT) data from producing/injecting wells. Because of the time-lapse nature of cased-hole log and PLT data, they represent dynamic reservoir data at the flow-unit scale. To achieve the objectives of the modeling effort and optimize production on a flow-unit basis, these dynamic data must be incorporated into the simulation model at the appropriate scale. When these data are incorporated into a simulation model, it is typically done during the history match. There are, however, instances when these data are incorporated during other phases of the study. The objective of this paper, therefore, is to discuss the methods used to integrate the dynamic reservoir data acquired at the flow-unit scale into the Upper Vermelha reservoir simulation model. Reservoir Geology The geology of the Takula field is described in detail in Ref. 2. The aspects of the reservoir geology that are pertinent to this paper are elaborated in this section. Reservoir Stratigraphy. The Takula field consists of seven stacked reservoirs. The principal oil-bearing horizon is the Upper Vermelha reservoir. This reservoir contains an undersaturated, 33°API crude oil. For reservoir management purposes, 36 marker surfaces have been identified in the reservoir. Flow units were then identified as reservoir units separated by areally pervasive vertical flow barriers (nonreservoir rock). This resulted in the identification of 20 flow units. The thickness of these flow units ranges from 5 to 15 ft. Reservoir Structure. The reservoir structure is a faulted anticline that is interpreted to be the result of regional salt tectonics. Closure to the reservoir is provided by faults on the southwestern and northern flanks of the structure and by an oil/water contact (OWC) on the eastern, western, and southern flanks of the structure. A structure map of the reservoir is presented in Fig. 1. Data Acquisition in the Takula Field Openhole Log Program. Most original development wells were logged with a basic log suite of resistivity/gamma ray and density/ neutron logs. In addition, the vertical wells drilled from each well jacket were logged with a sonic log and, occasionally, velocity surveys. All wells drilled after 1993 were logged with long spacing sonic and spectral gamma ray logs. In many wells drilled after December 1997, carbon/oxygen (C/O) logs have been run in open hole to distinguish between formation and injected water.3 A few recent wells have been logged with nuclear magnetic resonance (NMR) logs. The NMR log data, when integrated with data from other logs, have been of value in distinguishing free water from bound water, formation water from injection water, and reservoir rock from nonreservoir rock.
49
Zhu, X., and G. A. McMechan. "Numerical simulation of seismic responses of poroelastic reservoirs using Biot theory." GEOPHYSICS 56, no. 3 (March 1991): 328–39. http://dx.doi.org/10.1190/1.1443047.
Full textAbstract:
Biot theory proSvides a framework for computing the seismic response of fluid‐saturated reservoirs. Numerical implementation by 2-D finite‐differences allows investigation of the effects of spatial variations in porosity, permeability, and fluid viscosity, on seismic displacements of the solid frame and of the fluids (oil, gas, and/or water) in the reservoir. The porosity primarily influences wave velocities; the viscosity‐to‐permeability ratio primarily influences amplitudes and attenuation. Synthetic crosswell, VSP, and surface survey seismograms for representative reservoir models contain primary and converted reflections from fluid as well as lithologic contacts, and they illustrate the distribution of information available for describing a reservoir.
50
Henzell, S. T., H. R. Irrgang, E. J. Janssen, R. A. H. Mitchell, G. O. Morrell, I. D. Palmer, and N. W. Seage. "FORTESCUE RESERVOIR DEVELOPMENT AND RESERVOIR STUDIES." APPEA Journal 25, no. 1 (1985): 95. http://dx.doi.org/10.1071/aj84007.
Full textAbstract:
The Fortescue field in the Gippsland Basin, offshore southeastern Australia is being developed from two platforms (Fortescue A and Cobia A) by Esso Australia Ltd. (operator) and BHP Petroleum.The Fortescue reservoir is a stratigraphic trap at the top of the Latrobe Group of sediments. It overlies the western flank of the Halibut and Cobia fields and is separated from them by a non-net sequence of shales and coals which form a hydraulic barrier between the two systems. Development drilling into the Fortescue reservoir commenced in April 1983 with production coming onstream in May 1983. Fortescue, with booked reserves of 44 stock tank gigalitres (280 million stock tank barrels) of 43° API oil, is the seventh major oil reservoir to be developed in the offshore Gippsland Basin by Esso/BHP.In mid-1984, after drilling a total of 20 exploration and development wells, and after approximately one year of production, a detailed three-dimensional, two-phase reservoir simulation study was performed to examine the recovery efficiency, drainage patterns, pressure performance and production rate potential of the reservoir.The model was validated by history matching an extensive suite of Repeat Formation Test (RFT)* pressure data. The results confirmed the reserves basis, and demonstrated that the ultimate oil recovery from the reservoir is not sensitive to production rate.This result is consistent with studies on other high quality Latrobe Group reservoirs in the Gippsland Basin which contain undersaturated crudes and receive very strong water drive from the Basin-wide aquifer system. With the development of the simulation model during the development phase, it has been possible to more accurately define the optimal well pattern for the remainder of the development.* Mark of Schlumberger