Tight Oil Formations Research Articles

Geological characteristics and volume fracturing adaptability of tight oil reservoirs in the Ordos Basin of China

Abstract In recent years, China’s dependence on foreign crude oil has gradually increased. The Ordos Basin has abundant oil, gas, and coal resource. Tight oil and shale reservoirs have become very important replacement resources. This article studies the geological characteristics and volume fracturing adaptability of the Yanchang Formation tight oil reservoir in the central region of the Ordos Basin, and uses X-ray diffraction experiments to analyze the mineral composition of the reservoir; Utilizing high-pressure mercury intrusion technology to achieve precise quantitative characterization of multi-scale pore structures in reservoirs; Using the Analytic Hierarchy Process, establish a numerical judgment matrix and factor weights to study the adaptability of volume fracturing in the region. The results indicate that the volume fracturing adaptability of tight oil reservoirs in the Ordos Basin is good.

Downhole Hydrogen-Generation System Stimulates Challenging Formations in Kuwait

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 34832, “Successful Trial of Innovative Downhole Hydrogen-Generator System To Stimulate Hard-to-Recover Formations: First in Onshore Kuwait,” by Mustafa Al-Hussaini, Hamad S. Al-Rashedi, and Nada Al-Saleh, SPE, Kuwait Oil Company, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ The objective of the pilot trial described in the complete paper was to provide an economic solution to develop tight and hard-to-recover formations within the operator’s fields. These assets represent a major challenge because of their low recovery factor (1–3%), the high cost of available conventional stimulation technologies, low revenue, and inability to sustain production rates. Introduction To establish an integrated stimulation solution for tight and heavy oil formations, the concept of using active single-atom hydrogen power to enhance near-wellbore permeability was evolved. This technology is based on downhole hydrogen generation from an in-situ exothermic multistage chemical reaction between two unique hydroreacting agents (HRAs). This reaction generates a huge amount of thermal energy, active hydrogen, and other hot active gases and acid vapors. The selection of HRA compounds, and their amount and concentration, is customized for each field. Development of Business Cases West Kuwait (WK) Business Case. The M formation in the WK region is a carbonate, multifractured tight reservoir that had been producing for years but had begun experiencing a low recovery factor. Some of its wells had low-productivity issues related to tight formation characteristics and low pressure. Production could not be sustained for long periods of time even after conventional acid stimulation. The reservoir featured a carbonate reservoir thickness of 300 ft, with 70% of oil in place at the top section. The reservoir is classified as tight (less than 0.1–10 md average permeability and 10–25% porosity), with 10 fractured multilayers. Only 1–3% recovery could be achieved despite many vertical, horizontal, and multilateral wells having been drilled in the M formation. Oil is considered nonviscous (28 cp, 21 °API). Current stimulation approaches included conventional acid stimulation, which elicited a poor response, and multistage fracturing, which encountered mixed results at best. North Kuwait (NK) Business Case. The tight T formation in this region featured poor reservoir connectivity. Minimal aquifer support led to a rapid decline in reservoir pressure. In general, low mobility of oil, poor API gravity, and low permeability were the main obstacles in draining oil from the T formation, in addition to reservoir heterogeneities such as facies distribution, fracture patterns, and pressure regimes. The formation consisted of tight limestone deposited on a carbonate ramp. The reservoir is divided into three main stratigraphic units (Upper, of approximately 110 ft; Middle, of approximately 60 ft; and Lower, of approximately 16 ft). The reservoir exhibits porosity of approximately 14% and permeability of approximately 14 md and is filled with relatively-low-API hydrocarbon (19–22 °API).

