A fault is a potential pathway for fluid leakage, which can contaminate underground water resources. In addition, fault leakage can affect hydrocarbon production. This study aims to develop a type-curve-based methodology to characterize a fault both laterally and vertically using pressure transient analysis. We develop an analytical model to assess the pressure perturbations corresponding to production/injection from/into a reservoir with a leaky fault. Displacement of layers during the fault displacement may cause alteration of the reservoir properties across the fault. This alteration is accounted for by considering different properties on the two sides of the fault. The reservoir is divided into two regions separated by the fault, which are in hydraulic communication with one another and with the overlying/underlying permeable layers. The governing system of differential equations and corresponding boundary conditions are solved using Fourier and Laplace transforms. At early times of the fault leakage, the recorded well pressure changes are mostly affected by the fault properties and the effects of resistance from the upper zone emerge later. In this model, we neglect the resistance to leakage flow caused by the overlying zone to focus on the pressure changes at early times of the fault leakage. We show that these assumptions are valid to arrive at correct fault characteristics. For fault characterization, type curves are presented in terms of dimensionless vertical and horizontal conductivities of the fault. A computational optimization method is used in combination with type curves to fully characterize the reservoir-fault system. Results show that the characterization method is useful to estimate the fault vertical and lateral conductivities.
The Gas-Assisted Gravity Drainage (GAGD) process has been suggested to enhance oil recovery by placing vertical injectors for CO2 at the top of the reservoir with a series of horizontal producers located at the bottom. The injected gas accumulates to form a gas cap while oil and water drain down to the bottom due to their heavier densities. The GAGD process has limitations with regards to the high levels of water cut and high tendency of water coning. This paper provides an integration of water sink into the GAGD process to overcome these limitations.
The hybrid process of Gas Injection and Downhole Water Sink-Assisted Gravity Drainage (GDWS-AGD) was developed and tested to minimize water cut in oil production wells from reservoirs with bottom water drives and strong water coning tendencies. In the combined technologies, the 7 inch production casing are dual completed for two 2-3/8 inch horizontal tubings: one above the oil-water contact for oil production and one underneath for water sink. The two completions are hydraulically isolated inside the well by a packer. The bottom (water sink) completion employs a submersible pump and water-drainage perforations.
The submersible pump drains the formation water from around the well and prevents the water from breaking through the oil column and getting into the horizontal oil-producing perforations. The GDWS-AGD was efficiently adopted to improve oil recovery at the upper sandstone member/South Rumaila Oil Field, located in Iraq. The Rumaila field has an infinite active aquifer with very strong edge and bottom water drives. Many successive cases were conducted to obtain the clearest image about optimal setting of the combined processes. These cases include oil and water production only, oil and water production with constant pressure gas injection, and oil and water production with decreased pressure gas injection. The injection pressure needed to be periodically decreased in order to ensure immiscibility of CO2 flooding. In the GDWS-AGD, the produced water not only reduced water cut and coning, but also significantly reduced the reservoir pressure, resulting in improving gas injectivity. In addition, the GDWS-AGD process improved oil recovery to promising levels. More specifically, the results showed that oil recovery increased from 71% to 85% and water cut decreased from 98% to less than 5% in all the horizontal oil producers.
The novelty of GDWS-AGD process comes from its effectiveness to improve oil recovery with reducing the water coning, water cut, and improving gas injectivity. This leads to more economic implementation, especially with respect to the operational surface facilities.
