High Water Cut Research Articles

Oil Production Optimization by Means of a Combined “Plugging, Profile Control, and Flooding” Treatment: Analysis of Results Obtained Using Computer Tomography and Nuclear Magnetic Resonance

Due to long-term water injection, often oilfields enter the so-called medium and high water cut stage, and it is difficult to achieve good oil recovery and water reduction through standard methods (single profile control and flooding measures). Therefore, in this study, a novel method based on “plugging, profile control, and flooding” being implemented at the same time is proposed. To assess the performances of this approach, physical simulations, computer tomography, and nuclear magnetic resonance are used. The results show that the combination of a gel plugging agent, a polymer microsphere flooding agent, and a high-efficiency oil displacement agent leads to better results in terms of oil recovery with respect to the situation in which these approaches are used separately (the oil recovery is increased by 15.37%). Computer tomography scan results show that with the combined approach, a larger sweep volume and higher oil washing efficiency are obtained. The remaining oil in the cluster form can be recovered in the middle and low permeability layer, increasing the proportion of the columnar and blind end states of the oil. The nuclear magnetic resonance test results show that the combined “plugging, profile control, and flooding” treatment can also be used to control more effectively the dominant channels of the high permeability layer and further expand the recovery degree of the remaining oil in the pores of different sizes in the middle and low permeability layers. However, for the low permeability layer (permeability difference of 20), the benefits in terms of oil recovery are limited.

Review on Resistivity Inversion of Underground Abnormal Bodies

With the development of petroleum in China, most oilfields have entered the stage of high water cut development. Well ground resistivity method as a new type of electric prospecting method, which have influence on the formation of small, measuring low cost advantages, gradually become one of the key technology of remaining oil distribution in the detection of resistivity inversion is through observation of the underground space apparent resistivity data reconstruction of the underground resistivity distribution, can realize the resistivity imaging of the underground space. In order to achieve the morphological characterization and spatial location of the abnormal area of underground resistivity, and then to carry out geological interpretation, the definition and properties of resistivity inversion are summarized, and the bottleneck problems encountered in practical engineering application are re-recognized and analyzed. On this basis, the theoretical method, numerical method and inversion method based on machine learning are introduced to solve the inverse resistivity problem of underground abnormal body. The inversion method based on deep learning is emphatically introduced, and its advantages and disadvantages and applicability are evaluated. It is pointed out that inversion is an ideal tool for data analysis. Then, it is pointed out that the development direction of resistivity inversion of underground abnormal body is to propose an optimized inversion network architecture based on deep learning.

Laboratory experimental study on the binary combination flooding system in low permeability conglomerate reservoir

In view of the poor injection-production effect of low permeability conglomerate complex fault block reservoir in Xinjiang Oilfield in the late development stage of high water cut, the indoor experimental study of binary compound flooding system was carried out. By compounding the petroleum sulfonate and polymer binary system, the viscosity and morphology parameters of the binary compound flooding system were measured. The microscopic pore structure of the core in this block was analyzed by GE Phoenix Nanotom S, and four groups of experimental schemes were designed to study the oil displacement efficiency of the whole diameter core binary compound flooding system. The experimental results showed that the binary system of surfactant and polymer showed additive synergistic effect. The performance of binary compound system is less affected by polymer molecular weight and solution concentration, which meets the viscosity requirement of low permeability conglomerate for binary compound flooding system. The porosity of samples is relatively small and the connectivity between pores is relatively poor. The experimental results of physical model oil displacement efficiency show that the oil recovery can be increased by more than 17% by injecting 0.3PV 1200mg/L polymer + 0.5% (w) surfactant binary compound system.

