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Collaborating Authors
Kazemi, Hossein
Abstract The development of unconventional reservoirs is strongly affected by the reliability of the production forecast and project economics. This paper has addressed these issues by analyzing the performance of several wells using both analytical and numerical modeling. For instance, after history matching a portion of each well's production history, we forecasted the remaining portion of the well's production history using the early history-matched model parameters. Next, using mathematical models, we studied the feasibility of Enhanced Condensate Recovery (ECR) to increase condensate production and to utilize and store CO2. This research study includes multi-phase rate transient analyses of five wells and a pressure build-up test on one of the wells to calculate the stimulated permeability of the SRV region. Moreover, decline curve analysis of 34 wells in four well-groups (based on their landing zones) indicated that the wells in three landing zones had similar ‘Oil EUR’ while wells landed in the region between Austin Chalk and Eagle Ford had the highest ‘Gas EUR’. Our Eagle Ford compositional reservoir model consisted of three horizontal wells in the liquid-rich volatile oil region. After matching the production history of the wells, our model correctly forecasted the future performance of the wells. Furthermore, the input permeability of the SRV region in the history match was two orders of magnitude higher than the core permeability—confirming permeability enhancement resulting from hydraulic fracturing. The history-matched compositional reservoir model was used to study cyclic (Huff-n-Puff) CO2, lean wet gas, and dry gas ECR to evaluate the potential of improved condensate recovery. Each of the three injected compositions indicated considerable enhanced condensate recovery (ECR). The enhanced condensate variability was further studied by changing cycle length, injection rate and injection pressure. The optimum CO2 enhanced condensate recovery was obtained by injecting CO2 for 60 days followed by 180 days of production. The incremental condensate production after 4 cycles increased by 19% above the primary production with a net CO2 utilization of 8550 scf per bbl of incremental condensate.
Development of Multi-Stage Fracturing System and Wellbore Tractor to Enable Zonal Isolation During Stimulation and EGS Operations in Horizontal Wellbores
Fleckenstein, William (Colorado School of Mines) | Miskimins, Jennifer (Colorado School of Mines) | Kazemi, Hossein (Colorado School of Mines) | Eustes, Alfred (Colorado School of Mines) | Abdimaulen, Dias (Colorado School of Mines) | Mindygaliyeva, Balnur (Colorado School of Mines) | Uzun, Ozan (Colorado School of Mines) | Amini, Kaveh (Colorado School of Mines) | Hill, Tom (Tejas RE) | Mailand, Jason (Tejas RE) | Henschel, Robert (Tejas RE) | King, George (KSWC-HERCON Inc) | Ortiz, Santos (KSWC-HERCON Inc) | Keyes, Cullen (Defiant Exploration)
Abstract This paper discusses the progress on a project funded by the DOE Utah FORGE (Frontier Observatory for Research in Geothermal Energy) for the development of a subsurface heat exchanger for Enhanced Geothermal Systems (EGS) using unique casing sleeves cemented in place and are used first as a system for rapid and inexpensive multi-stage stimulations and second to perform conformance control functions at 225 °C. The proposed sleeves will use a single-sized dissolvable ball to open for fracture stimulation. After stimulation, and once the balls dissolve, the sleeves are open for immediate fluid injection. A separately designed wellbore tractor specific for both fluid detection and valve manipulation is then deployed to detect and control the injection entry points to create an effective EGS through paired horizontal injectors and open hole producers. The wells will be connected through multiple networks of induced and natural fractures that can be controlled throughout the field life.
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource (0.89)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (3 more...)