The influence of hydraulic fracture and reservoir parameters on the storage of CO2 and enhancing CH4 recovery in Yanchang formation

The demand for a clean energy source from shale is growing day-to-day since it is not harmful to the environment like other fossil fuels. Further, shale reservoirs offer long-term geo-carbon dioxide (CO2) storage. Innovations in horizontal drilling and multi-stage hydraulic fracturing have made shale gas extraction and geo-CO2 storage economically viable. A three-dimensional Yanchang shale formation simulation model in Ordos's basin was developed using CMG-GEM, considering adsorption/desorption, diffusion, geomechanics, permeability changes, and non-Darcy flow. Two horizontally drilled wells, each 510 m long, were fractured and positioned 90 m apart. CO2 gas was injected into Well-2, producing methane (CH4) in Well-1. After simulation for 30 years, the cumulative mass of CH4 produced was 1.07×10+5kg, the cumulative mass of CO2 produced was 2.3×10+4kg, which is 1.14% of the mass injected, the cumulative mass of CO2 injected was 2.01×10+6kg and cumulative mass of CO2 gas stored was 1.987×10+6kg which is 98.86% of the injected mass of CO2 gas. The natural fracture system was the dominant factor of enhanced shale gas recovery and CO2 injection in the Yanchang shale formation. A sensitivity analysis was conducted with CMG-CMOST, examining the influence of reservoir and hydraulic fracture parameters in the storage of CO2 and enhancing CH4 recovery. Natural fracture porosity had the most significant impact on CH4 production and CO2 storage, followed by fracture permeability and half-length leading for hydraulic fracture parameters, with fracture conductivity being the least influential parameter. The approach used in this study applies to tight shale oil and gas formations in various sedimentary basins worldwide, enabling a more comprehensive understanding of reservoirs and hydraulic fracture parameters that can enhance oil and natural gas production.

Effects of Pore Water Content on Stress Sensitivity of Tight Sandstone Oil Reservoirs: A Study of the Mahu Block (Xinjiang Province, China)

Traditional stress sensitivity experiments are typically conducted under dry conditions, without considering the reservoir’s water content. In reality, the presence of water within pores significantly influences the extent of stress sensitivity damage in tight sandstone oil formations, subsequently affecting the determination of stress sensitivity coefficients during experimentation. By investigating sandstone samples from wells in the Mahu Block of China’s Xinjiang province, we observed that increasing water saturation reduces the stress sensitivity of tight sandstone. By conducting stress sensitivity experiments under varying water content conditions, we found that the stress sensitivity coefficient is not a constant value but decreases as water saturation increases. Based on experimental comparisons, an optimized power-law model for stress-sensitive damage assessment was refined. By conducting stress-sensitive damage assessment experiments under different water content conditions and integrating the concept of comprehensive compression coefficient, an improved stress-sensitive power-law model was established allowing for the influence of water content. The accuracy of this improved model was increased by 46.98% compared to the original power-law model through experimental validation. The research outcomes can enhance the accuracy of permeability and productivity evaluation, providing valuable guidance for unconventional oil and gas development.

Influence of matrix physical properties on flow characteristics in dual network model

The tight oil formation develops with microfractures and matrix pores, it is important to study the influence of matrix physical properties on flow characteristics. At first, the representative fracture and matrix samples are selected respectively in the dual media, the fracture and matrix digital rocks are constructed with micro-CT scanning at different resolutions, and the corresponding fracture and matrix pore networks are extracted, respectively. Then, the modified integration method is proposed to build the dual network model containing both fracture and matrix pore-throat elements, while the geometric-topological structure equivalent matrix pores are generated to fill in the skeleton domain of fracture network, the constructed dual network could describe the geometric-topological structure characteristics of fracture and matrix pore-throat simultaneously. At last, by adjusting the matrix pore density and the matrix filling domain factor, a series of dual network models are obtained to analyze the influence of matrix physical properties on flow characteristics in dual-media. It can be seen that the matrix system contributes more to the porosity of the dual media and less to the permeability. With the decrease in matrix pore density, the porosity/permeability contributions of matrix system to dual media keep decreasing, but the decrease is not significant, the oil–water co-flow zone decreases and the irreducible water saturation increases, and the saturation interval dominated by the fluid flow in the fracture keeps increasing. With the decrease in matrix filling domain factor, the porosity/permeability contributions of matrix system to dual media decreases, the oil–water co-flow zone increases and the irreducible water saturation decreases, and the saturation interval dominated by the fluid flow in the fracture keeps increasing. The results can be used to explain the dual-media flow pattern under different matrix types and different fracture control volumes during tight oil production.

