Reduce Water Cut Research Articles

A Proposed Method for Simulation of Rate-Controlled Production Valves for Reduced Water Cut

SummaryIn recent years, the advancement of horizontal-well technology has played a major role in making oil production economically feasible from many reservoirs. One of the major problems that can reduce the efficiency of using horizontal wells is gas and water coning caused by the heel-toe effect and heterogeneity along the well. To tackle this problem, Equinor’s autonomous inflow-control device (ICD) (AICD), known as rate-controlled production (RCP) valves, is widely used today. RCP valves can effectively delay the early water breakthrough and partially choke back water autonomously after water breakthrough. To fulfill a suitable design of a long horizontal well with the RCP completion, a detailed understanding of multiphase-flow behavior from the reservoir pore to the wellbore and production tubing is needed. Coupling a dynamic multiphase-flow simulator such as the OLGASM (Schlumberger Limited, Sugar Land, Texas, USA) simulator with the near-wellbore reservoir module such as the OLGA ROCX module provides a robust tool for achieving this purpose. However, there is no predefined option in the OLGA simulator for implementing the autonomous behavior of the RCP valves directly. Therefore, creating a model of oil production by considering well completion with the RCP valves in the OLGA simulator is challenging. In the previous works, this has been performed by using the Proportional Integral Derivative (PID) Controller option in the OLGA simulator, which controls the opening of an equivalent orifice valve according to the fixed value of the water cut. However, because of the performance of the PID Controller using a fixed setpoint and the difficulties in properly tuning the PID Controller, choosing this option leads to a large degree of inaccuracy in the simulation models. In this paper, by proposing a novel method with a developed mathematical model and a control function for the RCP valves, the autonomous behavior of these valves is implemented in the OLGA simulator. In this new approach, the control signals are calculated using the variation of water cut and introduced to the OLGA simulator through the Table Controller option instead of the PID Controller. The presented approach in this paper can be used for the simulation of water-cut (or gas/oil-ratio) reduction potential of all RCP-type AICDs in reservoirs with different characteristics. However, to explain the procedure of this approach in detail, the near-well oil production from Well 16/2-D-12 in the Johan Sverdrup Field (JSF) considering RCP completion is modeled as a case study. In this study, the simulation model is developed using one of the commonly used types of RCP valves called the TR7 RCP valve. Version 2016.1.1 of the OLGA simulator/ROCX module is used (Schlumberger 2016). According to the simulation results, compared with using ICDs, by the completion of Well 16/2-D-12 with RCPs, the water cut, water-flow rate, and accumulated water production can be reduced by 2.9, 13.3, and 12.1%, respectively, after 750 days. The results also showed that by using the proposed approach, the autonomous behavior of the RCP valves according to the water-cut variations can be appropriately implemented in the OLGA simulator. This can help engineers and researchers to achieve a better design of a long horizontal well using the RCP completion. Consequently, using this approach can be beneficial for improving technology, optimizing production, minimizing risk, and reducing costs in oil recovery.

Factors affecting gel strength design for conformance control: An integrated investigation

In petroleum industry, excessive water production represents a major industry challenge because of its serious economic and environmental impacts. Conformance control gel treatments have been proven to be effective in mitigating this problem and in reactivating oil production in brown fields. Understanding the most important factors that control the performance of gel treatment represents a priority for the optimization process and should be considered during the design of gel treatments. In this study, different scenarios of reservoir simulation models were developed and validated with field data to investigate the most important factors controlling the success and failure of gel treatments. Numerical simulation methods were used to determine how the optimum water residual resistance factor (Frrw) of gels should be changed with different reservoir conditions to achieve the highest oil recovery. Furthermore, the impact of crossflow on gel design was deeply investigated and correlated with the oil recovery improvement and water cut reduction by calling up some of the petroleum engineering basics. Moreover, the relationship between the gel penetration depth and permeability contract has been determined. The results of this research developed a new equation which correlates the optimum Frrw, that should be achieved by gels, with the reservoir candidate properties. However, Design of Experiments (DOE) proved that there are two main parameters which have the dominant role to decide the optimum Frrw. New cut-off values for crossflow and permeability contrast have been determined from this study to provide guidelines on gel treatments selection criteria. This research presents new findings to optimize gel design according to the reservoir conditions. The findings of this study are built on an integrated combination of field data, reservoir simulation, and reservoir engineering basics. • The results of this research developed a new equation correlating the optimum Frrw with reservoir properties. • The optimum value of Frrw is only function of two main parameters which are the permeability contrast and the oil viscosity. • If the crossflow ≥0.1 and the permeability contrast ≤10, there is no benefit from gel treatment regardless of the Frrw used. • There is no effect for the timing of gel treatment on its performance if the high-K streak was already watered out completely. • This study found that as far as the oil viscosity increased the optimum value of Frrw should be increased for better results.

