Wang, Yang (China University of Petroleum – Beijing and Pennsylvania State University) | Cheng, Shiqing (China University of Petroleum – Beijing) | Zhang, Kaidi (Lusheng Petroleum Development Co., Ltd, SINOPEC Shengli Oilfield Company) | Xu, Jianchun (China University of Petroleum – East China) | Qin, Jiazheng (China University of Petroleum – Beijing) | He, Youwei (China University of Petroleum – Beijing and Texas A&M University) | Luo, Le (China University of Petroleum – Beijing) | Yu, Haiyang (China University of Petroleum – Beijing)
Pressure-transient analysis (PTA) of water injectors with waterflood-induced fractures (WIFs) is much more complicated than hydraulic fracturing producers due to the variation of fracture properties in the shutting time. In plenty of cases, current analysis techniques could result in misleading interpretations if the WIFs are not well realized or characterized. This paper presents a comprehensive analysis for five cases that focuses on the interpretation of different types of pressure responses in water injectors.
The characteristic of radial composite model of water injector indicates the water erosion and expansion of mini-fractures in the inner region. The commonplace phenomena of prolonged storage effect, bi-storage effect and interpreted considerably large storage coefficient suggest that WIF(s) may be induced by long time water injection. Based on this interpreted large storage coefficient, fracture half-length can be obtained. In the meanwhile, the fracture length shrinks and fracture conductivity decreases as the closing of WIF, which has a considerable influence on pressure responses. Results show that the upward of pressure derivative curve may not only be caused by closed outer boundary condition, but also the decreasing of fracture conductivity (DFC). As for multiple WIFs, they would close successively after shutting in the well due to the different stress conditions perpendicular to fracture walls, which behaves as several unit slopes on the pressure derivative curves in the log-log plot.
Aiming at different representative types of pressure responses cases in Huaqing reservoir, Changqing Oilfield, we innovatively analyze them from a different perspective and get a new understanding of water injector behaviors with WIF(s), which provides a guideline for the interpretation of water injection wells in tight reservoirs.
Yu, Wei (Texas A&M University) | Zhang, Yuan (China University of Geosciences Beijing) | Varavei, Abdoljalil (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin) | Zhang, Tongwei (The University of Texas at Austin) | Wu, Kan (Texas A&M University) | Miao, Jijun (SimTech LLC)
The effectiveness of CO2 injection as a Huff-n-Puff process in tight oil reservoirs with complex fractures needs to be investigated due to the fast decline of primary production and low recovery factor. Although numerous experimental and numerical studies have proven the potential of CO2 Huff-n-Puff, relatively few numerical compositional models exist to comprehensively and efficiently simulate and evaluate CO2 Huff-n-Puff considering CO2 molecular diffusion, nanopore confinement, and complex fractures based on an actual tight-oil well. The objective of this study is to introduce a numerical compositional model with an embedded discrete fracture model (EDFM) method to simulate CO2 Huff-n-Puff in an actual Eagle Ford tight oil well. Through non-neighboring connections, the EDFM method can properly and efficiently handle any complex fracture geometries without the need of local grid refinement (LGR) nearby fractures. Based on the actual Eagle Ford well, we build a 3D reservoir model including one horizontal well and multiple hydraulic and natural fractures. Six fluid pseudocomponents were considered. We performed history matching with measured flow rates and bottomhole pressure using the EDFM and LGR methods. The comparison results show that a good history match was obtained and a great agreement between EDFM and LGR was achieved. However, the EDFM method performs faster than the LGR method. After history matching, we evaluated the CO2 Huff-n-Puff effectiveness considering CO2 molecular diffusion and nanopore confinement. The traditional phase equilibrium calculation was modified to calculate the critical fluid properties with nanopore confinement. The simulation results show that the CO2 Huff-n-Puff with smaller CO2 diffusion coefficients underperforms the primary production without CO2 injection; nevertheless, the CO2 Huff-n-Puff with larger CO2 diffusion coefficients performs better than the primary production. In addition, both CO2 molecular diffusion and nanopore confinement are favorable for the CO2 Huff-n-Puff effectiveness. The relative increase of cumulative oil production after 7300 days with CO2 diffusion coefficient of 0.01 cm2/s and nanopore size of 10 nm is about 12% for this actual Eagle Ford well. Furthermore, when considering complex natural fractures, the relative increase of cumulative oil production is about 8%. This study provides critical insights into a better understanding of the impacts of CO2 molecular diffusion, nanopore confinement, and complex natural fractures on well performance during CO2 Huff-n-Puff process in the Eagle Ford tight oil reservoirs.
