R. B. Piccinini, Petrobras Summary Traditional methods of pressure-transient analysis rely on homogeneous reservoir models and require assumptions on reservoir shape and well-flow regimes. Unsteady flow rates offer further complexity because traditional methods are dependent on past production history. Crump and Hite (2008) proposed a new method for estimating average reservoir pressure that applies to heterogeneous reservoirs and only requires knowledge of the pressure-buildup data. The Crump and Hite (2008) method relies on obtaining the first few eigenvalues of a diffusion equation to predict average reservoir pressure. A large buildup time may be required for a successful application of the method, depending on the magnitude of the first eigenvalue. This work applied the Crump and Hite (2008) method to a real field case. A reservoir was produced by a single horizontal well for a period of a few years, which was followed by a shut-in period of approximately 200 days. The first four eigenvalues could be extracted, providing an estimate of average reservoir pressure.
Tang, Hewei (Texas A&M University) | Yan, Bicheng (Texas A&M University (now with Sanchez Oil and Gas)) | Chai, Zhi (Texas A&M University) | Zuo, Lihua (Texas A&M University) | Killough, John (Texas A&M University) | Sun, Zhuang (University of Texas at Austin)
Well interference is a common phenomenon in unconventional-reservoir development. The completion and production of infill wells can lead to either positive or negative well-interference impacts on the existing producers. Many researchers have investigated the well-interference phenomenon; however, few of them attempted to apply rigorous simulation methods to analyze both positive and negative well-interference effects, especially in two different formations. In this work, we develop a comprehensive compositional reservoir model to study the well-interference phenomena in the Eagle Ford Shale/Austin Chalk production system. The reservoir model considers capillary pressure in the vapor/liquid-equilibrium (VLE) equation (nanopore-confinement effect), and applies the embedded discrete-fracture model (EDFM) for dynamic fracture modeling. We also include a multisegment-well model to characterize the wellbore-crossflow effect introduced by fracture hits. The simulation results indicate that negative well-interference impact is much more common in the production system. With a smaller permeability difference, the hydraulic-fracturing effect can lead to a positive well-interference period of several hundred days. The nanopore-confinement effect in the Eagle Ford Shale can contribute to the negative well-interference effect. We also analyze the impact of other factors such as initial reservoir pressure, matrix porosity, initial water saturation, and the natural-fracture system on the well performance. Our work provides valuable insights into dynamic well performance under the impact of well interference.
Kumar, Abhash (AECOM, National Energy Technology Laboratory) | Zorn, Erich (National Energy Technology Laboratory (currently with DiGioia Gray Inc.)) | Hammack, Richard (National Energy Technology Laboratory) | Harbert, William (University of Pittsburgh)
Hydraulic fracturing is a well-established technique to extract gas or liquid hydrocarbons from low-permeability formations such as shale and tight gas reservoirs. Diffusion of hydrofracturing fluid outward from the stimulated fractures into the target formation produces slip across pre-existing fractures and other discontinuities in the rock. Microseismic events recorded by downhole seismic-monitoring arrays are a manifestation of associated deformation. Recent investigations suggest that the total cumulative seismic moment of microearthquakes during hydraulic fracturing is only a small portion of the total seismic-energy release expected for the fluid volume injected into the formation. These observations suggest that other sources of energy release (such as inelastic deformation), contemporaneous with microseismicity, should be considered relevant to the hydraulic-fracturing process. Recent observations on long-period, long-duration (LPLD) seismic events suggest that slow slip emission along weaknesses that are misaligned with respect to the present-day stress field is likely an important mechanism of deformation and should be better understood and quantified in reservoir stimulations. In Morgantown, West Virginia, we conducted seismic monitoring of hydraulic-fracturing activity using an array of five broadband, three-component (3C) surface seismometers. Using this network, we identified 89 high-amplitude, impulsive events and 436 LPLD events, with highly emergent waveform characteristics. In these interpreted LPLD events, we observed a significant concentration of energy in the 0.8- to 3-Hz frequency range. During hydraulic fracturing, LPLD events were found to occur most frequently when the pumping pressure and rate were at or near maximum values. Because the main purpose of hydraulic fracturing is to stimulate oil and gas production from the less-permeable reservoir, we compared the relative production contributions/stage to the frequency of the occurrence of suspected LPLD events. We found a positive correlation between the frequency of LPLD events and stage-by-stage gas production, highlighting the potential contribution of slow deformation processes and its effectiveness in the reservoir stimulation.
Hadavand, Mostafa (University of Alberta) | Carmichael, Paul (ConocoPhillips Canada) | Dalir, Ali (ConocoPhillips Canada) | Rodriguez, Maximo (ConocoPhillips Canada) | Silva, Diogo F. S. (University of Alberta) | Deutsch, Clayton Vernon (University of Alberta)
4D seismic is one of the main sources of dynamic data for heavy-oil-reservoir monitoring and management. 4D seismic is significant because seismic attributes such as velocity and impedance depend on variations in reservoir-fluid content, temperature, and pressure distribution as a result of hydrocarbon production. Thus, the large-scale nature of fluid flow within the reservoir can be evaluated through information provided by 4D-seismic data. Such information may be described as anomalies in fluid flow that can be inferred from the unusual patterns in variations of a seismic attribute. During steam-assisted gravity drainage (SAGD), the steam-chamber propagation is fairly clear from 4D-seismic data mainly because of changes in reservoir conditions caused by steam injection and bitumen production. Anomalies in the propagation of the steam chamber reflect the quality of fluid flow within the reservoir. A practical methodology is implemented for integration of 4D seismic into SAGD reservoir characterization for the Surmont project.