Application of New Water Flooding Characteristic Curve in the High Water-Cut Stage of an Oilfield

The oil production predicted by means of the conventional water-drive characteristic curve is typically affected by large deviations with respect to the actual value when the so-called high water-cut stage is entered. In order to solve this problem, a new characteristic relationship between the relative permeability ratio and the average water saturation is proposed. By comparing the outcomes of different matching methods, it is verified that it can well reflect the variation characteristics of the relative permeability ratio curve. Combining the new formula with a reservoir engineering method, two new formulas are derived for the water flooding characteristic curve in the high water-cut stage. Their practicability is verified by using the production data of Mawangmiao and Xijiakou blocks. The results show that the error between the predicted cumulative oil production and production data of the two new water drive characteristic curves is less than the error between the B-type water drive characteristic curve and the other two water drive characteristic curves. It is concluded that the two new characteristic curves can be used to estimate more accurately the recoverable reserves, the final recovery and to estimate the effects of water flooding

Deep diversion strategy of the displacement front during oil reservoirs watering

The goal of this research is to develop formulations for blocking highly permeable zones using cheap, traditional reagents and materials, and to determine the dependence of the position of the blocking screen on the degree of watering of the oil formation in order to maximize the efficiency of oil displacement. Using readily available chemical reagents and biosystems, technology for generating a stable foam system with adjustable rheological properties and providing deep alignment of the displacement front has been developed. In the study, the required penetration depth of the proposed foam system to achieve the maximum effect at different water cuttings was determined; moreover, the effect of pressure on the stability of the foam system generated as a result of decomposition of the biosystem was studied, and the significant effect of gas saturation on the rheology of the foam system was confirmed. It was further established that with a high water-cut (more than 90%), isolation was most effective in the production wells. At a 50% water cut, the deep diversion of the injected fluid gave promising results, however, the best results were achieved using isolation near the discharge line immediately after the water breakthrough in the production wells. Keywords: foam system; gas generation; stability; multiplicity; dspersion; rheology; reservoir model; displacement ratio; water cut; penetration depth.

Insight into water-enhanced CO2 extraction in the treatment of oily sludge

Oily sludge produced in the petroleum industry is a hazardous waste without treatment. Oil recovery from the oily sludge can reduce environmental pollution and make recycling resources. Water-enhanced CO2 extraction (WECE) is a novel method which could recycle oil from oily sludge efficiently, which has been proposed by our group. Although the operating conditions of WECE method had been determined by a single factor test with small experimental range in our previous work, which ignored the interaction between the other factors. This is an ideal condition which is uncertain for its actual application. In this work, correlational research for WECE method was further performed by the orthogonal test to obtain comprehensive analysis of various factors. All the experiments are tested in the visible autoclave, from which the macro morphology of treating oily sludge can be observed directly. WECE method is proved to have a better oil recovery than supercritical CO2 and liquid CO2 extraction at low temperature and middle pressure. In the experimental range which is larger than previous study, CO2 pressure and system temperature are confirmed the main controlling factors of WECE which is 3 MPa and 60 ℃. From the variance results of orthogonal test, stirring time has little effect on oil recovery which could have discretionary consideration of reducing time to increase efficiency. Additionally, WECE method can dispose the oily sludge with high watercut directly. It could avoid drying process which is more economic and efficient than the traditional methods. WECE method has a potential application in the petroleum company.

Hybrid analysis for excessive water production problem

The production performance of wells should be studied in order to extend the production plateau period which can lead to an increase in revenue. The pool performance plot of a reservoir is a pictorial representation of the pressure-production history of a reservoir. Water-coning, near wellbore problem and multilayer channeling are the three basic mechanisms associated with high water-cut wells. Identification of the water sources is quite important to perform any remedial operation to extend oil production. This paper is a case study on the application of two methods to determine the accurate mechanism for high water-cut in an oil field ‘A’ of the upper Assam basin. Based on the study of conventional plotting of water-cut vs. time with well card data (History of all the jobs performed on the well) and log-log plots of WOR and WORꞌ vs. time, it was observed that the problems were due to multilayer channeling and coning. These plots show the problems associated with high water cut wells and they serve as an effective tool for the selection of water control treatment processes to enhance treatment. However, a failed treatment job will alter the conditions for the next job whereby the expenditure increases significantly.

Diagnosing High Water Production in Kalama Field, Niger Delta

Produced water is water trapped in underground formations that is brought to the surface along with oil or gas. It is by far the largest volume by-product or waste stream associated with oil and gas production especially in brown fields. Management of produced water present challenges and costs to operations. In this paper, the possible causes, effects and solutions of high water-cut is being investigated in some production oil wells in Niger Delta, using Kalama field as a case study. Diagnostic and performance plots were developed in order to determine the source of water as well as to evaluate the impact of excess water production on oil production and in field economics in general. Results obtained from the diagnostic plots showed the possible sources of water production are channeling behind casing and multi-layered channeling. The recommended remediation is cementation through a workover operation. Also, a concise step to be taken for identifying excess water was also developed in this work to effectively control excess water production in oil producing wells.