Ross, T. S. (New Mexico Institute of Mining & Technology) | Rahnema, H. (New Mexico Institute of Mining & Technology) | Nwachukwu, C. (New Mexico Institute of Mining & Technology) | Alebiosu, O. (ConocoPhillips Co) | Shabani, B. (Oklahoma State University)
Steam injection—a thermal-based enhanced oil recovery (EOR) process—is used to improve fluid mobility within a reservoir, and it is well known that it yields positive results in heavy-oil reservoirs. In theory, steam injection has the potential of being applied in light-oil reservoirs to enable vaporization of in-situ reservoir fluids, but field developments and scientific studies of this application are sparse. Conventional displacement methods like water-flooding and gas-flooding have been applied to some extent, however, oil extraction in such reservoirs relies on recovery mechanisms like capillary imbibition or gravity drainage to recover oil from the reservoir matrix. Furthermore, low-permeability reservoir rocks are associated with low gravity drainage and high residual oil saturation.
The objective of this study is to evaluate the potential of steam injection for light (47°API) oil extraction in naturally-fractured reservoirs. It is theorized that this method will serve as an effective tool for recovery of light hydrocarbons through naturally-fractured networks with the benefit of heat conduction through the rock matrix. This research investigates the application of light-oil steamflood (LOSF) in naturally- fractured reservoirs (NFR).
A simulation model comprised of a matrix block surrounded by fracture network was used to study oil recovery potential under steam injection. To simulate gravity drainage, steam was injected through a horizontal well completed in the upper section of the fracture network, while the production well was completed at the bottom of the fracture network. The simulation included two different porous media: (1) natural fractures and (2) matrix blocks. Each of these porous media was assumed to be homogeneous and characterized based on typical reservoir properties for carbonate formations. This study also analyzed the impact of different recovery mechanisms during steam injection for a light-oil sample in NFR, with reservoir sensitivity examined, based on varying amounts of vaporization, injection rate, permeability, matrix height and capillary pressure. Of these, vaporization was found to be the dominant factor in the application of LOSF in NFR, as described in detail within the results.
Holubnyak, Yevhen (Kansas Geological Survey) | Watney, Willard (Kansas Geological Survey) | Hollenbach, Jennifer (Kansas Geological Survey) | Rush, Jason (Kansas Geological Survey) | Fazelalavi, Mina (Kansas Geological Survey) | Bidgoli, Tandis (Kansas Geological Survey) | Wreath, Dana (Berexco LLC)
Baseline geologic characterization, geologic model development, studies of oil composition and properties, miscibility pressure estimations, geochemical characterization, reservoir modelling were performed. In March of 2015 the injection well (class II) KGS 2-32 was drilled, cored, and logged through an entire anticipated injection interval. Whole core samples were obtained and tested for porosity and permeability, relative permeability, and capillary pressure. The Drill Stem Test (DST) was also conducted to estimate injection interval permeability and pore-pressure. After the injection well KGS 2-32 was acidized, Step Rate (SRT) and Interference (IT) tests were conducted and analysed for permeability, well pattern communication, and fracture closing pressure.
Approximately 20,000 metric tons of CO2 was injected in the upper part of the Mississippian reservoir to verify CO2 EOR viability in carbonate reservoirs and evaluate a potential of transitioning to geologic CO2 storage through EOR. Total of 1,101 truckloads, 19,803 metric tons, average of 120 tonnes per day were delivered over the course of injection that lasted from January 9 to June 21, 2016. After cessation of CO2 injection, KGS 2-32 well was converted to water injector and is currently continues to operate. CO2 EOR progression in the field was monitored weekly with fluid level, temperature, and production recording, and formation fluid composition sampling.
As a result of CO2 injection observed incremental average oil production increase is ~68% with only ~18% of injected CO2 produced back. Simple but robust monitoring technologies proved to be very efficient in detection and locating of CO2. High CO2 reservoir retentions with low yields within actively producing field could help to estimate real-world risks of CO2 geological storage.
Wellington filed CO2 EOR was executed in a controlled environment with high efficiency. This case study proves that CO2 EOR could be successfully applied in Kansas carbonate reservoirs if CO2 sources and associated infrastructure is available.