Countermeasures to Decrease Water Cut and Increase Oil Recovery from High Water Cut, Narrow-Channel Reservoirs in Bohai Sea

Most multilayer sandstone reservoirs in the Bohai Sea have already entered the middle or high water cut production stage with large amounts of remaining oil being scattered distributed. Therefore, there is an urgent need to find a suitable countermeasure to reduce water cut and increase oil recovery. In this study, taking the narrow-channel reservoirs in the M oilfield as an example, we qualitatively described the sand body scale and the contact relationships between different sand bodies, in addition to carefully analyzing the material base and remaining oil distribution characteristics. Accordingly, we proposed a countermeasure based on the injection-production structural adjustment to reduce water cut and increase oil recovery from high water cut, narrow-channel reservoirs. Herein, three optimization strategies were developed based on the proposed development mode: a seepage field optimization strategy was developed based on the quantified injection-production index; a well pattern optimization strategy for narrow-channel reservoirs was developed to overcome the production energy refueling problem; an injection-production measure optimization strategy was developed to tap the different types of remaining oil. Additionally, the well pattern optimization and injection-production optimization strategies were integrated to optimize and adjust the seepage field system. The findings reported herein this paper help understand the development of similar offshore oilfields with a high water cut.

Experimental investigations to evaluate surfactant role on absorption capacity of nanofluid for CO2 utilization in sustainable crude mobilization

Carbon dioxide (CO2) utilization for oilfield applications is affected by viscous fingering which leads to premature breakthrough without showing any appreciable impact on oil recovery and storage. Therefore, to control these issues, CO2 is often injected with high viscous fluid i.e. nanofluid. However, nanofluid efficacy can be further improved by inclusion of a surfactant that not only increases specific area of CO2 [via interfacial tension (IFT) reduction] but also increases CO2 absorption capacity of nanofluid through formation of foam. Thus, in this study, a new colloidal solution of anionic surfactant (i.e. sodium dodecyl sulfate, SDS, 0.16–0.24 wt%) and polymer based single-step silica nanofluid of varying concentration (0.1–1.0 wt%) was proposed for subsurface carbon utilization in CO2 absorption, IFT reduction, and fossil fuel displacement. CO2 absorption experiments showed that absorption was positively influenced by pressure and NP concentration, while increasing temperature showed reverse impact on CO2 absorption. In addition, SDS ensured formation of a Pickering foam which made CO2 to retain inside for over 10 days (an increase of 67%) in SDS treated nanofluid, higher than 6 days of simple nanofluid. Pickering CO2 foam of SDS treated nanofluids was also envisaged for IFT reduction of crude oil, to identify role of these nanofluids in crude mobilization from porous reservoir. CO2 absorption capacity of nanofluid exhibited inverse relationship with IFT value of crude oil. Finally, displacement experiments were conducted which also support inclusion of SDS in silica nanofluid for reduced water cut and higher fossil fuel recovery from porous media. Initially, the oil recovery was only 42% with water and 52% with 1 wt% NP concentration. However, the highest oil recovery was 61% when 1 wt% NP/0.16 wt% SDS combination was used.

