Mu, Lingyu (China University of Petroleum Beijing) | Liao, Xinwei (China University of Petroleum Beijing) | Zhao, Xiaoliang (China University of Petroleum Beijing) | Zhang, Jingtian (CNPC Engineering Technology R&D Company Limited) | Zou, Jiandong (China University of Petroleum Beijing) | Chu, Hongyang (China University of Petroleum Beijing) | Shang, Xiongtao (China University of Petroleum Beijing)
Due to the special micro-pore structure and the seepage law of tight reservoirs, the research on the development of tight oil is quite different from conventional reservoirs. For the tight oil reservoirs recovered with the gas injection, the gas breakthrough is an eternal theme as a result of the preferable mobility of the gas and the strong heterogeneity of the reservoirs. It is extremely important to evaluate the sweep efficiency. Based on the stream-tube method and the non-Darcy theory, this paper establishes a rapid evaluation technique of sweep efficiency considering the mechanism of the gas flooding and the seepage characteristics of the tight oil reservoir.
Firstly, the relative permeability under different miscible condition are determined through the revised Coats model. Besides, the Todd-Longstaff model is adopted to describe the varying viscosities of oil and gas. Secondly, the stream-tube model of the inverted nine-spot well pattern with fracture is established. Next, the seepage equations of oil and gas in the stream-tube is constructed considering the threshold pressure and the variation of the viscosity and relative permeability. Then, the sweep efficiency is obtained by solving these equations. Furthermore, an application example for evaluating the sweep efficiency is presented and sensitivity analyses are conducted to study the effect of the viscosity, pressure difference, fracture permeability and well spacing taking the case of a real tight reservoir.
Through the analyses, it can be concluded that the factors have remarkable impacts on the sweep efficiency. The threshold pressure increases the resistance and reduces the flow rate, leading to a lower sweep of the injected gas. Even worse, the excessive threshold pressure results in that the effective displacement cannot be established. The fracture greatly shortened the breakthrough time and result in early channeling of the injected gas. The sweep efficiency is improved through the increase of the pressure difference and decrease of the well distance. Consequently, in order to improve the sweep efficiency of the tight reservoirs, a reasonable displacement pressure difference and a well pattern adapted to the reservoir are needed. This paper presents a rapid and effective technology to evaluate the sweep efficiency of the tight reservoirs recovered with gas injection, which provides an important basis for improving the sweep efficiency and fine development of the tight reservoir.
In the Williston Basin, thin reservoirs coupled with large stimulation jobs result in large vertical hydraulic fractures and out-of-zone contribution of fluids to the wells. To understand the extent of vertical fracture growth and the source of fluids reaching the wellbore, the time-lapse elemental and isotopic composition of produced waters were compared with the in-situ pore water chemistry reconstructed from core analysis (residual salts analysis (RSA)) for a set of wells in Williams county, ND.
Residual salts analysis was performed on 28 core plugs from the Lodgepole (LP), Upper Bakken Shale (UBS), Middle Bakken (MB), Lower Bakken Shale (LBS), and Three Forks (TF). RSA data indicate that the sampled formations have distinct fingerprints, predominantly in terms of strontium abundance [Sr] and strontium isotopic compositions (87Sr/86Sr). Once baseline compositions for all formations were established, time-lapse produced water samples were taken from two lateral wells (1MB and 1TF; high-impact stimulation) proximal to the baseline RSA data. Time-lapse water chemistry from both lateral wells indicates that from initial flowback through 7 months of production >80% of the produced water is sourced predominantly from the TF with minimal water contribution from other formations. Large compositional changes in the produced water within this time-period are caused by operational disturbances and/or changes in flow rate.
Preliminary, these data suggest that high-impact stimulation results in large vertical hydraulic fractures that stay open for at least 7 months resulting in produced water being dominated by a TF source. Based on produced water data from older wells with lower-impact completions, the relative contribution of water from the TF diminishes over time indicating continued, but diminished communication with the TF. Results from this study also have implications about irreducible and critical water saturations, which both have critical impact in reservoir models. A comprehensive understanding of the origins of fluids from different subsurface storage units improves well stimulation and production programs and ultimately, well economics.
Unconventional resources such as Bakken shale have made a significant impact on the global energy industry, but the primary recovery factor still lingers from 5% to 15 %. Over the past ten years, a number of pilot tests for both gas and water injection or their cyclic injection have been implemented to improve oil recovery in the Bakken Formation. The available public data show that the injectivity is not a problem, but only a small increase in production. The obvious reason is unexpected early breakthroughs even with a relatively low reservoir permeability of around 0.03 mD. Lots of experimental and simulation studies have been conducted to investigate different mechanisms behind these improved oil recoveries. However, no one has succeeded to clarify this early breakthrough.
