A Novel Double-Group Crosslinked Hydrogel with High Thixotropy for Water Control in Horizontal Wells

SPE Journal ◽  
2020 ◽  
pp. 1-15
Author(s):  
Gang Li ◽  
Lifeng Chen ◽  
Meilong Fu ◽  
Lei Wang ◽  
Yadong Chen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Gelation Time ◽  
Horizontal Wells ◽  
Uniform Grid ◽  
Drilling Fluids ◽  
Water Production ◽  
Water Control ◽  
Recovery Coefficient ◽  
Metastable Structure ◽  
Control Water

Summary Horizontal wells that are completed with slotted liners often suffer from a severe water-production problem, which is detrimental to oil recovery. It is because the annulus between the slotted liners and wellbore cannot be fully filled with common hydrogels with poor thixotropy, which determines the ultimate hydrogel filling shape in the annulus. This paper presents a novel hydrogel with high thixotropy to effectively control water production in horizontal wells. This study is aimed at evaluating the thixotropic performance, gelation time, plugging performance, and degradation performance. The thixotropic performance of the new hydrogel was also investigated by measuring its rheological properties and examining its microstructures. It was found that the new hydrogel thickened rapidly after shearing. Its thixotropic recovery coefficient was 1.747, which was much higher than those of traditional hydrogels. The gelation time can be controlled in the range of 2 to 8 hours by properly adjusting the concentrations of the framework material, crosslinker, and initiator. The hydrogel could be customized for mature oil reservoirs, at which it was stable for more than 90 days. A series of laboratory physical modeling tests showed that the breakthrough pressure gradient and the plugging ratio of the hydrogel in sandpacks were higher than 9.5 MPa/m and 99%, respectively. At the same time, it was found that the hydrogel has good degradation properties; the viscosity of the hydrogel breaking solution was 4.22 mPa·s. Freeze-etching scanning-electron-microscopy examinations indicated that the hydrogel had a uniform grid structure, which can be broken easily by shear and restored quickly. This led to the remarkable thixotropic performance. The formation of a metastable structure caused by the electrostatic interaction and coordination effect was considered to be the primary reason for the high thixotropy. The successful development of the new thixotropic hydrogel not only helps to control water production from the horizontal wells, but also furthers the thixotropic theory of hydrogel. This study also provides technical guidelines for further increasing the thixotropies of drilling fluids, fracturing fluids, and other enhanced-oil-recovery polymers that are commonly used in the petroleum industry.

Increased Recovery Using Autonomous Inflow Management

2019 ◽  
Author(s):  
Bernt S. Aadnøy ◽  
Beder Al Furati
Keyword(s):  
Oil Recovery ◽  
Horizontal Wells ◽  
Water Production ◽  
Active Devices ◽  
Considerable Portion ◽  
Master Thesis ◽  
Control Devices ◽  
Reservoir Simulator ◽  
The University ◽  
Viscosity Fluid

Abstract Inflow control devices (ICD) were first introduced 26 years ago on the Troll field. The main purpose was to reduce water coning to delay water production. This technology is commonly used in long horizontal wells. An ICD is a passive orifice. More recently several types of active devices have been developed. The choking effect here depends on viscosity, fluid density or pressure contrasts. They are called autonomous devices as they react on changes inside the reservoir, without signal from surface. The main objective is to maximize oil recovery, before water production is so large that the wells are abandoned. A master thesis study conducted at the University of Stavanger together with Neptune Energy has investigated the applications of passive and autonomous inflow devices, to see which tool actually provides the highest oil recovery. The analysis was based on existing products and tools under development. Areas where a specific tool works most optimally were identified. Wells from a producing field were used as candidates for the analysis. A considerable portion of the work was to build a realistic reservoir simulator from production data. This paper will present the work and discuss the results of the study.