Abstract Pore radius and pore surface wettability affect capillary pressure and relative permeability functions which, in turn, affect fluid distribution in the flow channels and the outcome of improved and enhanced oil recovery in the reservoir. The contact angle between each pair of fluids and the pore surface is the main wettability determinant which is the focus of this paper; thus, we present measured contact angles for 16 samples from five unconventional reservoirs in the US and we correlate mineralogy of the facies and the crude oil composition to the reservoir rock wettability. Beyond enhanced oil recovery (EOR), the results may be significant in managing CO2 flooding and in determining the fraction of the sequestered CO2 in carbon capture utilization and storage (CCUS). Primary production, IOR, and EOR are affected by wettability and wettability alterations during the reservoir's life as a result of reservoir production methods used. Contact angles were measured using a drop shape analyzer (DSA) at the reservoir temperature and pressure for reservoir samples from Wolfcamp, Eagle Ford, Niobrara, Codell, and Bakken: 1) unaged core slices surrounded with formation brine, 2) aged core slices surrounded with formation brine, and 3) aged core samples surrounded with formation brine and CO2. Core slices of 1-in width were prepared and polished using different grades of sandpaper and cleaned using toluene, chloroform, and methanol in a Soxhlet extractor, and dried in the oven. Sample saturation was accomplished in an ultrafast centrifuge. Results show that the carbonate-dominated facies from Wolfcamp-A formation and Niobrara A-Chalk show a relatively higher contact angle even when the core sample is cleaned and is not aged. However, Eagle Ford, Niobrara B-chalk and C-chalk, Codell, Bakken, Three Forks indicate strong water-wet behavior when unaged as expected in ambient conditions. The same characteristics were observed for aged samples from the Eagle Ford. The results indicate the need for studying the wide variations for the formation facies and the need for evaluating the wettability of the reservoir facies prior to any EOR application in unconventional reservoirs, especially in Wolfcamp formation, where the facies mineralogy and wettability are significantly different in almost every foot.
- North America > United States > Texas (1.00)
- North America > United States > North Dakota (1.00)
- North America > United States > New Mexico (1.00)
- North America > United States > Colorado (1.00)
- Phanerozoic > Paleozoic (0.95)
- Phanerozoic > Mesozoic > Cretaceous (0.47)
- Geology > Mineral > Silicate (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.98)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.70)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Enhanced Oil Recovery Experiments in Wolfcamp Outcrop Cores and Synthetic Cores to Assess Contribution of Pore-Scale Processes
Kamruzzaman, Asm (Colorado School of Mines) | Kazemi, Hossein (Colorado School of Mines) | Kneafsey, Timothy J (Lawrence Berkeley Laboratory) | Reagan, Matthew T (Lawrence Berkeley Laboratory)
Abstract This paper assesses the pore- and field-scale enhanced oil recovery (EOR) mechanisms by gas injection for low permeability shale reservoirs. We performed compression-decompression laboratory experiments in ultratight outcrop cores of the Permian Basin as well as in ceramic cores using n-dodecane for oil. The EOR assessment strategy involved determining the quantity of oil produced after injection of helium (He), nitrogen (N2), methane (CH4), and methane/carbon dioxide (CH4/CO2) gas mixtures into unfractured and fractured cores followed by depressurization. Using the oil recovery volumes from cores with different number of fractures, we quantified the effect of fractures on oil recovery—both for Wolfcamp outcrop cores and several ceramic cores. We observed that the amount of oil recovered was significantly affected by the pore-network complexity and pore-size distribution. We conducted laboratory EOR tests at pore pressure of 1500 psia and temperature of 160°F using a unique coreflooding apparatus capable of measuring small volumes of the effluent oil less than 1 cm. The laboratory procedure consisted of (1) injecting pure n-dodecane (n-C12H26) into a vessel containing a core which had been moistened hygroscopically and vacuumed, and raising and maintaining pressure at 1500 psia for several days or weeks to saturate the core with n-dodecane; (2) dropping the vessel pressure and temperature to laboratory ambient conditions to determine how much oil had entered the core; (3) injecting gas into the n-dodecane saturated core at 1500 psia for several days or weeks; (4) shutting in the core flooding system for several days or weeks to allow gas in the fractures to interact with the matrix oil; (5) finally, producing the EOR oil by depressurization to room pressure and temperature. Thus, the gas injection EOR is a ‘huff-and-puff’ process. The primary expansion-drive oil production with no dissolved gas from fractured Wolfcamp cores was 5% of the initial oil in place (IOIP) and 3.6% of IOIP in stacked synthetic cores. After injecting CH4/CO2 gas