In this study, a simulation reservoir model, including two wells, is developed, whose properties are based on public data. In terms of hydraulic fractures for each well, their geometry and conductivities are evenly built. Furthermore, our geomechanical module is applied to capture the evolution of stress field and rock failure, where a Barton-Bandis model and a Mohr–Coulomb failure criterion are applied to model tensile and shear failure, respectively. Our simulation model coupled with the geomechanical module is then implemented to explain the performance of injection pilot test.
The results of this initial study clearly show the new fractures (frac-hits) induced by water injection connect the injection and production wells, resulting in the early water breakthrough. The stress field has also been altered by the production process to favor the formation of these fractures. This study highlights the importance of geomechanics during an IOR process; identifies the reasons for the early breakthrough and provides an insight view about how to improve oil production in the Bakken Formation.
Unconventional reservoirs such as the Eagle Ford have had tremendous success over the last decade, and while wells come on at high rates, they drop quickly and the recovery factors are low, which suggests the need for enhanced oil recovery. One method that has become popular is cyclic (huff-n-puff) gas injection. In this method, gas is injected down a well for some time, and then the injection well is turned back into a producer until the production drops, and the process is repeated. A few companies have successfully tested this in the field, and the production data clearly indicates that incremental oil is being produced, but the physical mechanisms for the additional recovery are not well understood.
In this paper, the relative significance of four proposed recovery mechanisms is examined: (1) oil swelling, (2) viscosity reduction, (3) vaporization, and (4) pressure support. A numerical flow simulation model is used to study these effects. A model of an unconventional reservoir is constructed where all these mechanisms are present and contributing to the recovery. To validate the model, it is history matched to a pilot gas injection project in the Eagle Ford. A primary case and a full gas injection case are completed. A run is also completed where all of the recovery mechanisms for gas injection are turned off, which provided a result that is similar to primary production. Then each mechanism is turned on and off (one at a time), and the model is re-ran to determine the relative contribution of each mechanism. This process is carried out for different reservoir fluids from low gas-oil-ratio (GOR) black oils to liquid rich gas condensate.
By evaluating the recovery mechanisms for fluids at various GORs, charts are created that show how important each mechanism is as a function of different reservoir fluids. All mechanisms provide some contribution, but their significance varies as a function of GOR. Pressure support provides similar small response for all fluid types. Vaporization is most important for gas condensate reservoirs (high GORs), but it plays a role for all fluid types. Oil swelling has a large impact for low GOR oils, but diminishes for higher GOR fluids, and viscosity reduction plays a minor role only for low GOR cases.
Most importantly, the impacts of the mechanisms on recovery are better understood for these processes. Currently huff-n-puff gas injection has been applied successfully in parts of the Eagle Ford, but this play has a wide range of in-situ fluid types; and likewise, other unconventional basins have a large variety of reservoir fluids. By better defining the recovery mechanisms for cyclic natural gas injection, EOR can be improved in existing unconventional plays and better designed for new areas.
Recent studies have indicated that Huff-n-Puff (HNP) gas injection has the potential to recover an additional 30-70% oil from multi-fractured horizontal wells in shale reservoirs. Nonetheless, this technique is very sensitive to production constraints and is impacted by uncertainty related to measurement quality (particularly frequency and resolution), and lack of constraining data. In this paper, a Bayesian workflow is provided to optimize the HNP process under uncertainty using a Duvernay shale well as an example.
Compositional simulations are conducted which incorporate a tuned PVT model and a set of measured cyclic injection/compaction pressure-sensitive permeability data. Markov chain Monte Carlo (McMC) is used to estimate the posterior distributions of the model uncertain variables by matching the primary production data. The McMC process is accelerated by employing an accurate proxy model (kriging) which is updated using a highly adaptive sampling algorithm. Gaussian Processes are then used to optimize the HNP control variables by maximizing the lower confidence interval (μ-σ) of cumulative oil production (after 10 years) across a fixed ensemble of uncertain variables sampled from posterior distributions.
The uncertain variable space includes several parameters representing reservoir and fracture properties. The posterior distributions for some parameters, such as primary fracture permeability and effective half-length, are narrower, while wider distributions are obtained for other parameters. The results indicate that the impact of uncertain variables on HNP performance is nonlinear. Some uncertain variables (such as molecular diffusion) that do not show strong sensitivity during the primary production strongly impact gas injection HNP performance. The results of optimization under uncertainty confirm that the lower confidence interval of cumulative oil production can be maximized by an injection time of around 1.5 months, a production time of around 2.5 months, and very short soaking times. In addition, a maximum injection rate and a flowing bottomhole pressure around the bubble point are required to ensure maximum incremental recovery. Analysis of the objective function surface highlights some other sets of production constraints with competitive results. Finally, the optimal set of production constraints, in combination with an ensemble of uncertain variables, results in a median HNP cumulative oil production that is 30% greater than that for primary production.