Study on Development Characteristics of Low Permeability Oil-water Horizontal Well Area in the Same Layer

According to the development practice of horizontal wells in Putaohua reservoir of low permeability oil-water block, this paper summarizes the development characteristics of the block. At the initial stage of production, the chloride ion value of the near-wellbore formation (i.e., the fluid produced at the initial stage of production) is corrected for the large-scale fractured horizontal wells according to the fracturing fluid that is not returned, so as to judge the water breakthrough property of high water-bearing wells. After putting into production, it is found that the formation water in the block is affected by structure and lithology respectively. The water injection policies of “strengthening water injection at high position and restraining water injection at low position” and “strengthening water injection at main layer and restraining water injection at communication layer” are adopted to restrain formation water energy from plane and interlayer and reduce water cut in horizontal wells. Based on the theoretical analysis of fracture effect and water breakthrough characteristics of horizontal wells, the theoretical water breakthrough strength and theoretical hydraulic conductivity strength of fractures are calculated respectively, and the chart is drawn. According to the chart, the adjustment idea of “classification cycle water injection, zonal determination of parameters” is implemented, so that the determination of cycle water injection parameters is changed from “fixed strength, fixed cycle water quantity” to “fixed water quantity, fixed cycle water strength”, and further improved The improvement of water injection policy can provide reference for the development characteristics research and water injection adjustment of horizontal wells in the same type of oilfield in the future.

Increasing the efficiency of water shut-off in oil wells using sodium silicate

Purpose. Substantiation of technology for creation of a water-blocking zone below an oil reservoir and calculation of the proper composition of a gel-forming compound based on sodium silicate, in order to reduce water cut in production wells. Methodology. The goal of the work was achieved by conducting theoretical and experimental studies on technological processes of water blocking in an oil reservoir, and by identifying patterns of gel formation of sodium silicate and hydration of a micro-cement solution in reservoir conditions on full-scale models. The gel compound included sodium silicate (Na2SiO3, also referred to as liquid glass) and an aluminum salt cross-linker (AS-1). The plugging material mixture of Portland micro-cement and sodium silicate contained calcium oxide, to allow expansion, and a GL-1 reaction inhibitor. The criteria for assessing the creation of a reliable water-blocking zone in an oil reservoir are: the mobility of the aqueous solution of the gel-forming compound during its movement from the wellhead to the bottom of the well, the low permeability of the zone following its creation, and the sufficient strength of the non-shrink micro-cement in the annulus of the well. Findings. A new technology is suggested used to create a water isolation zone is a gel-forming compound based on sodium silicate, which provides a significant reduction of water cut in oil production. It is found that perforation of production string below the oil reservoir at the level of the water-saturated zone followed by injection into a well through perforated channels, the mixture of fresh water and the gel-forming compound prevents water inflow to the bottom of the well. Experiments established that with a gelation time of 2 hours at a temperature of 80 C, the viscosity of the gel is in the range of 1.22.9 Pas, and the density is 10801109 kg/m3. These values for the viscosity of the gel allow transportation from the top of the well to the bottom with the least resistance to motion. Following gelation time, the viscosity increases significantly, and after 3 days the gel viscosity reaches a range of 3.46.7 Pas. The values indicated for the viscosity of the gel are much greater than those of oil. Therefore, the proposed gel-forming compound provides a reliable water shut-off zone at the bottom of an oil reservoir, and prevents the influx of water at the bottom of a well. Originality. The proposed sodium silicate compound allows for the creation of a reliable water shut-off zone and an enhanced grouting material, based on the combination of sodium silicate and micro-cement, which together provide a significant reduction in water cut in wells during oil production. Practical value. A method for studying technological processes of oil reservoir water-blocking has been devised and the rational composition of gel-forming compound and micro-cement grout slurry with an expanding additive and a reaction retarder in reservoir conditions on full-scale models has been established. The application of the research results in oil fields allows reduction of water cut in production wells to 010%, against existing values of 7090%, and an increase in flow rate in producing wells by 2030%.

СРАВНИТЕЛЬНАЯ ОЦЕНКА ФИЗИОЛОГО-БИОХИМИЧЕСКИХ ПАРАМЕТРОВ НЕКОТОРЫХ ВИДОВ И СОРТОВ FICUS В УСЛОВИЯХ ЛЕТНЕГО ДЕФИЦИТА ВЛАГИ НА ЮЖНОМ БЕРЕГУ КРЫМА