Application of Multilateral Wells for Production and Enhanced Oil Recovery: Case Studies from Canada

2021 ◽  
pp. 1-23
Author(s):  
Eric Delamaide
Keyword(s):  
Oil Recovery ◽  
Horizontal Wells ◽  
Production Performance ◽  
Water Production ◽  
Public Data ◽  
Heavy Oil Reservoirs ◽  
Complex Architectures ◽  
Cumulative Production ◽  
Tertiary Recovery ◽  
And Performance

Summary The use of multilateral wells started in the mid-1990s in particular in Canada, and they have since been used in many countries. However, few papers on multilateral wells focus on their production performance. Thus, what can be expected from such wells in terms of production is not clear, and this paper will attempt to address that gap. Taking advantage of public data, the production performance of multilateral wells in various Western Canadian fields has been studied. In the cases reviewed in this paper, these wells always target a single formation; they have been used in a variety of fields and reservoirs, mostly for primary production but also for polymer flooding in some cases. Multiple examples will be provided, mostly in heavy oil reservoirs, and production performance will be compared with nearby horizontal wells whenever possible. From the more classical dual and trilateral, to more complex architectures with seven or eight laterals, and the more exotic with laterals drilled from laterals, the paper will present the architecture and performance of these complex wells and of some fields that have been developed almost exclusively with multilateral wells. Interestingly, multilateral wells have not been used much for secondary or tertiary recovery, probably because of the difficulty of controlling water production after breakthrough. However, field results suggest that this may not be such a difficult proposition. One of the most remarkable wells producing a 1,250-cp oil under polymer flood has achieved a cumulative production of more than 3 million bbl, which puts it among the top producers in Canada. Although multilateral wells have been in use for more than 25 years, very few papers have been devoted to the description of their production performance. This paper will bring some clarity to these aspects. It will also attempt to address when multilateral wells can be used and to compare their performance to that of horizontal wells in the same fields. It is hoped that this paper will encourage operators to reconsider the use of multilateral wells in their fields.

scholarly journals Evaluation of influencing factors on the adaptability of ICD completion technology

2021 ◽  
Vol 261 ◽  
pp. 02071
Author(s):  
Guohui Zhang ◽  
Liangchuan Li ◽  
Rong Chen ◽  
Peng Wang ◽  
Guowen Zhang ◽  
...  
Keyword(s):  
Comprehensive Evaluation ◽  
Design Method ◽  
Orthogonal Experiment ◽  
Horizontal Wells ◽  
Water Production ◽  
Water Control ◽  
Orthogonal Experiment Design ◽  
Factors Affecting ◽  
Well Completion ◽  
Main Index

After years of research and practice, ICD well completion technology has become a relatively mature completion technology, and has been successfully applied in hundreds of horizontal Wells abroad. However, due to many factors affecting ICD effect, mature evaluation methods have not been completely established. At present, the main index of ICD water control development effect is to balance inflow profile and inhibit water production, and the evaluation factors involve reservoir, process and equipment structure. This paper summarizes the factors influencing the effects of ICD, using orthogonal experiment design method to carry on the comprehensive evaluation, and puts forward the corresponding Suggestions

PLANNING AND DRILLING OF SINUOUS HORIZONTAL WELLS FOR THE GRIFFIN AREA DEVELOPMENT

1994 ◽  
Vol 34 (1) ◽  
pp. 19
Author(s):  
D. Berean ◽  
T. Slate ◽  
T. Wallace ◽  
R. Aldred ◽  
L. Hedger ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Vertical Section ◽  
Horizontal Wells ◽  
Wellbore Stability ◽  
Production Performance ◽  
Drilling Fluids ◽  
Planning Period ◽  
Horizontal Drilling ◽  
Formation Evaluation ◽  
Area Development