The application of a Bayesian framework for optimizing the HNP performance in a real shale reservoir is introduced for the first time. This work provides practical guidelines for the efficient application of advanced machine learning techniques for optimization under uncertainty, resulting in better decision making.
Yu, Wei (Texas A&M University and University of Texas at Austin) | Zhang, Yuan (China University of Geosciences, Beijing) | Varavei, Abdoljalil (University of Texas at Austin) | Sepehrnoori, Kamy (University of Texas at Austin) | Zhang, Tongwei (University of Texas at Austin) | Wu, Kan (Texas A&M University) | Miao, Jijun (SimTech)
Although numerous studies proved the potential of carbon dioxide (CO2) huff ’n’ puff, relatively few models exist to comprehensively and efficiently simulate CO2 huff ’n’ puff in a way that considers the effects of molecular diffusion, nanopore confinement, and complex fractures for CO2. The objective of this study was to introduce a numerical compositional model with an embedded-discrete-fracture-model (EDFM) method to simulate this process in an actual Eagle Ford tight oil well. Through nonneighboring connections (NNCs), the EDFM method can properly and efficiently handle any complex fracture geometries. We built a 3D reservoir model with six fluid pseudocomponents. We performed history-matching with measured flow rates and bottomhole pressure (BHP). Good agreements between field data, EDFM, and local grid refinement (LGR) were achieved. However, the EDFM method performed faster than the LGR method. After that, we evaluated the CO2-enhanced-oil-recovery (EOR) effectiveness for molecular diffusion and nanopore confinement effects. The traditional phase equilibrium calculation was modified to calculate the critical fluid properties with nanopore confinement. The simulation results showed that the CO2 EOR with larger diffusion coefficients performed better than the primary production. In addition, both effects were favorable for the CO2 huff ’n’ puff effectiveness. The relative increase of cumulative oil production after 20 years was approximately 12% for this well. Furthermore, when considering complex natural fractures, the relative increase of cumulative oil production was approximately 8%. This study provided critical insights into a better understanding of the impacts of CO2 molecular diffusion, nanopore confinement, and complex natural fractures on well performance during the CO2-EOR process in tight oil reservoirs.
The recent slump in oil prices has resulted in new terminology: “drilled uncompleted wells,” often referred to as DUC wells by the industry. In 2013 and 2014, when oil prices were more than USD 100/bbl, rate of return (ROR) from most unconventional plays was in the range of 15 to 50%, depending on the quality of rock and the operator’s portfolio in the basin. The objective of this paper is to address key challenges associated with DUC completions when they are eventually fractured and brought on line for production. The paper addresses four main concerns that can have significant impacts on productivity of DUC wells: fracture hits (well interference), reservoir quality (hydrocarbon drainage), multiple horizons (zone connectivity), and well spacing (high-density drilling). The paper also showcases case studies in which real-time observations made from wells have been used to validate predictions from forward-looking fracture and production models.
First, fracture hits commonly have been observed in all unconventional plays throughout the US, with effects on offset wells being mixed. Some fracture hits result in a positive uptick in production in offset wells, whereas other fracture hits affect production negatively in the form of increased water cut, reduced wellhead pressure, and other responses. Understanding fracture hits and their influence on other wells is very critical to avoid any detrimental impacts or to leverage positive effects on production. Second, reservoir quality decides how much oil in place is available for the DUC wells to drain, which, in turn, depends on length of production history and parent-well-completion geometries in offset wells. Third, in basins where there are multiple producing horizons or formations, fracture-height growth and interference between adjacent formations can result in asymmetric fracture propagation toward depleted zones. The longer these wells completed in the same/adjacent formations have been on production, the greater the extent of asymmetry will be. Addressing this concern requires a good understanding of drainage patterns from offset wells and evaluation of their impact on fracture geometries in DUC wells. Last, in areas with high-density drilling, a combination of longer production and fracturing stages with multiple perforation clusters per stage can leave very little oil available for the DUC well to produce.
Saini, Dayanand (California State University, Bakersfield) | Wright, Jacob (California State University, Bakersfield) | Mantas, Megan (California State University, Bakersfield) | Gomes, Charles (California State University, Bakersfield)
A critical analysis of the key geological characteristics, completion techniques, and production behaviors of the Monterey Shale wells and their comparisons with analogous major US shale plays—namely, the Bakken and the Eagle Ford—may provide insights that could eventually help the petroleum industry unlock its full potential. The present study reports on such efforts.