Andersen, Pål Ø. (University of Stavanger) | Brattekås, Bergit (University of Stavanger) | Nødland, Oddbjørn (University of Stavanger and International Research Institute of Stavanger) | Lohne, Arild (University of Stavanger and International Research Institute of Stavanger) | Føyen, Tore L. (University of Bergen and SINTEF Industry) | Fernø, Martin A. (University of Bergen)
We present numerical interpretations of two experimental sets of spontaneous-imbibition tests with combined cocurrent/countercurrent flow in high-permeability, unconsolidated sandpacks. The experiments were conducted using the two-ends-open free-spontaneous-imbibition (TEOFSI) boundary condition, in which one end face was in contact with the wetting (W) phase and the other with the nonwetting (NW) phase. The simulations quantified the impact from boundary-condition effects during capillary imbibition in the low-capillary sandpacks; the flow resistance in the outlet filter controlled imbibition rates, end recovery, and countercurrent production in tests with high NW-phase viscosity. A hydrostatic water column of a few centimeters at the W-phase end face also affected the imbibition process. Numerical and analytical solutions provided insight into when such boundary effects become important. In particular, the observed linear recovery with time and variations in time scale could not be explained by conventional modeling, but were captured by incorporating a thin, low-permeability filter into the models. For high-viscosity NW-phase tests with a low-permeability filter, countercurrent production is strongly enhance and controlled by the capillary backpressure (CBP).
Cheng Chen, Virginia Polytechnic Institute and State University, and Ming Gu, West Virginia University This erratum is being issued to correct the captions of Figs. 2 and 3 on pages 395 and 396 of SPE-175907-PA [SPE Res Eval & Eng 21 (2): 392-404. This change affects the captions only, and supersedes those contained in the paper.
Chen, Zhiming (State Key Laboratory of Petroleum Resources and Prospecting in China University of Petroleum, Beijing, and University of Texas at Austin) | Liao, Xinwei (State Key Laboratory of Petroleum Resources and Prospecting in China University of Petroleum, Beijing) | Zhao, Xiaoliang (State Key Laboratory of Petroleum Resources and Prospecting in China University of Petroleum, Beijing)
Forecasting coalbed-methane well performance in the Qinshui Basin is a key task for predicting future gas production, There is evidence suggesting that complex fracture geometry and multiple hydraulic-fracture networks might develop. Unfortunately, very limited work has been published on the production analysis of multiple-fractured vertical wells (MFVWs) in coalbed-methane reservoirs. To better understand the production performance of the MFVWs, a new, fast, and reliable methodology is presented in this paper. This semianalytical methodology is derived from an analytical reservoir solution and a numerical fracture solution. Dual-porosity, gas-diffusion, gas-adsorption, and stress-sensitivity effects are considered. Verification of the methodology is accomplished through comparison with synthetic-reservoir-simulation cases and with field-performance data. Good agreement is shown between results from the proposed methodology and those from a reservoir-simulation model. Results from this study indicate increasing transient-gas-production rate and cumulative gas recovery with increasing natural-fracture permeability, gas-storage coefficient, Langmuir volume, fracture conductivity, and fracture length. The transient gas-production rate and cumulative gas recovery were found to decrease with increasing stress-sensitivity coefficient. The parameters found to have the strongest and weakest effects on the gas-production rate were the nature-fracture permeability and the fracture conductivity, respectively. Results from this study on MFVWs in coalbed-methane reservoirs indicate fracture length is more important than fracture conductivity in terms of its effect on gas productivity.
We present here a practical method for estimating the directional permeabilities in anisotropic reservoirs. The method uses pressure transient-analysis results from at least three sets of interference/pulse tests among wells offset at different azimuths. Knowledge of themaximum/minimum permeability directions in anisotropic reservoirs helps to optimize injector/producer locations and is important for reservoir management, especially under secondary/enhanced recovery of hydrocarbons. The proposed method uses transient-test data rich with dynamic information to provide fieldwide permeability distribution at well-spacing scale, which is relevant for estimating fluid movement and recovery. Its application in a carbonate oil field in Kazakhstan is also discussed.
The proposed method uses well coordinates and multiple sets of analysis results of interwell transient tests through mathematical matrix operations. It is straightforward to use and works efficiently. The algorithms to calculate directional permeabilities in anisotropic homogeneous reservoirs from interference tests were first introduced by Ramey (1975) and extended to pulse tests by Kamal (1983). Our new approach can use the analysis results of any type of interwell transient test directly in heterogeneous reservoirs. Any valid modern methods can be used to analyze each interwell test, and all analysis results can be integrated to generate the field permeability-tensor map.