Decision-Making Techniques for Water Shutoff Using Random Forests and Its Application in High Water Cut Reservoirs.

The major oil fields are currently in the middle and late stages of waterflooding. The water channels between the wells are serious, and the injected water does little effect. The importance of profile control and water blocking has been identified. In this paper, the decision-making technique for water shutoff is investigated by the fuzzy evaluation method, FEM, which is improved using a random forest, RF, classification model. A machine learning random forest algorithm was developed to identify candidate wells and to predict the well performance for water shutoff operation. A data set consisting of 21 production wells with three-year production history is used, where out of the mentioned well data, 70% of them are implemented for training and the remaining are used for testing the model. After fitting the model, the new weights for the factors are established and decision-making is made. Accordingly, 16 wells out of 21 wells are selected by the FEM where 8 wells out of 21 wells are selected by the new factor weight created by RF for water shutoff. A numerical simulation model is established to plug the selected wells by both methods after which the influence of plugging on water cut, daily oil production, and cumulative oil production is compared. The paper shows that the reservoir had a better performance after eight wells were selected using a new weighting system created by RF instead of the 16 wells that were selected using the FEM model. The paper also states that the new weighting model’s accuracy improved the decision-making abilities of the wells.

Reduced-Order Modeling Framework Enables Dynamic Process Optimization

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202643, “Dynamic Process Optimization Using a Reduced-Order Modeling Framework,” by Ravikishan Guddeti, SPE, IPCOS, and Sathish Sankaran, SPE, Xecta Digital Labs, prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. The role of process operations upstream, midstream, and downstream is critical to fundamental business resilience and production optimization in a dynamic environment. In the complete paper, the authors propose a fast, hybrid, self-learning dynamic process-modeling method derived from routine plant measurements that can be used for short-term forecasts, scenario modeling, and process optimization and control. Introduction The methodology, reduced-order modeling (ROM), can use large quantities of data from plant sensors to create a dynamic process model that can be used to optimize process performance. The authors propose a model structure and a hybrid method that is physically intuitive and interpretable and can learn incrementally in real time and thus can augment human intelligence with fast machine-derived insights. Problem Description In the offshore facility system considered in this work, the oilwell flowlines are connected to the platform through risers that terminate at the facility inlet. Each topside flowline includes a subsea production flowline connected to a pressure-controlled choke. This topsides flowline choke is used to control production rate or manage slugging conditions. The facility is designed to provide separation and processing of the oil and condensate production as required to meet export pipeline specifications. A typical oil-separation train consists of many stages of separation and contains liquid surge volume to accommodate surges in liquid rate that may occur from wells or subsea flowlines. Depending on the space available, these separators are two- or three-phase separators. The liquid from each stage is dumped to the subsequent stage of separation, allowing the three phases (oil, gas, and water) to separate. Gas from each stage of separation is compressed, treated to remove water, and then pumped into the export line. Water removed in the separation trains is routed to treating systems before being dumped back into the sea. The dry oil is stored in the dry oil tank and pumped out to the pipelines. Each well has different characteristics that change with the age of the well. As the wells mature with reduced reservoir pressures and increased gas/oil ratio, the hydrocarbon phases travel at lower velocity, resulting in unstable flow regimes. When wells producing at high water cuts are brought online, combined with low gas flow rates and low wellhead pressure, the potential for slug flow can disrupt steady operation of the separation train. The frequency of these events increases with aging reservoirs and high-water-cut production. An effective real-time tool is needed that can monitor current operating conditions continuously and is able to run through alternative mitigation strategies quickly using the predictive model to analyze the effect on downstream processes.