The Griffin Area Development in the Barrow Sub-basin of Western Australia consists of three major oil fields, the Griffin, Scindian and Chinook fields.One of many new concepts of subsea technology used for the Griffin Area Development is the application of horizontal wells with a sinuous profile to improve oil recovery in the Birdrong reservoir.Reservoir simulation modelling initiated the concept and as a result, a multi-disciplined team was formed early in the pre-development phase to plan and implement a horizontal drilling program. Issues which were addressed by this team during planning included wellbore stability, drilling fluids, liner and completion design, wellpath orientation, reservoir constraints and formation evaluation techniques.After an extensive planning period, three sinuous path horizontal wells, Griffin-5(H), Griffin-6/ST1(H) and Scindian-2/STI(H) were successfully drilled in early 1993 by a semi-submersible rig as part of the Griffin/Scindian fields development drilling program.These sinuous wells have a well path profile which intersects the reservoir in three low-angle passes of the vertical section over a horizontal length of between 800 and 950 m, in the shape of a sine wave.A feature of the wells was the use of geosteering techniques to keep the sinuous profile on track to intersect specific reservoir targets, using the latest in formation evaluation measurement while drilling (FEMWD) technology.Although technically successful, the economic benefit of the horizontal wells will be measured by their production performance when tied into the 'Griffin Venture' floating production facility, expected on stream in early 1994.

Relative Permeability Modifiers as a Chemical Means to Control Water Production in Oil and Gas Reservoirs

2021 ◽  
Author(s):  
Ali Al-Taq ◽  
Abdullah Alrustum ◽  
Basil Alfakher ◽  
Hussain Al-Ibrahim
Keyword(s):  
Relative Permeability ◽  
Gas Flow ◽  
Water Production ◽  
Success Rates ◽  
Water Control ◽  
Overburden Pressure ◽  
The Core ◽  
Carbonate Cores ◽  
Polymer Retention ◽  
Control Water

Abstract It is challenging to control water production in horizontal wells or in vertical wells having oil and water produced from the same zone using conventional methods such as through-tubing bridge plugs or other mechanical means. Relative permeability modifiers (RPMs), known to selectively reduce the relative permeability to water with minimum impact on the relative permeability to oil or gas, are considered a promising technology for solving this problem. The current generation of RPMs, unlike the old ones, can tolerate high hardness and so have higher success rates. An extensive experimental work was carried out to evaluate three RPMs for water control in gas and oil wells. Test conditions included gas flow in sandstone cores with temperatures of up to 300°F, and oil flow in carbonate cores with temperatures as high as 220°F. The effect of initial core permeability to brine, RPM concentration, flow rate, and water-wetting surfactants on the effectiveness of RPM to reduce water production was investigated using sandstone and carbonate cores. Coreflood experiments were undertaken at downhole conditions. The end-point relative permeabilities to various phases were measured. A back pressure of 500 psi, an overburden pressure of 3,500 to 5,000 psi and flow rates of 0.1 to 5 cm3/min were used. The concentration of RPM polymers was monitored in the core effluent using total organic carbon (TOC) analyzer to determine polymer retention in the core. The results revealed that temperature adversely affected the effectiveness of all RPMs evaluated. A better reduction in permeability to water was obtained at 220°F compared to that obtained at 300°F. The use of RPM at the right concentrations was found to significantly reduce permeability to water. A better water reduction was obtained at higher polymer injection rates, which was attributed to flow-induced polymer retention. Adsorption of RPM polymer tended to alter wettability of a carbonate rock to more water-wet. This paper discusses the effects of the above parameters on the performance of RPM in sandstone and carbonate reservoirs, and it gives some recommendations for improving the success rate of these chemical applications in the field.

Simultaneous Acid Diversion and Water Control in Carbonate Reservoirs: A Case History From Saudi Arabia

2008 ◽  
Vol 11 (05) ◽  
pp. 882-891 ◽  
Author(s):  
Ali A. Al-Taq ◽  
Hisham A. Nasr-El-Din ◽  
Jimmy K. Beresky ◽  
Khalid M. Al-Naimi ◽  
Leopoldo Sierra ◽  
...  
Keyword(s):  
Saudi Arabia ◽  
Relative Permeability ◽  
Carbonate Reservoir ◽  
Water Production ◽  
Water Control ◽  
Matrix Acidizing ◽  
Associative Polymers ◽  
Acid Diversion ◽  
Associative Polymer ◽  
Control Water