Fredriksen, S. B. (University of Bergen) | Alcorn, Z. P. (University of Bergen) | Frøland, A. (University of Bergen) | Viken, A. (University of Bergen) | Rognmo, A. U. (University of Bergen) | Seland, J. G. (University of Bergen) | Ersland, G. (University of Bergen) | Fernø, M. A. (University of Bergen) | Graue, A. (University of Bergen)
An integrated enhanced oil recovery (IEOR) approach is presented for fractured oil-wet carbonate reservoirs using surfactant pre-floods to alter wettability, establish conditions for capillary continuity and improve tertiary CO2 foam injections. Surfactant pre-floods, prior to CO2 foam injection, alter the wettability of fracture surface towards weakly water-wet conditions to reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity transmits differential pressure across fractures and increases both mobility control and viscous displacement during CO2 foam injection. Outcrop core plugs were aged to reflect conditions of an ongoing CO2 foam field pilot in West Texas. A range of surfactants were screened for their ability to change wetting state from oil-wet to water-wet. A cationic surfactant was the most effective in shifting the moderately oil-wet cores towards weakly water-wet conditions (from an Amott-Harvey index of - 0.56 ± 0.01 to 0.09 ± 0.02), and was used for pre-floods during IEOR. When applying a surfactant pre-flood in a fractured core system, 32 ± 4% points OOIP was additionally recovered by CO2 foam injection after secondary waterflooding. We argue the enhanced oil recovery is attributed to the surfactant successfully reducing the capillary entry pressure of the oil-wet matrix providing capillary continuity and enhancing volumetric sweep during tertiary CO2 foam injection.
Over the last decade, unconventional resources like the Bakken formation have revolutionized the petroleum industry, but they have only produced by primary mechanisms, and recovery factors have remained low. The need for IOR processes is clear, but there has only been minor work in this area and no commercial field applications. Flow simulation models can be used to test different methods without interrupting field operations, but models have had a poor track record for unconventional IOR, partly because there is little field injection information to validate the models. In this work, we history matched the model to an IOR injection pilot location in Mountrail County, North Dakota that included both water and gas injection tests.
A county sized geologic model was previously constructed based upon available core, log and geologic information. The model allows for easy extraction of smaller segments for flow simulation. For the current study, a segment around the pilot injection area was isolated. The injection well and two offset producing wells were included in the model. Fluids were added into the model based on a nearby PVT report, and the hydraulic fracturing was captured with a dual permeability grid. The model was matched to the historical production and injection data. At the offset wells, breakthrough times, water cuts and gas oil ratios were also reproduced by changing the fracture and matrix properties.
By matching the injection data, the interwell connectivity is reproduced, which should improve predictions from the model. Various situations were then tested with the model including both gas and water injection scenarios. In the actual field pilot, gas was only injected for two months in the injection well, and there was only a minor response. In one scenario, therefore, we injected into all three wells in a huff-n-puff manner for ten years, and the results showed significant additional oil recovered – 30% more than the primary recovery. In other scenarios, water was injected in both a continuous and huff-n-puff manner. The continuous case had early breakthrough and poor sweep, but the huff-n-puff injection case indicated that oil rates would increase almost as much as the best gas injection cases.
This work shows that by reproducing the field injection data in unconventional reservoirs, more realistic models are created. We evaluated a large number of scenarios, and some of them did not show any increase in oil production, but the models that did show an increase helped us identify IOR techniques that have a better chance of success in the Bakken, which will improve designing the much needed next generation of field pilot tests.
This paper describes the use of advanced completions employing passive inflow control devices (ICD) and autonomous inflow control devices (AICD) in multi-zone horizontal wells to improve the distribution of gas injection and to restrict premature production of gas in gas injection soak EOR process for unconventional oil wells.
The recovery efficiency of unconventional oil reserves is very low due to the micro-permeability of these reservoirs and rapid depletion of pore pressure proximal to the fractures and wellbore. Several enhanced oil recovery schemes have been proposed to stimulate production and increase recovery efficiency in these reservoirs by injecting gas or carbon dioxide in fracture stimulated, long horizontal wells, and either producing oil from adjacent wells (gas injection flooding drive mechanism), or by back-producing the injectant and reservoir fluids in the same wellbore after a suitable "soak" period (huff and puff).
The effective distribution of the injected gas in these wells and the ability to keep the gas in the reservoir to maintain energy can greatly affect the recovery efficiency that can be achieved. Advanced completions utilizing appropriately designed ICDs and AICDs can enhance the performance of these EOR schemes.
ICDs can be used to balance the distribution of gas injection along the length of the wellbore, while AICDs can help control the early back-production of gas. The Autonomous Inflow Control Device (AICD) is an active flow control device that delivers a variable flow restriction in response to the properties (viscosity) of the fluid flowing through it. Water or gas flowing through the device is restricted more than oil. When used in a horizontal well, segmented into multiple compartments, this design prevents excessive production of gas after breakthrough occurs in one or more compartments.
The implementation of advanced completions in EOR applications has been studied by reservoir and well performance simulation. This proper use of ICDs and AICDs in these applications can significantly improve recovery efficiency without further well intervention.
To evaluate the performance of the AICD, a comprehensive multi-phase flow model of the autonomous performance has been developed and workflow created for simulation of performance within the reservoir. This paper will describe the experience with the technology and modelling prediction for EOR projects.