mixtures, the EOR oil recovery by expansion-drive in Wolfcamp core was 12% of IOIP and 8.2% of IOIP in stacked synthetic cores. It is to be noted that the volume of the produced oil from Wolfcamp cores was 0.27 cm while it was 6.98 cm in stacked synthetic cores. Thus, while synthetic cores do not necessarily represent shale reservoir cores under expansion drive and gas-injection EOR, these experiments provide a means to quantify the oil recovery mechanism of expansion-drive in shale reservoirs. The gas injection EOR oil recovery in Wolfcamp cores with no fractures yielded 7.1% of IOIP compared to the case of one fracture and two fractures which produced 11.9% and 17.6% of OIP, respectively. Furthermore, in the no-fracture, one-fracture, and two-fracture cores, more EOR oil was produced by increasing the CO2fraction in the injection gas mixture. This research provides a basis for interpreting core flooding oil recovery results under expansion drive and gas injection EOR—both in presence and absence of interconnected micro- and macro-fractures in the flow path. Finally, the CO2 injection results quantify the CCUS efficacy in regard to the amount of sequestered CO2 from pore trapping in the early reservoir life. For the long-term CO2 trapping, one needs to include the chemical interaction of CO2 with the formation brine and rock matrix.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (0.89)
- Overview (0.67)
- Research Report (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
Abstract In this paper, we will show that it is highly beneficial to model dual-porosity reservoirs using matrix refinement (similar to the multiple interacting continua, MINC, of Preuss, 1985) for water displacing oil. Two practical situations are considered. The first is the effect of matrix refinement on the unsteady-state pressure solution, and the second situation is modeling water-oil, Buckley-Leverett (BL) displacement in waterflooding a fracture-dominated flow domain. The usefulness of matrix refinement will be illustrated using a three-node refinement of individual matrix blocks. Furthermore, this model was modified to account for matrix block size variability within each grid cell (in other words, statistical distribution of matrix size within each grid cell) using a discrete matrix-block-size distribution function. The paper will include two mathematical models, one unsteady-state pressure solution of the pressure diffusivity equation for use in rate transient analysis, and a second model, the Buckley-Leverett model to track saturation changes both in the reservoir fractures and within individual matrix blocks. To illustrate the effect of matrix heterogeneity on modeling results, we used three matrix bock sizes within each computation grid and one level of grid refinement for the individual matrix blocks. A critical issue in dual-porosity modeling is that much of the fluid interactions occur at the fracture-matrix interface. Therefore, refining the matrix block helps capture a more accurate transport of the fluid in-and-out of the matrix blocks. Our numerical results indicate that the none-refined matrix models provide only a poor approximation to saturation distribution within individual matrices. In other words, the saturation distribution is numerically dispersed; that is, no matrix refinement causes unwarranted large numerical dispersion in saturation distribution. Furthermore, matrix block size-distribution is more representative of fractured reservoirs.
- Asia (0.94)
- North America > United States > Colorado (0.29)
Abstract Diagnostic fracture injection tests (DFIT) are used as an indirect method to determine closure pressure and formation effective permeability in unconventional reservoirs as a first step in formation evaluation. The information obtained from DFIT is particularly useful because it is obtained before any production for a given well is available. In DFIT, a small fracture is created by injecting few barrels of completion fluid until formation breaks down and a fracture is initiated and propagates a short distance into the reservoir. Then, injection is stopped, and the pressure decline (or falloff) is monitored. From this pressure decline, the effective permeability of the formation is estimated by Nolte's G-function, log-log plot, or square root of time analysis. In this research, the viability of the common DFIT analysis techniques was investigated for unconventional reservoirs with and without micro-fractures by using a numerical hydraulic fracturing simulator, CFRAC. The results of numerical simulations were investigated to assess the impact of permeability, residual fracture aperture, and complex fracture networks on conventional DFIT interpretations. For the example considered in this work, the commonly used G-function analysis yielded estimates of permeability over an order of magnitude higher than the simulated matrix permeability. Error in the G-function estimates of permeability were higher for higher matrix permeability and in the existence of a fracture network. On the other hand, straight-line analysis of Ap versus G-time yielded much closer (in the same order of magnitude) estimates of permeability.