Delaware Basin Case History Details Economic Benefit of Water-Recycling Program

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 204166, “Turning Produced Water Into an Asset: A Delaware Basin Case History,” by Dustin Aro, SPE, and Steven Fowler, SPE, Precision Petroleum Solutions, prepared for the 2021 SPE Hydraulic Fracturing Technology Conference and Exhibition, held virtually 4–6 May. The paper has not been peer reviewed. Well completion operations are affected by freshwater procurement costs starting at approximately $0.75/bbl. Regardless of final fracturing design, water consumption during fracturing operations typically exceeds 500,000 bbl, or $375,000 per well at the time of writing. Significant value exists for recycling produced water by an on-lease pit that can be used for future fracturing operations. The case history outlined in the complete paper explores a multiwell sectional development in the Delaware Basin by a small operator that reduced drilling and completion costs, along with lease operating expenses, by turning undesirable produced water into an asset. Regulatory Considerations Because the Delaware Basin straddles two states, it is important to understand the guidelines and processes of pursuing produced-water recycling operations in Texas as opposed to New Mexico. The operations discussed were executed and managed on the Texas side. While contractor familiarity can be beneficial during the planning stages, the operator also must be well-versed in applicable regulations. It is advisable to consult with legal counsel regarding liability should an unplanned discharge event occur. Lease Development History Before the beginning of initial completions operations, three freshwater wells were drilled on-lease with the intention of use for fracturing operations. The flow rate from the three wells was insufficient to keep up with fracturing operations by an aboveground storage tank (AST). A large-volume fracturing pit was not constructed. The initial completion on Well 1, targeting the Wolfcamp C bench, was executed primarily with fresh water sourced from a third-party pit that was transferred to a nearby AST. During production, Well 1 maintained a high water cut (greater than 90%) and produced a significant amount of water over time. Additional infrastructure would be required to fully exploit the existing freshwater wells as a source for future completions activity. Operator break-even treatment costs have been determined to be the most favorable when using a centralized pipeline water-management program. A pit would act as a centralized gathering point with temporary pipeline infrastructure for water-transfer purposes. An internal economic analysis was undertaken to determine construction costs for a pit that could accommodate 500,000 bbl or 1,000,000 bbl of fresh water. The option of constructing a pit that could handle produced water also was included for comparison.

Optimizing Water Injection Performance by Using Sector Modeling of the Mishrif Formation in West Qurna-1 Oil Field, Southern Iraq

The regular job of a reservoir engineer is to put a development plan to increase hydrocarbon production as possible and within economic and technical considerations. The development strategy for the giant reservoir is a complex and challenging task through the decision-making analysis process. Due to the limited surface water treatment facility, the reservoir management team focuses on minimizing water cut as low as possible by check the flow of formation and injected water movement through the Mishrif reservoir. In this research, a representative sector was used to make the review of water injection configuration, which is considered an efficient tool to make study in a particular area of the entire field when compared with the full-field model on the basis of time-consuming and computational analysis. The sector model was neighboring by extra grid blocks and three pseudo wells as injector wells to realize the pressure on the sector boundary, which attained an acceptable history matching. The fluid model and physics model were introduced by using Pressure Volume Temperature data of well involved in the study area and two relative permeability curves. Fourteen wells were utilized in this work, four wells are injectors, and the rest are producer. The development scenarios were implemented by setting various targets of oil production and different water injection rates required for pressure maintenance operations. Optimization of water cut has been applied by adjustment of production and injection rates and shut off the high water cut intervals. The results obtained from this study showed that the inverted 9-spot has a good recovery which is illustrated in the case_2C, the production rate was (49,000 STB/D) with minimum water cut (27.5%) as compared with a five-spot pattern.

Estimation of existing production capacity during operation in conditions of high watercut

The paper studies the estimation of existing production capacity of the wells operated via oil well pumps in conditions of high watercut. Production parameters are of great importance during the increase of production and efficiency of using well stock, particularly, in the last stages of field development. In this view, based on the actual field data, the values of oil and water rates of the wells operated from one object have been analyzed, as well as the distribution of rates by actual watercut diapason developed. The change rate of oil and water output depending on the watercut have been calculated based on mathematical models. The research results allow specifying the limit values of watercut, as well as contribute to trustworthy prediction of oil flow rate of the wells and development by the groups and whole well stock of producing wells.