Summary Matrix acidizing and water control are usually addressed as two separate issues. Associative polymers can be used to simultaneously achieve effective acidizing and water control during a single treatment. A polymer-based treatment was applied in an offshore, perforated vertical well with two sets of perforations in a carbonate reservoir in Saudi Arabia. The acid treatment was needed to restore the productivity of the upper set of perforations and reduce water production from the lower set of perforations. Experimental studies were carried out to investigate the potential use of associative polymers to control water mobility and act as an acid diverter. Coreflood experiments were conducted on reservoir cores at downhole conditions (temperature of 200°F and pressure of 3,500 psi). Extensive laboratory testing showed that associative polymers had no significant effect on the relative permeability to oil. However, the relative permeability to water was significantly reduced. This paper presents a case history where an associative polymer was applied during matrix acid treatment of a damaged well. The treatment included two stages of associative polymer solutions and 20 wt% HCl with additives. Post-stimulation treatment production data showed that oil rate increased 11.18-fold, whereas water rate decreased 1.7-fold, resulting in a reduction in the water cut from 75 to 14 vol%. The production logging tool (PLT) results indicated that the associative polymer was effective in diverting the acid into the oil producing zone. The upper set of perforations was producing most of the fluid, which further confirmed that the associative polymer significantly reduced water production from the lower zone. Introduction Matrix acidizing and water control are two important treatments conducted to enhance well performance. These treatments are commonly addressed as two separate issues. Associative polymers can be used to simultaneously achieve effective acidizing and water control utilizing a single treatment (Eoff et al. 2005). Acid diversion is an important issue contributing to the success of any matrix acid stimulation treatment. For this reason, extensive laboratory studies and field applications have been performed on several acid diverting agents as reported in the literature. Among the techniques that have been applied to improve acid coverage are: mechanical (packers, ball sealers, and particulate diverting agents) and chemicals (foam, polymers, and in-situ-gelled fluids). More recently, viscoelastic surfactants have been used extensively for diversion during matrix acid treatments, and have shown a tendency to reduce water production as reported by Nasr-El-Din et al. (2006). Relative permeability modifiers, commonly used for water control, can also be utilized for acid diversion. They can act simultaneously to enhance diversion during matrix acid treatments and impair water mobility. Eoff et al. (2005) presented laboratory and field tests, which showed that associative polymers could provide both goals in sandstone reservoirs. However, a few studies considered application of associative polymers to divert and control water production in carbonate formations. Therefore, the objectives of the present study are to:assess the effectiveness of associative polymers in reducing brine permeability in carbonate cores,design a polymer-based treatment to control water and divert acid in matrix treatments, andevaluate the use of associative polymers based on field application. This paper presents laboratory data that support the use of this new technology in carbonate reservoirs. It will also give for the first time field results on the application of associative polymers in a carbonate reservoir in Saudi Arabia. Field data were in good agreement with laboratory results.

Production optimisation and water control in oil/water producing wells using horizontal downhole water sink technology

2011 ◽  
Vol 51 (1) ◽  
pp. 577
Author(s):  
Fadi Ali ◽  
Hassan Bahrami ◽  
Po Chu Byfield ◽  
Jijin Mathew
Keyword(s):  
Pressure Drop ◽  
Oil Recovery ◽  
Gas Production ◽  
Production Operation ◽  
Water Production ◽  
Water Control ◽  
Water Zone ◽  
Water Breakthrough ◽  
Downhole Water Sink ◽  
Water Problems