The Monterey Shale is very young and geologically heterogeneous compared with the Eagle Ford and the Bakken. Oil viscosity in the Monterey Shale is significantly higher, and one can also notice that Monterey oil production has declined over the years. The Monterey Shale has a field-dependent completion strategy (pattern spacing and fracturing stage), while a horizontal, uncemented wellbore completion is common in the Bakken and the Eagle Ford. In the Monterey, nonhydraulically fractured zones of horizontal and hydraulically fractured wells appear to be making approximately equal contributions to the well’s cumulative production. The ongoing water-disposal operations in overlying injection zones, up to a certain extent, have affected the productivity of both types (long and short production histories) of wells. The geology also appears to have an effect on the production behaviors of horizontal and hydraulically fractured wells.
A preliminary economic analysis suggests that exploitation of the Monterey Shale is still a profitable venture. However, for sustainable development in a current price regime of USD 50/bbl of crude oil, it is necessary that production costs be reduced further. Also, compared with the Bakken and the Eagle Ford, the Monterey sits in regions of extremely high water stress (i.e., frequent occurrences of drought or drought-like conditions). However, oilfield-produced water associated with current steamflooding-based oil- and gas-production operations in the region as a base fluid suggests that it can potentially meet most of the water demand for future fracturing jobs. Also, combined use of a centralized water-management system; a less-costly, more energy-efficient, and high-capacity solar-powered desalination system; and a final sludge-management and/or residual-brine-disposal mechanism might assist the petroleum industry in managing flowback and produced waters while keeping water-handling costs low.
A combination of new enhanced-oil-recovery (EOR) methods for releasing the remaining oil from both nonfractured and fractured zones of horizontal wells and the use of oilfield-produced and recycled water for completing hydraulically fractured horizontal wells might prove to be a significant change for the future exploitation of California’s Monterey Shale resource, which is subject to the toughest hydraulic-fracturing regulations in the nation and is in a region of extremely high water stress.
Alfarge, Dheiaa (Iraqi Ministry of Oil, Missouri University of Science and Technology) | Alsaba, Mortadha (Australian College of Kuwait) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
Over the last decade, Unconventional Liquids Rich Reservoirs (ULR) have become the main target for oil and gas investors as conventional formations started to deplete and diminish in numbers. These unconventional plays have a huge oil reserve; however, the primary oil recovery factor is predicted to be less than 10%. Unconventional Improved Oil Recovery (UIOR) techniques are still a new concept in the oil industry since there is no commercial project reported for any IOR technique yet. Miscible gas based EOR technique might be the most potential strategy to improve oil recovery in such complex plays.
In this study, a comprehensive and critical review has been conducted to evaluate the feasibility of miscible gas based EOR technique in ULR. The reports and studies from three different approaches (lab, simulation and pilot tests) were summarized and combined to provide in-depth insights and lessons learned from the applicability of miscible gas based EOR in ULR. Firstly, the main problems in the previous lab and simulation approaches, which were used to investigate the viability of different EOR methods, have been diagnosed. Secondly, the performance of injecting different miscible gases to enhance oil recovery in the pilot tests conducted in ULR has been extensively discussed. Thirdly, the physical and chemical reasoning behind the performance gap for the injected gases in the lab scale versus the field scale of ULR been diagnosed.
This study reported that most of the previous lab and simulation approaches suffered from significant lacks and drawbacks, which created a clear gap in the performance of the injected gases in the lab scale versus the field scale. This research clearly found that the performance of Natural Gas (NG) injection is significantly better than the performance of CO2 injection in terms of enhancing oil recovery in the field pilots. This study also found that the production response of unconventional reservoirs to the injected NGs is much faster than that for the injected CO2. Combining the pilot tests data and simulation studies showed that the number of cycles in huff-n-puff operations has a negative impact on CO2-EOR while it has a positive impact on NGs-EOR. Finally, this research provided deep insights on what the operators can expect from the EOR performance by injecting different miscible gases in the lab scale versus the field scale of ULR.
Multistage horizontal well designs have been used since 2007 in the Bakken oilfield of North Dakota. Since then over 12,000 wells have been completed in either the Middle Bakken or Three Forks zones. Early-time production rates as measured by 180-day state-reported cumulative production have increased 4-fold over this period as industry has pursued a program of innovation and continuous improvement in completions technology with production per well increasing in ten of the twelve years. Through a "Big-Data" analytical study comparing geological data, completions parameters, and statereported production results the authors have evaluated the fundamental changes that have guided industry to produce these results over the past twelve years. While geological changes in different areas drove both the drilling "mania" during times of $100 oil and consequent contraction of the industry when wellhead prices dropped below $40 per BO; it is the advances in completion design and hydraulic fracturing that have driven macro performance over the twelve years - and resulted in this significant increase in production per well. These completion advances have allowed the region to compete on a global scale with production that while dipping to 1.0 Million bopd in 2016 has now rebounded to over 1.2 Million bopd. Large datasets of geological, completions and production data take years to assemble and analyze. Through the authors use of multivariate analysis techniques this paper presents the deterministic factors affecting well performance in the Bakken and provides guidance and best practices towards applying these techniques in emerging international plays.