Journal of Unconventional Oil and Gas Resources最新文献

Counter-current spontaneous imbibition (COUCSI) is an important mechanism of recovery from tight matrix blocks in naturally fractured reservoirs. In this study, by means of numerical simulation experiments we show that significant differences in terms of the final recovery and imbibition rate exist between COUCSI with and without the gravity forces. A specific situation where gravity forces are resisting the process is considered. For COUCSI in presence of these forces, literature on the scaling of recovery is limited. To present appropriate scaling equations, two approaches have been examined on the main governing equation; (1) inspectional analysis and (2) applying an approximate analytical solution. The scaling equations based on the latter approach give better results than those derived from the inspectional analysis and scaling equations in the literature, as well. The new scaling equations accounting for the resistive gravity forces and relative permeability and capillary pressure properties are presented, which are consistent with the common scaling situations, as well.

Wastewater from shale oil and gas wells is an issue that has received significant attention although limited research has been conducted on the variability of water production from hydraulically fractured wells. In this paper, sources of variability in flowback and produced water volumes from horizontal oil and gas wells were examined and correlations established. Horizontal wells in the Denver-Julesburg basin operated by Noble Energy were studied and results show that water production varies with time, location and wellbore length as expected. Additionally, production volume variation with fracturing fluid type and water source (fresh versus recycled) was explored. Results indicate that both of these variables should also be considered when developing a general model for water production. A guar based frac fluid resulted in greater water production when compared to a cellulose-derivative based fluid. Finally, wells fraced with a fresh water based fluid had significantly greater produced water volume than geospatially-paired wells with a 1/7-recycled/fresh blend based fluid.

One of the limitations of gas or water injection in tight shale oil reservoirs is that the fluid injectivity is low due to the nature of very low permeability of shale. Another challenge of gas flooding is that the injected gas is subject to early breakthrough in densely fractured shale gas or oil reservoirs, resulting in poor performance. Cyclic gas injection (CGI) in a single horizontal well is not affected by early gas breakthrough. Compared to gas flooding, cyclic gas injection is an effective recovery process in tight shale oil reservoirs. This paper presented our experimental work on using nitrogen cyclic injection in shale rocks. We analyzed the experimental data using numerical simulation approaches. Coreflooding and simulation outputs showed that it is favorable to implement cyclic gas injection enhanced oil recovery process in shale oil reservoirs.

Our experimental data and simulation results have demonstrated the potential of gas huff-n-puff injection to improve oil recovery in shale oil reservoirs. We also examined the effect of diffusion on improved oil recovery performance by cyclic injection process. The objective of this paper is to investigate significance of possible factors on gas huff-n-puff recovery process in shale oil reservoirs via experimental work and simulation approaches. Our simulation results benchmarked with experimental observations showed that molecular diffusion played a significant role in the mobilization of oil in lab scale.

The production of heavy oil and bitumen requires unconventional methods. One such approach is steam-assisted gravity drainage (SAGD). This technology has key advantages but is characterized with substantial levels of water consumption and discharge. Therefore, there is a need for effective water treatment and reuse methods in SAGD. This paper examines the use of an emerging technology: thermal membrane distillation (TMD) as an integral part of water treatment for SAGD. Synergistic effects are exploited from heat and mass integration of SAGD and TMD. Specifically, the hot produced water and blowdown water are evaluated for treatment using TMD because of their thermal content and because of the need for high levels of purity which can be achieved by TMD. Several design configurations and scenarios are proposed and evaluated to assess the technical and economic viability of including TMD as a process in water-management systems for SAGD.

Significant exploration risks are associated with the pursuit of deeply-buried shale gas reservoirs due to pore volume reduction and changes in pore size distribution. These changes in pore character result in decreases in gas in place and permeability. A suite of shale, low grade, pelitic metamorphic and a granite outcrop samples from various location in North America have been selected to span the later stages of diagenetic, epimetamorphic (epizone) and anchimetamorphic (anchizone) processes to evaluate the changes in the inorganic pore volumes and size distributions. Diagenetic/metamorphic ranking of samples were determined by the illite crystallinity method. Pore volumes reduce with increasing maturity/metamorphic grade. The loss of mesopore volume (2–50 nm) with increasing maturity is the cause of the reduction in porosity. The reduction in mesopore volume is interpreted to be due to the authigenic recrystallization and growth of the clay minerals. As maturity/metamorphic grade increases there is a relative increase in the macropore (>50 nm) and micropore (<2 nm) size fractions. The increase in micropore volumes may be attributed to the development of secondary porosity within the kerogen. At higher maturity/metamorphic grade (i.e., illite crystallinity < 0.2 Δ2θ) porosity values range between 0.9% and 3.6% indicating that fracture porosity is not the only mechanism of gas storage in deeply buried shale (and pelitic metamorphic rocks) reservoirs. Matrix porosities in these higher maturity/metamorphic samples are comparable to matrix porosities of the Horn River shales of British Columbia and other shale reservoirs. Similar to the Horn River and Doig–Montney shales, the reduction in mesopore volumes may reduce the matrix permeability of these rocks and fracture stimulation will be an integral component of the completions program to access hydrocarbons.