Investigation of salinity and ion effects on low salinity water flooding efficiency in a tight sandstone reservoir

Low salinity water flooding (LSW) has been proven to be a low-cost and accessible enhanced oil recovery method in conventional reservoirs. However, its applications and potentials in tight reservoirs are mysterious in tight sandstone reservoirs due to the low porosity and low permeability.A series of laboratory experiments were designed to investigate ionic composition and salinity on the performance of LSW in a tight oil formation. More specifically, zeta potential and contact angle were measured to examine rock surface charge distribution and wettability changes. Pressure-controlled mercury injection (PMI) and permeability tests were conducted to analyze the pore & throat and permeability changes during LSW injection. Thereafter, displacement experiments were implemented to analyze oil recovery under different LSW injection schemes.The experimental observation demonstrates that LSW injection expands the double electric layer on the oil/brine and rock/brine interfaces, resulting in the expected wettability modification. However, the presence of divalent ions in the LSW undermines this effect. On the other hand, the permeability reduction resulting from salinity decrease can be alleviated by introducing divalent ions into LSW. The coreflooding experiments reveal that continuous injection of monovalent brine would reduce the ultimate oil recovery. Alternatively, a mixture of monovalent and divalent ions in LSW is utilized to revive the permeability and maintain the wettability modification. Furthermore, an optimized lower divalent ion concentration is found to be conducive to refining the cutoff throat radius and achieving a higher oil recovery from tight oil reservoirs.

Stress evolution and fracture propagation of infill well after production and injection of parent well in a tight oil reservoir

Stimulation of unconventional tight oil formations via horizontal wells has seen increasing cases of fracturing infill wells in recent years. The effectiveness of such a strategy is mainly dependent on the proper characterization of the stress evolution and an accurate forecast of the subsequent fracture propagation in the region neighboring the infill wells after considering the production performance and the injection schemes of the parent wells. In this respect, a comprehensive approach was proposed to simulate the stress evolution caused by the production and injection of the parent wells. The approach can also predict the upcoming fracture propagation behavior of the infill well. It was found that depletion in the parent wells can result in dramatic changes of the stress field, highlighted by apparent decreases in the magnitude of the minimum horizontal stress and changes in its orientation. Controlled injection in the parent wells can reproduce the original stress field, which favors the transverse extension of the fracture network in the infill well. In contrast, soaking well alone has little effect on improving the stress field. Therefore, this study suggests optimal injection schemes for parent wells and provides insights for fracture cluster designs in an infill well, eventually leading to maximized productivity of the infill well.

Oil Charging Power Simulation and Tight Oil Formation of Fuyu Oil Layer in Sanzhao Area, Songliao Basin

A thermodynamic and hydrocarbon composition model based on VTFlinc software was conducted based on the homogenization temperature of fluid inclusions and gas-to-liquid ratio, and the fluid inclusions’ trapped pressure was calculated. This software does not require the determination of individual inclusions, the composition of the simulation procedure is simple, and the simulation result has certain reliability. The VTFlinc software was used to calculate the trapped pressure of oil inclusions in the Fuyu tight reservoir of the Sanzhao area in the Songliao Basin. The results show the existence of two phases of oil charge. The first phase occurred at the end of the Nenjiang Formation at 79–74 Ma with an oil entrapped pressure of 16.922–19.068 MPa, and pressure coefficient of 1.18–1.26. During the second period in the Sifangtai Mingshui group at 69–64 Ma, the oil entrapped pressure was 20.216–28.830 MPa, and the pressure coefficient was 1.21–1.33. During the two periods, the pressure of the trapped oil inclusions is abnormal, and the pressure coefficient is above 1.2. Abnormal high pressure is the main driving force of hydrocarbon source rock and oil in the Fuyu Formation, as well as an important driving force for the lateral migration of oil in the tight reservoir. The reservoir formation model of the Fuyu tight oil reservoir in the Sanzhao area is a direct high-pressure charging and multi-channel migration accumulation model. The Q-1 source rock and Fuyu oil layer has a direct contact relationship between the source rock and the reservoir.