The proposed method was validated using synthetic cases. Its application in a large set of multiple-well tests in a naturally fractured reservoir illustrated its practicality and efficiency. Extensive interwell transient data have been collected and analyzed from carefully designed and conducted tests among 12 wells in Korolev Field, a carbonate field in Kazakhstan. Of the 12 wells, 10 have interwell tests at three different directions, which allows the calculation of directional permeabilities. The permeability-tensor map is generated for the entire field and compared with the fracture orientations derived from geological-structure and image-log interpretation. Both static and dynamic data resources indicate that fracture orientations vary substantially throughout the field. In some areas, the dominant permeability directions from interwell transient data are consistent with those from image-log interpretation. However, they differ in other areas, emphasizing the need for using dynamic measurements at well-spacing scale for better understanding of fracture distributions/orientations and their effects on flow communication among wells.
The novelty of this method of estimating directional permeabilities is that it uses well coordinates and analysis results of individual interwell transient tests directly in heterogeneous reservoirs. It is convenient and efficient. It can be easily used to generate a fieldwide permeability-tensor map using dynamic transient data. Its application in a large carbonate reservoir demonstrates its practicality, even in fields with complex varying anisotropy. Integrating the results from this method with those from geological and petrophysical analyses reduces uncertainty in reservoir characterization. This method has already been implemented in some commercial well-testanalysis software.
Understanding reservoir-rock characteristics and the forces that mobilize oil in unconventional reservoirs is critical in designing oil-recovery schemes. Thus, we conducted laboratory experiments for three preserved Middle Bakken cores using centrifuge and nuclearmagnetic-resonance (NMR) instruments to understand oil-recovery mechanisms in the Bakken. Specifically, we measured capillary pressure, pore-size distribution (PSD), and oil and brine saturations and distributions.
A series of oil/brine-replacement experiments (drainage and imbibition) were conducted for the preserved cores using a high-speed centrifuge. T2 time distribution and 1D saturation-profile measurements were obtained using a 2-MHz NMR instrument before and after centrifuge experiments. Moreover, PSD was determined from mercury-intrusion capillary pressure (MICP) and nitrogen-gas-adsorption experiments. We conducted scanning-electron-microscope (SEM) imaging on polished cubical cores to determine pore shapes and mineralogy of pore walls using a field-emission SEM (FE-SEM).
Our measurements show that these three preserved Middle Bakken cores show mixed-wet characteristics. Water resides in smaller pores and oil resides in larger pores in all experiments. Using a low-salinity synthetic brine of 50,000 ppm to surround Bakken cores of much-higher salinity, we produced up to 6.33% [of pore volume (PV)] oil from two higher-porosity (approximately 8%) cores, and 10.72% (of PV) oil from one lower-porosity (approximately 2%) core in a spontaneous-imbibition (SI) experiment. Up to 6.62% (of PV) oil from the two higher-porosity cores and 11.23% (of PV) oil from the lower-porosity core were produced in a forced-imbibition (FI) experiment as well. These experiments indicate that molecular diffusion/capillary osmosis overrides the wettability effects in low-permeability Middle Bakken cores. The new observations regarding molecular diffusion/capillary osmosis have altered our classical notion of capillary imbibition in low-permeability reservoirs.
Alhuraishawy, Ali Khayoon (Missan Oil Company and Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Almansour, Abdullah ( King Abdulaziz City for Science and Technology (KACST))
Fractures and oil-wet conditions significantly limit oil recovery in carbonate reservoirs. Gel treatment has been applied in injector wells to modify the prevailing reservoir streamlines and significantly reduce fracture permeability, whereas low-salinity waterflooding has been applied experimentally to modify rock wettability toward water-wet for improved oil recovery. However, both processes have limitations that cannot be resolved using a single method. The objective of this study was to test whether low-salinity water could enable gel particles to move deeply into fractures to efficiently increase oil recovery and control water production. A semitransparent fracture model of carbonate cores and acrylic plates was built to study the effect of low-salinity waterflooding, fracture width, gel-injection volume, and fracture uniformity on oil recovery and to redirect the flow path to unswept zones. Preformed partial gel (PPG) and brine movements were visible through the model’s transparent acrylic plate. Seawater was used for brine flooding and to prepare swollen particles; the seawater was diluted 100 times to create low-salinity water. A light crude oil was used, with 10-cp viscosity. Low-salinity water was injected after gel placement to test the gel-plugging efficiency. The results showed that the low-salinity water could improve gel propagation into the fracture and increase oil recovery because the gel strength (apparent viscosity) decreased as the brine concentration decreased. The gel-injection volume had a significant effect on the oil-recovery factor when seawater flooding followed the gel-injection process, although there was less of an effect when the gel was followed by low-salinity waterflooding. Moreover, the effect of low-salinity waterflooding on gel propagation decreased as the fracture width decreased. In addition, the resulting fracture uniformity illustrates a viable effect of the in-depth water-diversion treatment.