Prediction of oil rates using Machine Learning for high gas oil ratio and water cut reservoirs

Allocated well oil rates are essential well performance evaluation. Flow meters are not reliable at high gas-oil ratio (GOR) and high water-cut (WC). Most of the available formulas are based on Gilbert-type formulas with neglecting the differential pressure across the choke. Adaptive network-based fuzzy inference system (ANFIS), and functional networks (FN) were used to generate different models to predict the production rates for high GOR and WC wells. A set of data (550 wells) was obtained from oil fields in the Middle East. GOR varied from 1,000 to 9,351 scf/stb, WC ranged from 1 to 60%. Around 300 wells were flowing under critical flow conditions, while the rest were subcritical. The developed AI models were compared against the previous published formulas. For each AI method, two models were developed for subcritical flow and critical flow conditions. The average absolute percent error (AAPE) in the subcritical flow for ANFIS and FN were 1.25, and 0.95%, respectively. While in the critical flow, the AAPE values were 1.1, and 1.35% for ANFIS and FN models, respectively. All developed AI models outperform the published formulas by 34%. The findings from this study will significantly assist production engineers to predict the oil rate in real-time without adding any cost or field intervention.

Technological feature of water shutoff operations

At present, the use of a water flooding pattern in the development of oilfields at the late stage causes the premature water influx. Therefore, in recent years, the problem of eliminating water influx has become urgent. The productive horizons of the studied deposits are merged into a single object and exhibit a sharp heterogeneity in combination with a dense well pattern. This leads to the natural water influx and, as a result, to high water cut oil reserves. In conditions of a high level of water cut, a significant number of wells are idle and require geological and technological measures for recommencing, demulsification of the produced oil and disposal of the produced water. Therefore, oil companies suffer significant losses. The aim behind this paper is to analyze and evaluate the existing water shutoff techniques for the Vereisk and Bashkir carbonate sediments in the field studied.

Using cyclic alternating water injection to enhance oil recovery for carbonate reservoirs developed by linear horizontal well pattern

In view of high water cut and low oil recovery caused by the unidirectional flow in linear pattern of horizontal wells for the carbonate reservoirs in the Middle East, this paper provides a novel approach to improve oil recovery by converting linear water injection to cyclic alternating water injection patterns including cyclic alternating water injection with apparent inverted seven-spot pattern or apparent five-spot pattern and cyclic differential alternating water injection. The main advantage of using this strategy is that the swept efficiency is improved by changing injection-production streamlines and displacement directions, which means displacement from two different direction for the same region during a complete cycle. This technology is effective in increasing the swept efficiency and tapping the remaining oil, thus resulting in higher oil recovery. Field application with three new patterns in a carbonate reservoir in the Middle East is successful. By optimizing injection and production parameters based on the cyclic alternating well pattern, the test well group had a maximum increase of daily oil production per well of 23.84 m 3 and maximum water cut drop of 18%. By further optimizing the distance (keep a long distance) between the heels of injection and production wells, the waterflooding performance could be better with water cut decreasing and oil production increasing.

Determination of boundary temperature and intelligent control scheme for heavy oil field gathering and transportation system

Heavy oil gathering and transportation system is increasingly attention and the realization of intelligent control has become the oilfield development direction and trend in the future. In this paper, boundary temperature is defined as safe inlet temperature and optimal oil transportation temperature. The intelligent supervisory control and data acquisition system was used to collect the production data of an oilfield in Western China in real-time. The heavy oil transportation pipeline was divided into 9 types through big data analysis. The safe inlet temperature under different conditions was determined by flow loop experiments. Then the total heat transfer coefficient was corrected by the least square method, and the optimal oil transportation temperature was calculated by the mathematical model. The results indicated that the relationship of the temperature drop along the pipeline could be more accurately predicted by the modified total heat transfer coefficient. Heavy oil field gathering and transportation system had low-temperature transportation potential in summer and winter. Liquid production, water cut, and the ambient temperature had a significant effect on the temperature gradient and safe inlet temperature. The heavy oil with high liquid production and high water cut had the greatest potential for low-temperature transportation. An oilfield intelligent control and management scheme is proposed to effectively guide heavy oil production. This study is of great significance to guide the optimization of operation parameters of heavy oil field gathering and transportation system, realize energy saving and consumption reduction, and ensure the efficient and stable operation of the pipeline.