Water breakthrough and the flow of water towards the perforations of a producing well increase production operation costs and influence overall recovery efficiency. To control water production, a downhole water sink can be used in which a well is completed in both oil and water zones. Water is produced from an interval in water zone, which can result in the same pressure drop below water oil contact (WOC) as the pressure drop created by oil or gas production. This system can reduce water production through oil zone perforations. Water produced from water zone perforations can then be injected in deeper aquifers intervals. This technology can also be implemented in horizontal and multi-lateral wells to further increase hydrocarbon recovery with fewer water problems. This study examines the use of horizontal downhole water sink technology to increase oil recovery. Numerical simulation is performed to optimise oil production and water control in a multi-layered oil reservoir, by optimising the direction of drilling and the downhole water sink method. Different scenarios of drilling direction and horizontal down-hole water sink method are examined to identify the option that provides maximum oil recovery. The simulation results showed that drilling horizontal wells in a north–south direction resulted in higher well productivity, and that wells with significantly more water production problems can be controlled using a horizontal downhole water sink.

Application of Horizontal Wells to Reduce Water Production during Gel Treatment

2013 ◽  
Vol 807-809 ◽  
pp. 2629-2633
Author(s):  
Guang Xi Shen ◽  
Ji Ho Lee ◽  
Kun Sang Lee
Keyword(s):  
Oil Recovery ◽  
Substantial Reduction ◽  
Cross Flow ◽  
Oil Production ◽  
Horizontal Wells ◽  
Water Production ◽  
Sweep Efficiency ◽  
Vertical Permeability ◽  
Water Breakthrough ◽  
Gel Treatment

It is well known that gel treatment has outstanding potential to delay water breakthrough and reduce water production. However, it causes the decrease of oil production by permeability reduction, even though it is not as much as reduction of water production. For this reason, to improve oil production with substantial reduction of water production, performances of gel treatments through the combination of horizontal and/or vertical wells were assessed and compared. An extensive numerical simulation was executed for four different well configurations under gel treatment associated with waterflood to accomplish the purpose of this study. Performances were compared according to cumulative oil recovery and water-oil ratio at the production well for different systems. Though all of well configurations considered in this study effectively decreased the water production compared with waterflood, applications of horizontal wells led to much higher oil recovery than vertical well because of improved sweep efficiency. Based on these results, the potential of horizontal wells was examined through different scenarios in combinations of injection and production wells. Furthermore, various well lengths of injectors or producers were assessed for horizontal wells. Because cross-flow between layers dominates performance of gel treatment, effects of vertical permeability were also investigated in application of gel treatment with horizontal well. Longer wells and higher cross-flow results in better performance. This study represents that effectiveness of horizontal wells for gel treatment even for reservoirs having dominant cross-flow.

scholarly journals A novel approach in extracting predictive information from water-oil ratio for enhanced water production mechanism diagnosis

2010 ◽  
Vol 50 (1) ◽  
pp. 567 ◽  
Author(s):  
Minou Rabiei ◽  
Ritu Gupta ◽  
Yaw Peng Cheong ◽  
Gerardo A. Sanchez Soto
Keyword(s):  
Oil Recovery ◽  
Water Production ◽  
Ensemble Classifiers ◽  
Production Mechanism ◽  
Water Control ◽  
Predictive Information ◽  
Oil Companies ◽  
Excess Water ◽  
Wide Range ◽  
Production Mechanisms

Despite the advances in water shutoff technologies, the lack of an efficient diagnostic technique to identify excess water production mechanisms in oil wells is preventing these technologies being applied to deliver the desired results, which costs oil companies a lot of time and money. This paper presents a novel integrated approach for diagnosing water production mechanisms by extracting hidden predictive information from water-oil ratio (WOR) graphs and integrating it with static reservoir parameters. Two common types of excess water production mechanism (coning and channelling) were simulated where a wide range of cases were generated by varying a number of reservoir parameters. Plots of WOR against oil recovery factor were used to extract the key features of the WOR data. Tree-based ensemble classifiers were then applied to integrate these features with the reservoir parameters and build classification models for predicting the water production mechanism. Our results show high rates of prediction accuracy for the range of WOR variables and reservoir parameters explored, which demonstrate the efficiency of the proposed ensemble classifiers. Proactive water control procedures based on proper diagnosis obtained by the proposed technique would greatly optimise oil productivity and reduce the environmental impacts of the unwanted water.

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