Abstract The complexity, high cost, and potential environmental concerns of chemical enhanced oil recovery (EOR) methods have diminished their field applications considerably. However, considering the significant incremental oil recoveries that can be obtained from these methods encourage researchers to explore ways to reduce both complexity, cost, and environmental concerns of such systems. This is especially important in carbonate formations, where after waterflooding, much of the oil remains trapped in complex reservoir pores—especially if the reservoir contains an interconnected fracture network of flow channels within the bulk rock matrix. In this paper, we present an experimental assessment of several simple chemical EOR waterflooding systems comprising of small concentrations of a low cost, low molecular weight ketone and a non-ionic surfactant in association with low-salinity brine. The experiments were conducted in carbonate cores from a Permian Basin San Andres Formation. Four different oil displacement scenarios were investigated using San Andres carbonate cores from the Central Vacuum Field in New Mexico. This included 1) low-salinity brine, 2) low-salinity brine with a surfactant, 3) low-salinity brine with a ketone, and 4) low-salinity brine with a combined ketone-surfactant system. Static imbibition experiments were conducted using a spontaneous imbibition apparatus in addition to the use of a high-speed centrifuge to saturate the cores to irreducible brine saturation. Adding a 1% concentration of 3-pentanone and a 1% non-ionic surfactant to a low-salinity brine yielded oil recoveries of 44% from the 3-pentanone system, compared to 11.4% from low-salinity brine only. The oil recovery is enhanced by a single mechanism or synergy of several mechanisms that includes interfacial tension (IFT) reduction by surfactant, capillary imbibition, favorable wettability alteration by ketone, and osmotic low-salinity brine imbibition. The IFT decreased to 1.79 mN/m upon addition of non-ionic surfactant to low-salinity brine, and it reduced to 2.96 mN/m in a mixture of 3-pentanone and non-ionic surfactant in low-salinity brine. Furthermore, ketone improved the core wettability by reducing the contact angle to 43.9° from 50.7° in the low-salinity brine experiment. In addition, the low-salinity brine systems caused mineral dissolution, which created an alkali environment confirmed by an increase in the brine pH. We believe the increase in pH increased the hydrophilic character of the pores; thus, increasing oil recovery.
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock (0.48)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (35 more...)
An Improved Multicomponent Diffusion Model for Compositional Simulation of Fractured Unconventional Reservoirs
Tian, Ye (Southwest Petroleum University and Colorado School of Mines) | Zhang, Chi (Colorado School of Mines) | Lei, Zhengdong (Research Institute of Petroleum Exploration and Development) | Yin, Xiaolong (Colorado School of Mines) | Kazemi, Hossein (Colorado School of Mines) | Wu, Yu-Shu (Colorado School of Mines (Corresponding author)
Summary Most simulators currently use the advection/diffusion model (ADM), where the total flux comprises Darcian advection and Fickian diffusion. However, significant errors can arise, especially for modeling diffusion processes in fractured unconventional reservoirs, if diffusion is modeled by the conventional Fick’s law using molar concentration. Hence, we propose an improved multicomponent diffusion model for fractured reservoirs to better quantify the multiphase multicomponent transport across the fracture/matrix interface. We first give a modified formulation of the Maxwell-Stefan (MS) equation to model the multicomponent diffusion driven by the chemical potential gradients. A physics-based modification is proposed for the ADM in fractured reservoirs, where fracture, matrix, and their interface are represented by three different yet interconnected flow domains to honor the flux continuity at the fracture/matrix interface. The added interface using a more representative fluid saturation and composition of the interface can hence better capture the transient mass fluxes between fracture and matrix. The proposed approach is also implemented in an in-house compositional simulator. The multicomponent diffusion model is validated with both intraphase and interphase diffusion experiments. Then, the improved model for fracture/matrix interaction is compared with a fine-grid model. The proposed multiple interacting continua (MINC) model with three continua (MINC3) can better match the fine-grid model’s result than the double-porosity (DP) model, which only obtains a fair match at an early time. Then, we simulate a gas huff ‘n’ puff (HnP) well in the Permian Basin to investigate the effect of diffusion within the fractured tight oil reservoir. The simulation reveals that diffusion has a minor effect on the performance of depletion when oil is the dominant phase. For gas HnP, the simulation neglecting diffusion will underestimate the oil recovery factor (RF) but overestimate the gas rate. The DP approach tends to overestimate the RF of heavy components but leads to a similar cumulative oil RF compared with MINC3. With the diffusion included in the simulation, gas HnP performance becomes more sensitive to the soaking time than the model without diffusion. Although increasing the soaking time will lead to a higher RF after considering diffusion, the incremental oil is not sufficiently large to justify a prolonged soaking time.