Application of an Accurate and Efficient Modeling Approach to a Multiscale Fractured Reservoir in South China Sea

Carbonate reservoirs in the South China Sea mostly contain natural fractures with various length scales and different intensities, which causes great challenges in efficient reservoir modeling and flow simulation. Existing efforts based on dual-porosity and dual-permeability models could not reflect the characteristics of production data in certain wells. To accurately and efficiently characterize multiscale fractures, a hybrid fracture characterization method is proposed. Firstly, fractures are divided into two types according to the geometrical size and interpretation approach. Then, small-scale fractures, characterized mainly by image log interpretations, are modeled by the traditional dual-porosity/dual-permeability (DP) method. And large-scale fractures, which are characterized by seismic interpretations and dominate the flow regime, are modeled by the embedded discrete fracture method (EDFM) to achieve both accuracy and efficiency. Lastly, transmissibilities among these three types of grid mediums are calculated to generate the hybrid DP+EDFM model for flow simulation. The proposed approach is applied to a carbonate, fractured reservoir in the South China Sea. The overall procedure is fast and reliable, and water cut matches of both field and specific wells are dramatically improved. Comparing the simulation results with the conventional DP model, the proposed approach yields much more accurate predictions on rapid water breakthrough and high water cut in fractured reservoirs.

Combination of alkali–surfactant–polymer​ flooding and horizontal wells to maximize the oil recovery for high water cut oil reservoir

Alkali/surfactant/polymer (ASP) combines the advantages of each of the chemical in the blend. ASP has shown to be an effective and practical method to enhance oil recovery. Compared with vertical wells, fluid flooding by using horizontal wells is believed to be infeasible due to easier fluid breakthrough and subsequent low sweeping efficiency. However, good responses observed in field applications (Daqing oil field, China) show the promising future of ASP flooding using horizontal wells. In this study, a combination of laboratory-scale core displacement experiments and reservoir-scale numerical simulations was used to study the performances of ASP flooding by using horizontal injection/production wells and vertical injection/production wells to reveal the mechanisms responsible for the favorable responses observed in the field. Firstly, displacement experiments in evaluation of ASP flooding using vertical wells and horizontal wells were conducted. The effects of well type on ASP flooding performances were further evaluated by numerical simulation based on a realistic reservoir. The results show that, horizontal well injection/production pattern facilitates a better oil displacement performance due to the higher sweeping volume. This is because horizontal injection/production pattern weakens both the effects of surface heterogeneity and vertical inter-layer heterogeneity during ASP flooding performance. Although horizontal injection/production well pattern is not suitable for water flooding due to the higher chances for water breakthrough, the profile-control characteristic of ASP system blocks the high permeable channels to some extent, providing a better performance in combination with horizontal injection/production well pattern. This work systematically studied the effects of well type on ASP flooding performance at core scale and reservoir scale, and it provides theoretical and practical implications for the application of ASP flooding in enhancing oil recovery for high water cut reservoirs.

Experimental characterization of hydrate formation in non-emulsifying systems upon shut-in and restart conditions

In offshore oil production, scheduled or emergency shutdowns of the production system may occur due to maintenance, equipment failure, production issues, and weather-related events. During the shut-in, the fluids may enter into the hydrate zone because of the thermal energy transfer to the cold ocean waters, increasing the risk of hydrate formation during the shut-in period and upon the restart of the production system. This work is focused on identifying some parameters that influence the hydrate formation in shut-in and restart conditions. Using a rock-flow cell with visual capabilities, the hydrate formation and the phenomena involved upon the restart were investigated. The main results of the experiments showed that the high shear conditions applied at the restart promoted water dispersion into the oil phase and contributed to the dispersion of hydrates. In addition, the low shear rate favored the formation of hydrate deposits while hydrate agglomerate was formed at high shear rate. Besides the shear rate, the subcooling proved to be an important parameter that favors the hydrate formation under sheared conditions. Conditions with high subcooling and low water cut promoted the formation of small hydrate particles (~2 mm) that can be dispersed in the oil-phase even without the anti-agglomerant. A high subcooling promoted the formation of “dry” hydrates, preventing the particles to stick with each other (agglomerates). The results indicated that subcooling is an important parameter to ensure a safe restart in the pipeline. Lastly, the addition of an anti-agglomerant reduced the water–oil interfacial tension, which promoted the water/hydrate dispersion; the effectiveness of the anti-agglomerant was clearly affected by the shear and the water cut.