The physiological and biochemical parameters of 6 genotypes of genus Ficus species leaves, associated with drought tolerance during the periods of the summer drought on the Southern coast of Crimea were determined. The specific features of the water regime of the species F. carica, F. palmata, F. virgata under the influence of drought factors were revealed. The species F. virgata turned out to be the most sensitive to insufficient water supply. Weak ability to retain moisture and insufficient turgidity was observed in the leaves of the varieties Krymskiy Cherniy and Opylitel Nikitskiy. Leaves of the species F. palmata are characterized by reduced water cut, good water-holding ability and restore tissue turgor at a high level. Protective and adaptive reactions to water stress of the leaves of the Sabrutsiya Rozovaya and Sary Stambulskiy varieties are manifested in the economical use of moisture and protects tissues from excessive dehydration, which ensures a sufficient level of repair for normal physiological processes. It was established that at different periods of the summer season, the biochemical parameters of the studied genotypes at different stages of the experiment varied differently. At the beginning of the summer period, in most of the studied genotypes, the content of proline decreased under full leaves watering, with the restoration of turgidity, it increased, and at the end of the summer, the opposite changes occurred. The activity of peroxidase during restoration of tissue turgor at the beginning of the summer period increased and decreased to a minimum at the end of summer. Catalase activity at the beginning of the summer period decreased with watering the leaves and increased with wilting but at the end of the summer demonstrated no changes with watering and wilting of the leaves and varied in different directions when the turgor was restored. The activity of polyphenol oxidase at the beginning of the summer period at the stage of complete watering and restoration of turgor increased in most genotypes, changed in different directions when wilting, and in late summer it decreased during watering and restoration of turgor and increased after wilting. Despite the amplification of the drought factors, at the end of the summer period the leaves of the studied genotypes preserved the possibility to carry out normal metabolic processes to a greater extent. It was revealed that the proline content, the activity of peroxidase and polyphenol oxidase contribute significantly to the adaptation to drought of the studied genus Ficus species. Analysis of the obtained data allows suggesting that the varieties Sabrutsiya Rozovaya, Sary Stambulskiy and the species F. palmata, which have good water-holding abilities, a high degree of repair after critical dehydration and the ability of the antioxidant system to quickly respond to extreme conditions display the highest adaptive ability to the hydrothermal stress effects, which indicates their relative drought tolerance.

Enhancing Heavy-Oil-Recovery Efficiency by Combining Low-Salinity-Water and Polymer Flooding

SummaryCombining low-salinity-water (LSW) and polymer flooding was proposed to unlock the tremendous heavy-oil resources on the Alaska North Slope (ANS). The synergy of LSW and polymer flooding was demonstrated through coreflooding experiments at various conditions. The results indicate that the high-salinity polymer (HSP) (salinity = 27,500 ppm) requires nearly two-thirds more polymer than the low-salinity polymer (LSP) (salinity = 2,500 ppm) to achieve the target viscosity at the condition of this study. Additional oil was recovered from LSW flooding after extensive high-salinity-water (HSW) flooding [3 to 9% of original oil in place (OOIP)]. LSW flooding performed in secondary mode achieved higher recovery than that in tertiary mode. Also, the occurrence of water breakthrough can be delayed in the LSW flooding compared with the HSW flooding. Strikingly, after extensive LSW flooding and HSP flooding, incremental oil recovery (approximately 8% of OOIP) was still achieved by LSP flooding with the same viscosity as the HSP. The pH increase of the effluent during LSW/LSP flooding was significantly greater than that during HSW/HSP flooding, indicating the presence of the low-salinity effect (LSE). The residual-oil-saturation (Sor) reduction induced by the LSE in the area unswept during the LSW flooding (mainly smaller pores) would contribute to the increased oil recovery. LSP flooding performed directly after waterflooding recovered more incremental oil (approximately 10% of OOIP) compared with HSP flooding performed in the same scheme. Apart from the improved sweep efficiency by polymer, the low-salinity-induced Sor reduction also would contribute to the increased oil recovery by the LSP. A nearly 2-year pilot test in the Milne Point Field on the ANS has shown impressive success of the proposed hybrid enhanced-oil-recovery (EOR) process: water-cut reduction (70 to less than 15%), increasing oil rate, and no polymer breakthrough so far. This work has demonstrated the remarkable economical and technical benefits of combining LSW and polymer flooding in enhancing heavy-oil recovery.