Development of an NMR workflow for determining nano-petrophysical properties of marine and lacustrine mudrocks

Nuclear Magnetic Resonance (NMR) is a powerful method of pore structure and fluids characterization for a wide range of porous media due to its fast and non-destructive capabilities, but its utilities of nano-petrophysics (the properties of rocks and fluids, as well as their interactions, in the presence of predominantly nm-sized pores) for tight oil formations warrant more studies. In this work, a total of four cylindrically-shaped tight reservoir samples at 2.54 cm in diameter with four different lithologies in USA and China were selected for systematic NMR analyses with T2 relaxation time, T1-T2 mapping, NMR cryoporometry (NMRc), and magnetic resonance imaging (MRI) techniques, along with other supplemental tests of X-ray diffraction (XRD), mercury intrusion porosimetry (MIP) and vacuum-assisted water immersion porosimetry (WIP), to characterize their petrophysical properties. The results show that the effective porosity obtained from NMR was highly consistent with WIP. Three samples characterized by MRI showed that T2 spectra had a good response to the fluid distribution in the samples. In this study, T2 time was converted into the pore size by combining corrected NMR T2 spectrum and MIP pore-throat size distribution. Finally, The Katz-Thompson model was applied for NMR data to calculate the permeability at different inflection points (connected pore networks) to quantitatively evaluate their individual permeabilities and porosities. Furthermore, except for sample N9 (carbonate-rich Wolfcamp A mudrock), a satisfactory agreement was achieved between the results of K2C (cut-off time at the second inflection point) and helium method for permeability analyses.

Performance of CO2 Foam Huff and Puff in Tight Oil Reservoirs

The challenges associated with unconventional reservoirs are related to their intrinsic nature: extremely low porosity and permeability. Combinations of horizontal wells and multistage hydraulic fracturing techniques have been developed to overcome the production obstacles and unlock the vast amount of oil in place in such formations. However, oil production still exhibits a sharp decline within the first 2 years after the stimulation, leading to an oil recovery of less than 15%. Thus, enhanced oil recovery methods need to be investigated to further increase the production rates and the recovery. In this study, laboratory experiments and numerical simulations were conducted to evaluate the performance of the CO2 foam huff and puff process and its impacts on oil recovery in tight oil formations. More specifically, the foam half-life was measured as a function of surfactant concentration and followed by the foam drainage ratio and its rheological properties in the subsequent tests. Reservoir simulations were conducted using the lab data and the field data collected from Cardium formation. Sensitivity analyses were finally carried out to investigate the effects of controlling variables on the CO2 foam performance. Experimental results revealed that the optimal surfactant concentration was found to be 0.2%, which is the critical micelle concentration point. Simulation results show that CO2 foam huff and puff can increase the oil recovery by more than 11% compared to that of the primary production. Moreover, sensitivity analyses show that the production time, injection time, and soaking time are the main effecting parameters, while the injection rate and the incremental injection rate are less important.

Production Forecasting of Tight Oil Reservoirs Using Improved Decline Model

Tight oil formation has become interest for many researchers since less than 10% of the OOIP can be obtained from the primary recovery. Other thinking on how to improve the oil recovery is still done. Decline curve analysis is one of the methods commonly used to estimate the ultimate recovery and the production rate profile of tight oil reservoirs. The present work uses the Duong model to overcome the limitations of Arps’ model. This study compares the observed values from simulation results to the estimated values from Duong model over 30 years. In our previous work, we demonstrated that some key parameters such as reservoir permeability, number of fractures per stage, fracture permeability, CO2 injection rate, CO2 injection time, CO2 soaking time, number of CO2 huff-n-puff cycle have a great effect on the improve of oil recovery of tight oil reservoirs while applying CO2 huff-n-huff. This work also focused on the development of some regression equations that can help to get approximatively the oil recovery factor of any formation, the goal here is to generate a suite of diagnostic plots to estimate oil recovery. These equations have revealed that the best fit is the polynomial regression. Results show the overestimation of oil reserve by Duong model when the flow regime changes from linear flow.