There is a nationwide trend to develop shale formations due to advances in horizontal drilling and hydraulic fracturing technology. The Barnett Shale in north Texas is one of the largest onshore natural gas fields in the US, and has experienced exponential growth since the 1990’s. This immense amount of well development and gas production has occurred near heavily populated, urban areas, leading to increased public concern regarding the impacts of these activities on human health and welfare. The Texas Commission on Environmental Quality (TCEQ) is charged with regulating sources of air emissions from natural gas operations (NGOs) and is in a unique position to evaluate any associated risks. The goal of this manuscript is to describe the problem formulation process used by the TCEQ to characterize risks associated with air emissions from NGOs, and the subsequent risk management strategies implemented. Details on how potential sources of risk to human health were identified and quantified are provided. Initial assessments identified volatile organic compounds (VOCs) as chemicals of concern. Over 4.7 million data points for VOCs were used in this assessment on both a short-term and long-term basis. Only three short-term samples measured VOCs above short-term health-based air monitoring comparison values (AMCVs). Several short-term samples measured VOCs above odor-based AMCVs. Long-term VOC levels were below long-term health-based AMCVs. We describe efforts to engage stakeholders early in the risk assessment process and outreach programs used. Finally, details on new rules and regulations that are being used to more efficiently manage risks are provided. Given the resources and experience TCEQ possesses to evaluate environmental impacts that may be caused by shale gas development and production, it is our hope that this manuscript may serve as a resource to others to identify and manage risks associated with oil and gas activities in their area.

Early transient flow corresponds to the period before the effect fluid depletion has reached the nearest reservoir no-flow boundary. Production from unconventional reservoirs tends to exhibit extended periods of early transient flow because of their low permeabilities. Massive flow areas are generated, typically through the creation of multiple fractures in horizontal wells, to feasibly produce hydrocarbons from these formations at economic rates. The presence of these fractures leads to a series of non-radial flow regimes, which may continuously change before reservoir no-flow boundaries are reached, with linear flow being one of the dominant regimes. One of the significant challenges in this area has been devising a proper production analysis technique applicable to the analysis of early transient flow data. Progress has been made in the area through the use of the concept of the region of influence, which accounts for the portion of reservoir volume responsible for early transient production. In this study, we propose to implement a density-based approach to analyze early transient production data. In the density-based approach, rate-time responses of gas reservoir system are predicted by rescaling the responses of liquid system with depletion driven variables. The density-based technique has previously proven applicable to boundary-dominated radial-flow, and has been extended to analyze boundary-dominated linear-flow behavior. In this work, we show that early transient flow behaviors can be analyzed using the density-based method that incorporates region of influence concept into rescaling variables, $\overline{\lambda }-\overline{\beta }$ calculations. A density-based procedure is proposed to analyze early transient production data and its applicability is verified using simulated rate-time data. Results show that the proposed method can effectively predict Contacted Gas In-Place and the fracture half-length and square root of permeability product. The density-based methodology provides an alternative and reliable means to model and analyze data from gas reservoirs exhibiting extended early transient production.

The U.S. has experienced a resurgence of the upstream hydrocarbon sector in recent years, owing to the economic extraction of oil and gas from ultra-tight reservoirs using multistage hydraulic fracturing in horizontal wells. This success is often attributed to slick-water stimulation treatments that help create extensive complexity and contact with the low permeability reservoir. In this process, hundreds of thousands of barrels of water are pumped downhole, along with friction reducers, low concentration linear gel, fracture propping sand and other additives, to create and sustain these fractures. However, only a small percentage of this stimulation water is recovered back once the well is put back on production. This not only leads to excessive water hauling costs for operators in each consecutive well but also liquid blockage for hydrocarbon flow. Such water blockage/loading may become a serious concern in dry gas reservoirs such as the Marcellus field in the northeastern U.S., due to the unfavorable hydrocarbon mobility ratios. In spite of its implications on early and late time well performance, the issue of hydraulic fracture cleanup and gas flowback through it when drained through a horizontal wellbore is still an insufficiently understood subject. In this study the authors investigate the potential of liquid loading (stimulation water or condensate) within the hydraulic fracture itself due to low matrix permeability and insufficient drawdown conditions. Similar conditions may also arise late in the life of well when the reservoir pressure has declined significantly or due to wellbore design issues. A 3D reservoir simulation model with a discrete, planar hydraulic fracture is set up to investigate the competition between capillary, viscous and gravity forces within the fracture. The results indicate a strong tendency for liquid loading in the ultra-low permeability gas reservoirs under common operational constraints and offer recommendations on best practices to minimize its impact.

Huge shale resources available and low gas price turn the oil operators’ activities to producing more liquid oil. The earlier studies from our research group and others show that huff-n-puff has the highest potential to improve oil recovery (IOR) in shale oil reservoirs, compared with common IOR methods of gas flooding and waterflooding. This paper is to extend the research to shale gas condensate reservoirs to evaluate the IOR potential. The simulation analysis approach is used.

The simulation results and discussions in this paper show that huff-n-puff injection of produced gases can produce more liquid oil in gas condensate reservoirs than gas flooding or primary depletion. This result is verified by all the simulated cases with different reservoir and fluid properties and operation conditions. The advantages of huff-n-puff over gas flooding are the early response to gas injection, high drawdown pressure, oil saturation decrease near the wellbore by evaporation, and overcoming the pressure transport problem owing to ultra-low permeability. The advantages become more important when the initial reservoir pressure is close to the dew point pressure, or the bottom-hole flowing pressure is low. The effects of injected gas composition, cycle time and soak time during the huff-n-puff process are investigated. A simple economic analysis is also conducted.