АНАЛИЗ МИРОВОГО ОПЫТА ПРИМЕНЕНИЯ ТЕХНОЛОГИЙ ВЫРАВНИВАНИЯ ПРОФИЛЕЙ ПРИЕМИСТОСТИ НА ОСНОВЕ СШИТЫХ ПОЛИМЕРНЫХ ГЕЛЕЙ

Due to a growing number of wells being in late stages of operation, there is an increasing demand for introduction of new integrated solutions reducing wellbore fluid watercut. Eventually, watercut reduction enables a prolonged operation of encroached wells and improves recovery of residual oil reserves. Polyacrylamide is the most available and industrially applicable reagent stabilizing formation water intake profiles. Based on the review of international and native experience, the study analyses the effectiveness of a variety of methods using polyacrylamide to reduce the wellbore fluid watercut. The paper discusses such injection technologies as conventional polymer water flooding, in situ gels, colloidal dispersion gels, and precrosslinked gels. Cross-linked polymer gels are three-dimensional structures where polymer chains are cross-linked by either ionic or covalent polar bonds. Depending on particle sizes, they are divided into macrogels (100 μm to several cm) and microgels (0.1 to 30 μm). Compared to in situ compounds, the use of macro- and microgels substantially reduces the risk of polymer chain destruction by mechanical, chemical or thermal factors. Based on the analysis, recommendations were developed for application of various polymer injection methods taking into account the geological and technological conditions of the production site development. It is recommended to use macrogels to reduce the wellbore fluid watercut in fields with the reservoir permeability above 500 mD; while it is advisable to use microgels with the reservoir permeability from 100 to 500 mD; and colloidal dispersion gels can be used with the reservoir permeability from 10 to 100 mD. In order to improve the development effectiveness, advanced technologies need to be adapted in due time to the geological and process conditions. Also pilot production operations need to be conducted in the native fields.

Comparative numerical study for polymer alternating gas (PAG) flooding in high permeability condition

Polymers have been used in water alternative gas, to viscosify the water and improve the overall sweep efficiency. The use of polymer alternative gas was successful in increasing the oil production in high permeability zones. However, few practical factors affecting the field applicability have been overlooked. Therefore, this study is aimed at bridging the gap between the possibility of using several EOR such as water flooding, CO2 flooding, water alternative gas, polymer flooding and polymer alternative gas. The research based on progressive comparison considering constant constraint. The numerical simulation STARS-CMG was used to predict the characteristics and behaviour of the fluid in the reservoir. The designed flooding pattern chosen was a single producer-single injection (P-I) scheme in homogeneous high permeable reservoir. The results of oil incremental recovery showed the following order compared to Water flooding < (3%) CO2 flooding < (6.8%) < Water alternative gas (11.6%) Polymer flooding < (15%) Polymer alternative gas. The impact of polymer on enhancing the water alternative gas was mostly noticeable in the reduction of water cut% (83%). The controlled conformance by polymer aided in improving the sweep efficiency as indicated by the uninform U-shape. Moreover, the delayed gas breakthrough was significant and resulted in the lowest gas oil ratio of 5.17E + 04 ft3/bbl. The low gas oil ratio observation is indication of potential capturing of CO2 in the reservoir and thus, good evidence to further implementation of CO2 as green utilization.

Experimental investigation on plugging and transport characteristics of Pore-Scale microspheres in heterogeneous porous media for enhanced oil recovery

To reduce water cut and improve sweep efficiency of water flooding, a novel pore-scale microsphere (NMPS) as profile control agent was firstly prepared through inverse emulsion polymerization technology. Then, its physical properties were investigated, including morphology, particle size distribution, elasticity, swelling property and long-term stability. Subsequently, the plugging and transport characteristics of NMPS were studied through dual parallel core displacement experiments. And then, oil displacement efficiency was evaluated through dual parallel core displacement experiments and nuclear magnetic resonance (NMR) experiment. Experimental results demonstrated NMPS possessed favorable elasticity, water swelling property, dispersibility and long-term stability with an initial average particle size of 7.58 μm. Also, NMPS could effectively plug high permeability channel and regulate heterogeneity. Moreover, NMPS effectively diverted subsequent injected water into low permeability zone and improve sweep efficiency. As a result, 10.83–31.6% of crude oil was produced during NMPS flooding and subsequent water flooding. It was believed that NMPS was a promising candidate for heterogeneity reduction and oil recovery enhancement.