Enhancing oil recovery through immiscible water-alternating-CO2 in tight oil formations—a case study of Yaoyingtai Field in China

Enhancing oil recovery through immiscible water-alternating-CO2 in tight oil formations—a case study of Yaoyingtai Field in China

Lightly salted surface waters

Hydraulic Fracturing Hydraulic fracturing uses a water-based mixture to open up tight oil and gas formations. The process is mostly contained, but concerns remain about the potential for surface water contamination. Bonetti et al. found a small increase in certain ions associated with hydraulic fracturing across several locations in the United States (see the Perspective by Hill and Ma). These small increases appeared 90 to 180 days after new wells were put in and suggest some surface water contamination. The magnitude appears small but may require that more attention be paid to monitoring near-well surface waters. Science , aaz2185, this issue p. [896][1]; see also abk3433, p. [853][2] [1]: /lookup/doi/10.1126/science.aaz2185 [2]: /lookup/doi/10.1126/science.abk3433

A novel polymer encapsulated silica nanoparticles for water control in development of fossil hydrogen energy—tight carbonate oil reservoir by acid fracturing

This paper introduces and evaluates performance of a novel polymer encapsulated silica nanoparticles (CM-NPs) as RPM on reducing water-cut in tight carbonate oil formations with multistage hydraulic fractures. CM-NPs as RPM were prepared by graft-polymerization and quaternization and then identified by FT-IR method. Changes in the core surface properties and oil/water relative permeability were identified by SEM, XPS, wettability measurements and core flooding experiments. Certain changes occur, as confirmed by SEM and XPS, in the element compositions and microstructure of the core surface after introducing CM-NPs on the reservoir rock surface. Such changes irreversibly alter its wettability from the hydrophobicity to hydrophilicity. During the displacement experiments, there exists a disproportionate permeability reduction on relative permeability of the oil-water systems. Because of microstructure change of core surface, water relative permeability is reduced up to 60% and water flow restricted by hydrophilic polymer chains on the surface of CM-NPs while oil relative permeability decreases by less than 15% at different stages of water saturation. In addition, the rheological measurements and water drive tests shows the CM-NP solution has good acid resistance and strong adsorption on the core surface, keeping a long-term period of water control after acid fracturing in tight carbonate oil reservoir.

Enhanced oil recovery application in low permeability formations by the injections of CO2, N2 and CO2/N2 mixture gases

Low oil recovery which is very predominant in shale oil reservoirs has stimulated petroleum engineers to investigate the applications of enhanced oil recovery methods in these formations. One such application is the injection of gases into the formation to stimulate increased oil recovery. In many gas flooding projects performed in the field, the miscibility of the gas injected is usually the most desired displacement mechanism, and carbon dioxide (CO2) gas has been recognized to be the best performing gas for injection due to its ability to be miscible with oil in the reservoir at low pressures compared to other gases such as nitrogen. This minimum miscibility pressure (MMP) is of very crucial importance because it is the primary limiting factor in the feasibility of a miscible gas flooding project. However, there are other limiting factors such as cost and availability and, in these instances, nitrogen (N2) and lean gas are the more preferred candidate as opposed to carbon dioxide gas. Mixing carbon dioxide gas with lean gas or with nitrogen in a required ratio can allow us to design an injection gas that will be suitable enough to satisfy both the availability and cost constraints and at the same time allow us to achieve a reachable and reasonable miscibility pressure. The objective of this paper is to investigate the effect of mixing nitrogen gas and carbon dioxide gas in a 50:50 ratio on oil recovery in tight oil formations. The experiment was performed with controlled constraints such as the same core sample, same crude oil and same core cleaning and saturation process which was repeated for each trial. The oil used was live oil from Eagle ford formation, and the gases used were nitrogen (99.9% purity), carbon dioxide and a mixture of nitrogen and carbon dioxide in a 50:50 ratio. The injection pressure ranged from 1000 to 5000 psi with pressure increments of 1000 psi, and the same flooding time was 6 h. The potential of the N2, CO2 and N2–CO2 mixture for improving oil recovery was assessed along with the breakthrough time. The results showed that CO2 gas had the highest recovery followed by the N2–CO2 mixture and N2 gas had the lowest recovery. The gas breakthrough time results showed that the N2–CO2 mixture had the longest breakthrough time, N2 had the shortest breakthrough time, and CO2 had a significantly longer breakthrough time than pure N2 gas. The RF increased with increasing pressure, but the gas breakthrough time decreased with increasing pressure. However, the incremental RF decreased in all three cases when the injection pressure was above 3000 psi.