Carbon dioxide (CO2) flooding is a mature technology in oil industry that finds broad attention in oil production during tertiary oil recovery (EOR). After about five decades of developments, there have been many successful reports for CO2 miscible flooding. However, operators recognized after considering the safety and economics that achieving miscible phases is one of big challenge in fields with extremely high minimum miscible pressure (MMP). Compared with CO2 miscible flooding, immiscible flooding of CO2 demonstrates the great potential under varying reservoir/fluid conditions. A comprehensive and high-quality data set for CO2 immiscible flooding is built in this study. Valuable guidelines have been concluded, and production prediction models are established to further assist the applicability of new projects for the first time. Results show that along with the current method in literature to find applicability guidelines, prediction models involved with important operation and production parameters help to increase the accuracy of CO2 immiscible applicabilities. Data involved in this study are checked for independence for feature selection before utilization. We also find that support vector machine could predict the enhanced oil production rate and CO2 injection efficiency better than multiple linear regression method based on the data set. Furthermore, the multiple linear regression method build an excellent model for the prediction of enhanced oil recovery with an accuracy of almost 100%.
A prediction model is a tool for decision making and problem solving that has been applied in variety of fields (e.g., medical science [1-3], meteorology , transportation [5, 6], business [7, 8], biology [9, 10], and chemistry [11, 12]) for further applicability evaluation. Eagle et al. built a prediction model to accurately estimate the risk of six month mortality after patients have been hospitalized for acute coronary syndrome (ACS), which provides guidance of the intensity of therapy to clinicians in clinical medicine . Gendt et al. established a numerical weather prediction model to help people to make plans for many activities (e.g., farmers to find the best time for harvest; pilots to schedule the safest path, etc. ). In a prediction model, prediction accuracy mainly depends on the methodology of prediction and the quality of data that fed into the model, which is one of the crucial indicator to evaluate the effectiveness of models that researchers spare no efforts to pursue as high of an accuracy as possible.
Unconventional resources have played a significant role in changing oil industry plans recently. Shale formations in North America such as Bakken, Niobrara, and Eagle Ford have huge oil in place, 100-900 Billion barrels of recoverable oil in Bakken only. However, the predicted primary recovery is still below 10%. Therefore, seeking for techniques to enhance oil recovery in these complex plays is inevitable. In this paper, two engineering-reversed approaches have been integrated to investigate the feasibility of CO2 huff-n-puff process in shale oil reservoirs. Firstly, a numerical simulation study was conducted to upscale the reported experimental-studies outcomes to the field conditions. As a result, different forward diagnostic plots have been generated from different combinations of CO2 physical mechanisms with different shale-reservoirs conditions. Secondly, different backward diagnostic plots have been produced from the history match with CO2 performances in fields’ pilots which were performed in Bakken formation of North Dakota and Montana. Finally, fitting the backward with the forward diagnostic plots was used to report and diagnose some findings regarding the injected-CO2 performance in field scale.
This study found that the porosity and permeability of natural fractures in shale reservoirs are significantly changed with production time, which in turn, led to a clear gap between CO2 performances in lab-conditions versus to what happened in field pilots. As a result, although experimental studies reported that CO2 molecular-diffusion mechanism has a significant impact on CO2 performance to extract oils from shale cores, pilot tests performances indicated a poor role for this mechanism in field conditions. Therefore, the bare upscaling process for the oil recovery improvement and the CO2-molecualr diffusion rate, which are obtained from CO2 injection in lab-cores, to the field scale via numerical simulations needs to be reconsidered. In addition, this study found that kinetics of oil recovery process in productive areas and CO2-diffusivity level are the keys to perform a successful CO2-EOR project. Furthermore, general guidelines have been produced from this work to perform successful CO2 projects in these complex plays. Finally, this paper provides a thorough idea about how CO2 performance is different in field scale of shale oil reservoirs as in lab-scale conditions.