Recent Advance of Microbial Enhanced Oil Recovery (MEOR) in China

Compared with other enhanced oil recovery (EOR) techniques like gas flooding, chemical flooding, and thermal production, the prominent advantages of microbial enhanced oil recovery (MEOR) include environment-friendliness and lowest cost. Recent progress of MEOR in laboratory studies and microbial flooding recovery (MFR) field tests in China are reviewed. High biotechnology is being used to investigate MFR mechanisms on the molecular level. Emulsification and wettability alternation due to microbial effects are the main interests at present. Application of a high-resolution mass spectrum (HRMS) on MEOR mechanism has revealed the change of polar compound structures before and after oil degradation by the microbial on the molecular level. MEOR could be divided into indigenous microorganism and exogenous microorganism flooding. The key of exogenous microorganism flooding was to develop effective production strains, and difficulty lies in the compatibility of the microorganism, performance degradation, and high cost. Indigenous microorganism flooding has good adaptation but no follow-up process on production strain development; thus, it represents the main development direction of MEOR in China. More than 4600 wells have been conducted for MEOR field tests in China, and about 500 wells are involved in MFR. 47 MFR field tests have been carried out in China, and 12 field tests are conducted in Daqing Oilfield. MFR field test’s incremental oil recovery is as high as 4.95% OOIP, with a typical slug size less than 0.1 PV. The input-output ratio can be 1 : 6. All field tests have shown positive results in oil production increase and water cut reduction. MEOR screening criteria for reservoirs in China need to be improved. Reservoir fluid, temperature, and salinity were the most important three parameters. Microbial flooding technology is mature in reservoirs with temperature lower than 80°C, salinity less than 100,000 ppm, and permeability above 5 mD. MFR in China is very close to commercial application, while MFR as quaternary recovery like those in post-polymer flooding reservoirs needs further study.

Modeling of Chemical Water Shut off Treatments

Water production is one of the major problems that been encountered in the oil industry, which may cause corrosion of tubular, fine migration and acceleration of well abandonment. More than $40 billion is spent yearly dealing with unwanted water, so a treatment should be implemented to reduce high water production. Many papers investigated and focused their researches on how to reduce water cut percentage. Mechanical and chemical treatments are suggested, chemical treatment represented in polymer-gel with cross linker solution proved optimistic results. Gel can solve many types of water production problems rather than other chemical or other mechanical treatments. In this paper a model was constructed to determine the applicability of gels in reducing water permeability. The model included equations predicted using statistical software (SPSS) that determines the water residual resistance factor (Frrw) and the oil residual resistance factor (Frro) by inserting polymer concentration then determine the optimum concentration which gives the most desired results. A real field data was obtained from Z field (well X, well Y, and Well Z) and gel applicability in permeability reduction had been tested, then an optimistic result obtained. The outcomes of this study investigate that there is a great chance to apply polymer-gel as water shut-off technique. For future work a full core-flooding study must be constructed to obtain more set of data and improvement of the equations accuracy

Influence of salinity on the properties of the different HPAM/Al3+systems

In order to achieve oil increment and water cut reduction in the heterogeneous oil reservoirs, a conformance control technology by using HPAM/Al3+systems has been widely used due to the low price and environmental friendliness. However, the complex structure and state of high-valent metal ions in brine water can directly affect the properties of the different HPAM/Al3+systems, which may lead to unreasonable applications. Therefore, in order to better utilize the HPAM/Al3+systems, the characteristics of gelation of HPAM and the three types of aluminum citrate under different salinities are systematically studied. Experimental results show that an important reason for the cross-linking reaction of HPAM/Al3+being affected by salinity is that the morphology and structure of the aluminum citrate complex is different under the different salinities. Although the change of characteristics of the reaction time and the cross-linking degree of the three HPAM/Al3+systems are different, the process of the cross-linking reactions of the three HPAM/Al3+systems are the same. Besides, the thermal stability of the HPAM/Al3+gels is weakened with the increasing of salinity regardless of the ratio of citrate ligands to Al3+. According to the matching relationship between salinity and HPAM/Al3+systems, the reaction time can be controlled to achieve the requirements of on-site construction operation for the conformance control of a given heterogeneous oil reservoir.