Against the Grain: Three Proppant Delivery Approaches That Buck the Status Quo

Pumping proppant down a wellbore is the easy part. Ensuring that the precious material does its job is another matter. A trio of field studies recently presented at the 2020 SPE Annual Technical Conference and Exhibition (ATCE) highlight in different ways how emerging technology and old-fashioned problem solving are moving the industry needle on proppant and conductivity control. These examples include the adoption of unconventional completion techniques in a conventional oil field in Russia and work to validate the use of small amounts of ceramic proppant in North Dakota’s tight-oil formations. Both studies seek to counter widely held assumptions about proppant conductivity. A third study details a recently developed chemical coating that Permian Basin producers are applying “on the fly” to sand before it is pumped downhole. The new adhesive material has found a niche in helping operators mitigate the amount of sand that returns to surface during flowback, a sectorwide issue that drives up completion costs and later may spell trouble for artificial lift systems. Disproving “The Overflush Paradigm” After conventional reservoirs are hydraulically fractured, both from vertical and horizontal wells, it has been standard practice for decades to treat the newly propped perforations with a gentle touch. The approach to this end is known as underflushing. When underflushing, the goal is to leave behind just a few barrels’ worth of proppant-laden slurry over the perforations before attempting to complete further stages. The motivation for this boils down to the need for an insurance policy against displacing the near-wellbore proppant pack and causing the open fracture face to pinch off before it ever has a chance to transmit hydrocarbons. Such carefulness comes at a price. Underflushing raises the risk of needing a cleanout before oil can flow optimally to surface. This not only delays the arrival of first oil, it means extra equipment and personnel are required. However, a more glaring downside to underflushing is that it appears to be an unnecessary precaution. The near-wellbore fracture area is, in fact, more robust than what conventional wisdom allows credit for.

Advantage of miscible fluid injection and tight oil production through a single-well alternating production-injection procedure over other single-well EOR methods

Tight oil reservoirs on primary production show less than 10% recovery in the US, creating a strong incentive to develop and apply suitable techniques for enhanced recovery. Enhanced oil recovery (EOR) techniques applied to tight oil include huff-and-puff (a cyclic injection-soaking-production approach) and flooding (continuous injection of an oil displacing fluid). Both approaches have seen limited success because of fundamental reasons. Huff-and-puff (HnP) requires substantial fluid transfer into and out of a tight oil formation during each injection-soaking-production cycle, a task that is inherently challenging because of low formation permeability. Similarly, flooding using fractured horizontal wells for injection and production faces the challenge of short-circuits created by fractures communicating from injector to producer. An alternative EOR approach for tight oil is to rely on a single well with a dual-conduit completion that allows for continuous injection and production through spatially alternating injection and production fracture sections, separated from each other by packers. This approach risks effective short-circuiting through cement leaks or high-conductivity secondary fractures. An alternative that mitigates these risks is to use a single-tubing completion featuring multiple remotely activated valves that can asynchronously inject into and produce from the spatially alternating fracture sections in a single-well alternating production (SWAP). While the well concepts considered in this work have been previously presented, operating aspects and quantitative effects of various reservoir, well completion, and operational variables have not been studied. This paper investigates the effects of reservoir permeability, secondary fractures, diffusion coefficient, cement leaks, resolution of completion control (fractures per section), and the injection and production cycling duration on SWAP performance and compares the performance of SWAP to HnP and the single-well alternating simultaneous injection and production (SWASIP) concept. Computer simulation is used to identify the merits of SWAP and compare it to SWASIP and HnP. Overall, SWAP appears to offer a cost-effective approach to increasing recovery from tight oil formations and deserves further development.