- North America > United States > Texas (1.00)
- North America > United States > California (0.93)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (24 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- (7 more...)
Abstract The main objective of the research presented in this paper was to develop a working knowledge of the unconventional shale in the UAE Diyab formation which includes reservoir engineering evaluation of the UAE Diyab Upper Jurassic gas condensate and Shilaif Middle Cretaceous light oil shale development. To achieve this objective, (1) we measured core permeability of a couple of Diyab cores with and without fractures, (2) we analyzed the pressure fall-off data from a Diagnostic Fracture Injection Test (DFIT) to determine in-situ matrix permeability for use in reservoir evaluation, modeling, and forecasting reservoir performance, and (3) we determined the effective permeability (that is, combined permeability of matrix and microfractures) of a Diyab stimulated well using rate transient analysis (RTA). Furthermore, we put together both analytical and numerical models for single-phase and two-phase flows in support of the interpretation of the field pressure falloff DFIT data, and the data from a laboratory DFIT conducted in a granite core by Frash in 2014 to shed light on enhanced geothermal reservoirs. Finally, we calculated the depths of filtrate invasion and the cooled region surrounding the hydraulic fracture surfaces to determine the net stress change near the surface of hydraulic fractures, which is commonly referred to as the ‘stress shadow' effect. We concluded that our research effort was both informative and instructive in determining the effectiveness of the stimulation efforts for the wells used in this study, and the process can be similarly utilized in any shale stimulation effort elsewhere.
- North America > United States (1.00)
- Asia > Middle East > UAE (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.66)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Diyab Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Arabian Basin > Jafurah Basin > Tuwaiq Mountain Formation (0.94)
- (5 more...)
Abstract Mini frac, or diagnostic fracture injection test (DFIT), is a short hydraulic fracturing test that provides formation break-down pressure, minimum horizontal stress, and reliable value for formation permeability of shale reservoirs. The calculated formation permeability is particularly more reliable from the analysis of the second cycle of the mini frac test because the fracture is already created. In this paper, we present a simple technique to analyze and interpret DFIT data similar to the analysis of the classic drillstem test (DST) data in vertical wells. The only difference is that in DFIT pressure-time characteristics approximate the linear flow regime while in DST, pressure-time behavior follows the radial flow regime. In general, DFIT analysis provides matrix permeability while the analysis of long-term pressure decline of the production data yields stimulated formation permeability, which can be attributed to microfracture permeability. Thus, we will show how we utilize the permeability from DFIT, and the permeability calculated from the production decline data of production wells (i.e., multistage hydraulically fractured wells) to construct a viable dual-porosity model to assess the performance of wells under primary production and gas injection EOR. We also compare our results with those of Nolte G-function. The paper includes numerical modeling of two-phase nonlinear flow, analytical solution methodology from multi-phase flow, experimental data, and field data to illustrate the viability of our interpretation method. Furthermore, our analysis technique is simple because it only uses pressure falloff data points during the shut-in period of the DFIT. Not only the method is confirmed by numerical modeling, but it is also verified by pressure falloff from laboratory data.
- Europe (0.93)
- North America > United States > Colorado (0.30)
- North America > United States > Texas (0.29)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.61)