Adjustment of Liquid Production in Reservoir with Handling Capacity Constraints

An oilfield was an oil reservoir with strong bottom water in offshore, the water cut was as high as 96%. In the high water cut stage, the most effective way of increasing oil production was to extract liquid and increase oil. The processing capacity of oilfield fluid was limited by the conditions. By using Petrel-RE-2017 software, combining reservoir engineering and percolation mechanics methods, this paper analyzes the effect of large-scale liquid pumping, expands coverage and shut-in coning in oil reservoirs with bottom water, and formulates the adjustment strategy of single well production structure of the whole oilfield. It was confirmed that large-scale liquid production can expand coverage and shutting down well can reduce water cut. It can provide reference and guidance for oil field with strong bottom water when it encounters bottleneck of liquid treatment capacity.

Experimental investigation and field pilot testing of air assisted cyclic steam stimulation technique for enhanced heavy oil recovery

Air assisted cyclic steam stimulation (AACSS) process is a novel technique for enhanced heavy oil recovery, which is efficient and economically attractive compared with other non-condensable gases and solvents injection-based techniques. In this study, the performance of AACSS process for an ultra heavy oil reservoir was investigated via laboratory experiments and field data analysis. The results indicate that air injection based on steam stimulation can effectively increase oil recovery in comparison with the conventional cyclic steam stimulation (CSS) process. The injected air can significantly increase and maintain the reservoir pressure, and reduce oil viscosity via flue gas dissolution and the thermal effect of low temperature oxidation (LTO) of the crude oil. The field pilot testing results of the AACSS technique in Liaohe Oilfield (Northeast China) demonstrate that AACSS can significantly increase oil production, prolong the effective production period of time, reduce water cut and the steam to oil ratio. A scoping economic study shows that the AACSS process can be more economically attractive than CSS process in terms of net present value. The AACSS technique has been effectively applied in mature heavy oil reservoirs developed by the conventional CSS, and it is also a feasible option to deep and offshore heavy oil reservoirs. [Received: January 6, 2017; Accepted: August 10, 2017]

Maximizing the Value of Information of a Horizontal Polymer Pilot Under Uncertainty Incorporating the Risk Attitude of the Decision Maker

SummaryPolymer injection might lead to incremental oil recovery and increase the value of an asset. Several steps must be taken to mature a polymer-injection project. The field needs to be screened for applicability of polymer injection, laboratory experiments have to be performed, and a pilot project might be required before field implementation.The decision to perform a pilot project can be dependent on a value-of-information (VOI) calculation. The VOI can be derived by performing a work flow that captures the effects of the range of geological scenarios, as well as dynamic and polymer parameters, on incremental net present value (NPV). The result of the work flow is a cumulative distribution function (CDF) of NPV linked to prior distributions of model parameters and potential observables from the polymer-injection pilot.The effect of various parameters on the CDF of the fieldwide NPV can be analyzed and in turn used to decide which measurements from the pilot have a strong sensitivity on the NPV CDF, and are thus informative. In the case shown here, the water-cut reduction in the pilot area has a strong effect on the NPV CDF of the polymer-injection field implementation. To extract maximum information, the response of the pilot for water-cut reduction needs to be optimized under uncertainty.To calculate the VOI, the expected-monetary-value (EMV) difference of a decision tree with and without the pilot can be used if the decision maker (DM) is risk neutral. However, if the DM requires hurdle values through a probability of economic success (PES), value functions (VFs) and decision weights according to the prospect theory should be used. Applying risk hurdles requires a consistent use of VFs and decision weights for calculating VOI and the probability of maturation (POM) of projects.The methodology was applied to assess the VOI for a horizontal-well pilot in the ninth Tortonian Horizon (9TH) Reservoir in Austria for a risk-averse DM. The operating parameters (polymer concentration and water injection) were chosen such that the water-cut reduction, which was the most influential parameter of the polymer pilot on the field NPV CDF, was maximized.