Kazempour, Mahdi (Nalco-Champion, an Ecolab Company) | Kiani, Mojtaba (Nalco-Champion, an Ecolab Company) | Nguyen, Duy (Nalco-Champion, an Ecolab Company) | Salehi, Mehdi (Nalco-Champion, an Ecolab Company) | Lantz, Mike (Nalco-Champion, an Ecolab Company)
In recent years, the United States (US) has experienced a resurrection in hydrocarbon recovery owing to the extraction of oil and gas from unconventional resources. Due to the ultra-low permeability nature of these reservoirs and their oil-wet characteristics, oil production declines are steep and oil recoveries remain very low (< 12% of OOIP). This challenge endures even with the assistance of hydraulic fracturing advancements and well spacing optimizations. The billions of barrels of remaining oil is a good target for chemical enhanced oil recovery (EOR) technologies.
In this study, after comprehensive laboratory testing, a series of customized chemical formulations was developed to improve oil recovery under the challenging conditions of the Middle Bakken and Niobrara formations (temperature >110 °C, salinity>220,000 ppm, and hardness>15,000 ppm). To examine the performance of the selected formulation in the field-scale, a single well enhancement trial was carried out. A detailed review of the lab and field data (pre-and post-treatment) is discussed in this study. Oil rate decline analysis and numerical simulations were used to obtain more insight about the true effectiveness of the chemical treatments. The results of this field trial reveal that injecting a proper wettability altering agent can improve oil recovery from shale oil reservoirs by up to 25% of the estimated ultimate recovery (EUR). The results of numerical simulations also show that the additional oil recovered in this field trial cannot be achieved by either well shut-in or straight water injection.
The lessons learned from this study provide practical information to optimize similar field trial designs leading to more profitable projects. The concepts and information here can be also translated to other unconventional basins and gas condensate or wet/dry gas reservoirs.
Oil production from tight formations such as the Bakken Formation has experienced a boom in the last decade with recent breakthroughs in horizontal drilling and hydraulic fracturing. However, despite the technological progress, the oil recovery is still less than 10 percent, leaving a huge amount of potentially recoverable oil in the reservoir. While miscible flooding is well understood in conventional reservoir, it is not fully explored in unconventional reservoirs. Therefore, it is very important to evaluate the potential of different enhanced oil recovery techniques in tight shale plays.
In this paper, we have studied CO2, methane, and nitrogen interactions with oil in reservoir conditions through laboratory experiments and examined their effects on the ultimate oil recovery. Several core flood experiments were conducted using CO2, methane, and nitrogen as the EOR agents and their results were compared. Next, numerical simulation was employed to model the process where the experimental results were used to validate and tune the simulation model.
In this work, the potential of different EOR processes was investigated in the formation, and comparisons were made to help better choose optimal EOR techniques and methodologies. It was observed that CO2 would outperform other EOR gases due to its miscibility with oil.
This paper examines a priori equation to describe recovery factors of EOR processes in oil shale plays. The existing studies imply promising future for implementing gas cyclic injection through hydraulically fractured wells completed in shale plays; the EOR agent (a mixture of HC gas or CO2) is injected and after a soaking period, the well is put back on production. However, translation of lab-scale EOR results to field-scale is yet to be resolved. Dynamic penetration volume (DPV) controls the amount of contacted oil by the EOR agent (fluid-fluid interface), slowly grows with
We use a combination of modeling, theoretical, and experimental work to investigate potential recovery loss in well-scale compared to recovery measured in the lab-scale. In our formulation, the recovery in pilot-scale is defined as the product of recovery in lab-scale by field factor. Recovery in lab-scale is a function of pressure drawdown during production (choke effect). Choke-size controls how fast the mixture of gas and vaporized oil components will be produced back after soaking time.
Field factor entails two parameters that control how much of in-situ liquid hydrocarbon can potentially interact with EOR agent; basically, field factor is evaluated as a fraction of reservoir volume prescribed within inter-well spacing accessible to the EOR agent when injection process begins. Field factor is calculated as a product of fraction of stimulated reservoir volume (SRV) accessible to EOR agent (DPV/SRV) at any given time by fraction of reservoir volume stimulated during fracturing; SRV is controlled by the efficiency of fracturing treatment. The pore connectivity loss can occur because of the physical closure of flow path at the fracture-matrix interface and/or two-phase blockage. The limiting two phase phenomena that can potentially prevent the injected gas from getting into pore space because of capillary forces.
Our results suggest that recovery in the pilot-scale can be significantly reduced owing to pore connectivity loss (a factor of two). The pore connectivity is reduced as pore pressure decreases and effective stress increases. We evaluate change of fluid conductivity under stress and differentiate contribution of pore connectivity loss and pore shrinkage. Moreover, our results suggest that chokes size effect observed in the experiments can be explained by loss of pore connectivity.
For the first time, an equation is presented to upscale the EOR results obtained in lab-scale to pilot-scale. The outcome is expected to help operators with the pilot-test performance evaluations.