Liu, Xiaochun (Research Institute of Oil and Gas Technology) | Ma, Liping (Research Institute of Oil and Gas Technology) | Tan, Junling (Research Institute of Oil and Gas Technology) | Yang, Tangying (Research Institute of Oil and Gas Technology) | Li, Xiaorong (Research Institute of Oil and Gas Technology) | Hou, Jirui (Research Institute of Enhanced Oil Recovery, China University of Petroleum) | Wei, Qi (Research Institute of Enhanced Oil Recovery, China University of Petroleum) | Hao, Hongda (Research Institute of Enhanced Oil Recovery, China University of Petroleum) | Song, Zhaojie (Research Institute of Enhanced Oil Recovery, China University of Petroleum) | Wang, Shitou (Research Institute of Oil and Gas Technology) | Bi, Weiyu (Research Institute of Oil and Gas Technology)
H-3 Block is an ultra-low permeability reservoir in Changqing oil field, China which had been waterflooded from 2009 and was switched to CO2 flooding in 2013 due to excess water production. However, the nature fractures in NE-SW region have resulted in early CO2 breakthrough and poor production performance. The investigation of CO2 production performance and the method to control CO2 production becomes a key to continue CO2-EOR project.
Outcrop cores are used to perform a series of CO2 flooding experiments at reservoir conditions of pressure, temperature and formation water salinity. Permeability heterogeneity and injection pressure are considered as two variables to affect gas channeling characteristics. It is figured out that producing gas-oil ratio and components analysis of effluent could be used to judge gas channeling and timing to control CO2 production for field use. Starch gel is developed to control CO2 production within nature fractures to improve CO2 swept volume in rock matrix. Ethylenediamine (EDA) is proposed to delay CO2 production within high-permeability zones, and the application boundary as a function of permeability heterogeneity is determined.
Three production stages are clearly stated based on production performance and experimental observation, including gas-free production stage, oil/gas co-production stage, and gas channeling stage. A significant new finding is that oil/gas co-production stage contributes the most to oil recovery. And oil-CO2 mass transfer zone, rather than free CO2, reaches the outlet at this stage, which is proved by color of effluent and chromatographic analysis. For field cases, producing gas-oil ratio and components analysis of effluent at wellhead could help field engineers make a decision: keep producing with caution at oil-gas co-production stage or control the CO2 production at gas channeling stage. The conformance improvement and the increase in injection pressure could remarkably enhance the oil recovery at oil/gas co-production stage. To delay gas channeling and extent oil/gas co-production stage, two-level gas channeling control is presented. A slug of starch gel is first injected to block fractures and then ethylenediamine is injected to react with in-situ CO2 within high-permeability zone. The starch gel, acting as pure viscous fluid, would not leave contamination in rock matrix. And the viscous reactant of ethylenediamine and in-situ CO2 could successfully tune injected CO2 to flood low-permeability zone when permeability ratio is less than 100.
After implications of hydraulic fracturing operations, the commercial production of tight formations and shale plays were successfully achieved in past decades. Due to the rapid decline rate after primary depletion of fractured reservoirs, extracting the remaining liquid hydrocarbon from the nano-Darcy permeability matrix becomes the next step.
Previously conducted laboratory experiments demonstrated promising results by successfully recovering liquid hydrocarbon from preserved and unfractured sidewall unconventional core plugs. However, what are the driving forces behind this observed result was not well understood. In other words, is the hydrocarbon recovery associated with commonly known recovery mechanisms during CO2 EOR processes, such as viscous displacement, oil volume expansion, viscosity reduction and vaporization of lighter hydrocarbon components? Or, is it driven by other mechanisms that are frequently considered insignificant during conventional CO2 EOR processes?
This study utilizes a commercial compositional simulator to investigate the oil production mechanisms from the matrix into the fractures. The process includes constructing a fine grid 3D model to simulate the previously conducted laboratory experiment, performing systematic sensitivity analysis, and evaluating the mechanisms that could potentially contribute to the oil recovery observed during the experiments. With laboratory scale modeling, the dominating mass transfer mechanism between the matrix and fractures, which in turn translates into oil recovery mechanism, is concluded to be diffusion. The work provided in this study can be used to enhance the accuracy for upscaled field simulations. However, whether CO2 EOR will unlock the unconventional liquid reservoir potential and make significant economic impacts at field scale needs to be carefully evaluated on a case by case basis.