Numerical simulation of air\u2013foam flooding in Wuliwan District 1 of Jing\u2019an Oilfield

Air–foam flooding is an important mean to reduce water cut, improve oil production rate, enhance oil displacement efficiency and oil recovery in old oilfield. Because of high cost of core displacement experiment, numerical simulation is an important method to get optimal injection-production parameters of air–foam flooding, which can improve displacement effect and direct field test in Wuliwan District 1 of Jing’an oilfield. Based on laboratory experiment of air–foam flooding, parameters including model component, low temperature oxidation reaction, physical/chemical phenomena, foam interpolation function were set, and then numerical simulation concept model of air–foam flooding was established, which realized accurate fitting for 1-D core flooding experiment. According to numerical simulation concept model of air–foam flooding, the injection-production parameters including injection volume, gas–liquid ratio, and injection time are optimized. Results indicated that optimum surfactant concentration was 0.5%, optimum injection volume of air–foam was 0.25PV, optimum gas–liquid ratio was 1.5:1, optimum injection time was 65% water cut when air–foam flooding began. The researches were applied in Wellbock ZJ53, Wuliwan District 1 of Jing’an Oilfield. There were 15 well groups with air–foam injection and 63 producers, with annual oil production rate scale of 50000 tons. The oil increase effect was very obvious and the application in Jing’an Oilfield was successful.

Mechanism of Polyacrylamide Hydrogel Instability on High-Temperature Conditions.

A gel system composed of acrylamide (AM), N,N′-methylenebisAM (BIS), and ammonium persulfate ((NH4)2S2O8) was developed and applied extensively in reservoirs to reduce water cut and increase oil production in mature fields. However, this gel system suffers from thermal stability loss and syneresis at high temperatures that reduces its ability to control water flow. It has been widely accepted that the loss of gel thermal stability can be explained via three aspects: the rupture of polymer chains, the breakage of cross-linker chains, and hydrolysis of polymer. The mechanism of hydrogel syneresis through polymer hydrolysis has been investigated extensively in other publications. However, research on the other two mechanisms is quite limited. In this article, we conduct a series of experiments to demonstrate how the rupture of polymer and cross-linker chains leads to the hydrogel instability at high temperatures. Viscosity and energy-dispersive system measurements suggested that polyAM chains were disrupted by the oxidation reactions involving free radicals. The method to measure the cross-linking degree was established and in combination with X-ray photoelectron spectroscopy measurements, the results showed that cross-linker chains were broken as a result of weaker C–N bond resulting from positively charged mesomethylene carbon and hydrolysis of amide groups on the cross-linker. Because of the application of deionized water in the experiments, nuclear magnetic resonance and FTIR measurements showed that the hydrolysis degree of polymer was weak. Hence, our results verified that breakage of polymer and cross-linker chains led to the rupture of the gel network at high temperature. Besides, cross-linker chains may play a more important role in the thermal stability of the gel, which explains some work into high-temperature-resistant gels.

Numerical simulation study to understand the performance of RPM gels in water-shutoff treatments

Disproportionate Permeability Reduction (DPR) is often used as a water-shutoff treatment in production wells when conventional solutions such as mechanical isolations are difficult to perform. Although this property has been well documented by different investigators, the performance of DPR treatments in field applications has varied between success and failure without understandable reasons. This work investigated the DPR performance in different scenarios to see when, where and at which conditions DPR treatments can give better results. Numerical simulation methods were used to simulate different scenarios happening in oil and gas fields such as five-spot pattern system and linear-system, with different number of layers, with and without crossflow. The possibility of using DPR treatment in hydraulically-fractured reservoirs was also investigated since many reports indicated that there is an increase in the water production for some oil and gas reservoirs after being hydraulically-fractured. Moreover, the physical reasoning behind the variations in the DPR performance for different scenarios has been extensively discussed.The results explored that the DPR performance was excellent in both of water-cut reduction and oil-recovery improvement when the flow regime was viscous dominated (viscous-gravity number<0.1). On the other hand, when the flow regime was gravity dominated (viscous-gravity number >10), the effective period of DPR treatment was a short-term remedy. Secondly, when the high-K layer is existed at the lower-zone of oil or gas reservoir, the reservoir would be a good candidate for the DPR treatment as compared with the reservoirs that have the high-K layer located at the upper zone. Furthermore, selecting the correct time to perform DPR treatments generally could have a significant role to mitigate water production. Finally, the dimensions of the treated fracture are the key components to get a successful DPR-treatment in the hydraulically fractured reservoirs.