Quantifying Oil-Recovery Mechanisms during Natural-Gas Huff ‘n’ Puff Experiments on Ultratight Core Plugs

Summary Despite promising natural gas huff ‘n’ puff (HnP) field-pilot results, the dominant oil-recovery mechanisms during this process are poorly understood. We conduct systematic natural-gas (C1 and a mixture of C1/C2 with the molar ratio of 70:30) HnP experiments on an ultratight core plug collected from the Montney tight-oil formation, under reservoir conditions (P = 137.9 bar and T = 50°C). We used a custom-designed visualization cell to experimentally evaluate mechanisms controlling gas transport into the plug during injection and soaking phases and oil recovery during the whole process. The tests also allow us to investigate effects of gas composition and initial differential pressure between injected gas and the plug (ΔPi = Pg−Po) on the gas-transport and oil-recovery mechanisms. Moreover, we performed a Péclet number, NPe, analysis to quantify the contribution of each transport mechanism during the soaking period. We found that advective-dominated transport is the mechanism responsible for the transport of gas into the plug at early times of the soaking period (NPe = 1.58 to 3.03). When the soaking progresses, NPe ranges from 0.26 to 0.62, indicating the dominance of molecular diffusion. The advective flow caused by ΔPi during gas injection and soaking leads to improved gas transport into the plug. Total system compressibility, oil swelling, and vaporization of oil components into the gas phase are the recovery mechanisms observed during gas injection and soaking, while gas expansion is the main mechanism during depressurization phase. Overall, gas expansion is the dominant mechanism, followed by total system compressibility, oil swelling, and vaporization. During the “puff” period, the expansion and flow of diffused gas drag the oil along its flowpaths, resulting in a significant flow of oil and gas observed on the surface of the plug. The enrichment of injected gas by 30-mol% C2 enhances the transport of gas into the plug and increases oil recovery compared to pure C1 cases.

Coupled Flow/Geomechanics Modeling of Interfracture Water Injection To Enhance Oil Recovery in Tight Reservoirs

Summary Unconventional tight reservoirs that are typically characterized by low permeability and low porosity have contributed significantly to the global hydrocarbon production in recent years. Although hydraulic fracturing, along with horizontal well drilling, enables the economic development of such reservoirs, the production rate often declines sharply and results in low primary hydrocarbon recovery. The application of enhanced-oil-recovery (EOR) techniques in tight reservoirs has received much interest. In this study, the feasibility and efficiency of interfracture water injection to enhance oil recovery in multistage fractured tight oil reservoirs are analyzed through an efficient coupled flow/geomechanics model with an embedded discrete-fracture model (EDFM). A combined finite-volume/finite-element scheme is used to discretize the governing equations for flow and geomechanics, and the coupled problem is solved sequentially using a fixed-stress splitting algorithm. A basic numerical model consisting of a 15-stage fractured horizontal well is constructed using the petrophysical and geomechanical properties of a tight oil formation in Ordos Basin, China. Fractures indexed with even numbers are switched into injecting fractures when the production rate has dropped to less than a certain threshold. The improvement of oil recovery is analyzed by comparing the production profiles with and without water injection. In this coupled model, the fracture closure/opening during production/injection is considered according to the constitutive relations between fracture aperture and effective normal stress acting on the fracture faces. The poromechanical response of matrix is modeled by the Biot (1941) theory. The effects of fracture spacing, injection rate, and the presence of a natural-fracture network on oil-recovery enhancement are discussed through sensitivity analysis. The main mechanisms of interfracture water injection for enhancing oil recovery are waterflooding and reservoir-pressure maintenance. Small fracture spacing tends to reduce the oil recovery because of fracture interference and a limited drainage area; therefore, the primary depletion stage is shortened as the fracture spacing is reduced. The influence of interfracture water injection is more pronounced with smaller fracture spacing because the pressure-transient responses near the producing fractures are more dramatic considering the close proximity between the injecting fracture and the producing fracture. Although a higher injection rate results in higher oil recovery, the injectivity in low-permeability reservoirs limits the maximum-allowable injection rate. When secondary (natural)-fracture networks are considered, neighboring hydraulic fractures can be connected to one another via the secondary fractures, particularly if the interfracture spacing is small. Water can break through in the producing fractures quickly, which could also lead to high water cut and suboptimal oil-recovery performance. This study tests the feasibility and efficiency of interfracture injection to enhance tight oil recovery. The results indicate that interfracture injection can be a promising EOR technique for tight oil reservoirs, which sheds lights on future completion strategies and production design in tight reservoirs.

E&P Notes (July 2020)

E&P Notes (July 2020)