For the past few decades, due to the increasing demand of energy and the advancements in horizontal drilling and hydraulic fracturing technologies, the industry reallocated its resources into exploring ways to produce oil from the previously unprofitable shale plays.
Relative permeability of CO2 and brine is one of the fundamental parameters controlling flow related to carbon storage in saline aquifers. Core samples recovered from subsurface formations are characterized in laboratory experiments to determine effective core relative permeability curves. Typically, coreflooding experiments are conducted at high injection rates so that the resulting flow is viscous dominated. However, at lower rates, it has been shown that the effective curves may change as capillary heterogeneity effects become significant. Using relative permeability determined by conventional coreflooding in simulations with low flow rates, e.g., to model CO2 migration in aquifers, may incur significant error.
A new method for calculating low flow rate relative permeability curves is presented. The method is based on approximate analytical solutions for effective relative permeability under steady state and capillary limit flow conditions. Derivation is carried out using power law averaging, assuming log normally distributed core permeability. We validate the analytical solution by comparison to numerical solutions for a wide range of cases. An additional correction for the CO2 curves is shown to be necessary and derived by matching analytical and numerical results. Given a core which has been characterized by conventional high rate coreflooding experiments, the current method gives a fast and efficient correction for low flow rate applications. It circumvents the need for additional experiments or computationally expensive coreflooding simulations.
Yuan, Zhou (China University of Petroleum) | Zhang, Kuaile (China University of Petroleum) | Liao, Xinwei (MOE Key Laboratory of Petroleum Engineering, China University of Petroleum) | Zhao, Xiaoliang (MOE Key Laboratory of Petroleum Engineering, China University of Petroleum) | Chu, Hongyang (China University of Petroleum) | Shen, Xudong (China University of Petroleum)
Carbon dioxide is commonly injected during secondary or tertiary recovery to enhanced oil recovery. While CO2 can also cause some precipitation damage. Usually scale ions (Ca2+, Mg2+) in water react with CO2 to form solid precipitation that can plug the pores. In this report, CO2 is injected into the high salinity formation water, which makes the problem of inorganic precipitation by reaction with scale ions. A number of static experiments have been conducted about various reservoir pressures and temperatures when the pH and scale ions content changes in a high temperature high pressure Reactor. Thus, the aim of this report is to determine how the presence of inorganic precipitation during CO2 injections and the factors affecting the amount of CO2 with high salinity water generating inorganic precipitation. Results from XPS and SEM images of precipitation are also provided. The results indicate that there are three stages in the reaction between carbon dioxide and high salinity formation water, and the third stage with high temperature or low pressure produced precipitation is the most important. PH less than 7 can still produce precipitation. The larger the PH and the scale of the ion content, the more precipitation; at first with low temperature or high pressure, and then with the high temperature or low pressure produced the largest amount of precipitation.
CO2 flooding technology is an important technology developed in the 1980s, which has been widely paid attention to by all countries in the world . However, compared with oil, gas and other geologic fluids, CO2 is an active gas, and when it was injected into the ground, it is very easy to react with the formation of fouling ions in stratum water to produce precipitation and eventually change the physical and chemical properties of the reservoir . Especially, the change of reservoir permeability will seriously affect the underground storage capacity of CO2 , so it is necessary to study and discuss the CO2 and formation water interaction.
Hao, Hongda (China University of Petroleum) | Hou, Jirui (China University of Petroleum) | Zhao, Fenglan (China University of Petroleum) | Wang, Zhixing (China University of Petroleum) | Fu, Zhongfeng (China University of Petroleum) | Li, Wengfeng (China University of Petroleum) | Wang, Peng (China University of Petroleum) | Zhang, Meng (China University of Petroleum) | Lu, Guoyong (China University of Petroleum) | Zhou, Jian (China University of Petroleum)
As an effective method for resource utilization, CO2 huff-n-puff can be utilized to reduce CO2 emissions and enhance oil recovery in edge-water flock-block reservoir, which was implemented in Jidong Oil Field, China since 2008 with oil production of 6.5×104 bbls by 2015. During operation period, synergetic effect was observed in adjacent wells with water cut drops and oil increments in a horizontal well group. Experimental and numerical simulations were conducted to investigate synergetic mechanisms of CO2 huff-n-puff. 3D physical models with a horizontal well group and edge-water-driving system were established in laboratory to simulate the edge-water fault-block reservoir. The formation mechanisms and influence factors of synergetic CO2 huff-n-puff were studied through laboratory experiments. Base reservoir model was also built to further discuss the synergetic types and injection allocations for CO2 huff-n-puff in horizontal well group.
Synergetic CO2 huff-n-puff is a smart gas cycling strategy for the horizontal well group to balance the formation pressure and replace the interwell oil. Experimental and numerical results showed that after CO2 injected into low tectonic position of the reservoir, synergetic effect could be observed in high position well with water cut drops and oil increments. The mechanisms of synergetic effect can be recognized as formation energy supplement, gas sweeping, gravity segregation and CO2-assisted edge-water driving. The stratigraphic dip and heterogeneity are advantages for the formation of synergetic effect. The synergetic types of CO2 huff-n-puff can be summarized as single-well synergy and multi-well synergy. For single-well synergy, edge-water invasion can be effectively controlled by energy supplement after CO2 injected into relatively low position well. For multi-well synergy, better synergetic effect and remaining oil replacement can be achieved after gas injected through different positions of the well group. The development efficiency of synergetic CO2 huff-n-puff can be enlarged with 700t CO2 injected into low position well + 100t CO2 into high position well, and about 5767.9 bbls oil of the well group could be recovered with the soaking time of 50d.
Cao, Mengjing (China University of Petroleum -Beijing) | Wu, Xiaodong (China University of Petroleum -Beijing) | An, Yongsheng (China University of Petroleum -Beijing) | Zuo, Yi (China University of Petroleum -Beijing) | Wang, Ruihe (China University of Petroleum -Beijing) | Li, Peng (Shengli Oilfield, Sinopec)
Unconventional oil, such as tight oil and shale oil, has become one of the most significant contributors of oil reservoirs and production growth. Due to low porosity and ultra-low permeability, unconventional oil reservoirs require multistage hydraulic fracturing technique to maximize production. However, the primary recovery remains very low to narrow the profit margin heavily. Although CO2 huff-n-puff process holds great potential to increase oil recovery and has a chance to sequester CO2 to reduce environmental footprint, our current knowledge of the performance of this process is very limited.
With numerical simulation, we performed a series of sensitivity work to present the impacts of reservoir properties, fracture properties and operation parameters such as CO2 injection rate, injection time, soaking time, number of cycle of CO2 on enhanced oil recovery in the tight oil formation. What’s more, the method of analysis of variance (ANOVA) was used to evaluate the performance of CO2 huff-n-puff process and beneficial result from CO2 EOR technology. Simulation results showed that bottom hold pressure and injection cycles impose more significant impose on oil recovery increment than injection time, injection rate and production time per cycle. Based on the typical reservoir and fracture properties from tight oil reservoir, the numerical models were established to evaluate the performance of four EOR methods: CO2 huff-n-puff, water huff-n-puff, nanofluids huff-n-puff and water alternating gas (WAG). With the comparison of oil recovery and its increment of four EOR methods and depletion method, it is found that CO2 huff-n-puff method would lead to much more incremental oil recovery than other three methods, which reveals its huge potentials of enhancing oil recovery and improving development profit in unconventional reservoirs. The conclusion of this work has the potential to advance our understanding of the role of CO2 in developing unconventional oil reservoirs, which will benefit both energy economy and environment with CO2 geological sequestration.