Control Water Production Research Articles

Mechanistic Insights into a Novel Controllable Phase-Transition Polymer for Enhanced Oil Recovery in Mature Waterflooding Reservoirs.

Expanding swept volume technology via continuous-phase polymer solution and dispersed-phase particle gel is an important technique to increase oil production and control water production in mature waterflooding reservoirs. However, problems such as the low viscosity retention rate, deep migration, and weak mobility control of conventional polymers, and the contradiction between migration distance of particle gel and plugging strength, restrict the long-term effectiveness of oil displacement agents and the in-depth sweep efficiency expanding capability in reservoirs. Combined with the technical advantages of polymer and particle gel, a novel controllable phase-transition polymer was developed and systematically studied to gain mechanistic insights into enhanced oil recovery for mature waterflooding reservoirs. To reveal the phase-transition mechanism, the molecular structure, morphology, and rheological properties of the controllable phase-transition polymer were characterized before and after phase transition. The propagation behavior of the controllable phase-transition polymer in porous media was studied by conducting long core flow experiments. Two-dimensional micro visualization and parallel core flooding experiments were performed to investigate the EOR mechanism from porous media to pore level. Results show that the controllable phase-transition polymer could change phase from dispersed-phase particle gel to continuous-phase solution with the prolongation of ageing time. The controllable phase-transition polymer exhibited phase-transition behavior and good propagation capability in porous media. The results of micro visualization flooding experiments showed that the incremental oil recovery of the controllable phase-transition polymer was highest when a particle gel and polymer solution coexisted, followed by a pure continuous-phase polymer solution and pure dispersed-phase particle gel suspension. The recovery rate of the novel controllable phase-transition polymer was 27.2% after waterflooding, which was 8.9% higher than that of conventional polymer, providing a promising candidate for oilfield application.

Synergistic mechanism of enhanced heavy oil recovery by compound flooding using 3D visualization model

Most of oilfields have entered the development stage of high water-cut and low recovery factors, and stabilizing oil production and controlling water production are the key to enhancing subsequent oil recovery. Adopting the 1/4 five-point injection-production well pattern, the chemical flooding experiments were conducted using a three-dimensional (3D) visualization sand-pack model with liquid drain orifices. A real-time image acquisition and dynamic observation device for detecting droplet textures as fluid flowing was developed with experimental system. In heterogeneous reservoirs with a high permeability contrast, the effects of oil-displacement agents on production dynamics, sweep morphology, and emulsifying characteristics of remaining oil at different locations were investigated to reveal the synergistic mechanism of compound flooding for enhanced oil recovery. The results showed that, in the main streamline region, the mean droplet diameter decreased, the distribution density increased first and then decreased, and the maldistribution decreased first and then increased with an increase in injection volume of the compound system. In the vertical region with the main streamline, the mean diameter and maldistribution reduced, and the distribution density increased owing to the synergistic mechanism. The viscosity reducer can increase sweep efficiency by 8.34% and recovery factor by 5.95% due to the viscous crossflow in the high permeability channel. The compound system can increase sweep efficiency by 15.92% and recovery factor by 12.67% due to the synergistic effect of emulsifying-tapping, emulsion plugging conversion, and profile control. Therefore, chemical compound flooding has great potential of enhancing heavy oil recovery in heterogeneous reservoirs due to the synergistic effect of the compound system.

Numerical approach on production optimization of high water-cut well via advanced completion management using flow control valves

With the development of smart downhole control devices, such as the electric flow control valve (FCV), research on completion optimization using FCV control is gaining traction for successful field production management. Applying and verifying its applicability to actual assets with uncertain production issues occur are important. This study focuses on managing downhole devices to optimize fluid production in an actual onshore oil field in Alberta, Canada. The target field has been in production operation for over 20 years, and water flooding was used in the early stages of production to maintain reservoir pressure. However, according to the flow characteristics of the field, water injection caused a high water-cut issue due to water channeling. To mitigate the problem, proactive and reactive strategies were investigated to optimize FCV control. Additionally, the effect of completion optimization was estimated considering both the field-level economic value and the fluid production behavior at the device level. In most optimization cases, the cumulative water production could be reduced compared with the base case without valve control. Notably, the flow-balancing strategy increased the revenue of the target field by approximately 23 MM$ by maximizing oil production and suppressing water production. However, reactive and streamline-balancing strategies, which directly control and delay water production, undermined the economic value due to the decrease in oil production. The findings imply that FCV control strategy of suppressing only water production for the field with high water-cut could not be the optimal solution considering the reduction in oil production and the field’s revenue. The results of this study could be used as a reference to optimize downhole devices when applying water flooding in fields where high water-cut is expected.

A new method of water control for horizontal wells in heavy oil reservoirs

It is more difficult to control water production in horizontal wells than in vertical wells. It is challenging to predict the water-producing section of a horizontal well and realize staged oil recovery. With water breaking through the oil layer, the water cut of production wells sharply rises. This can even lead to early closure of production wells, which can seriously affect the economic benefits. When researchers explore water control of horizontal wells, they usually use the method of plugging the water-producing section. The success rate is often low due to water flow around the plugged section and pollution of plugging agents in the high-oil saturation area. On the basis of nitrogen for water cresting control, this paper studied the ability of a viscosity reducer (VR) and nitrogen (N2) compound system to inhibit the rise in the water crest. First, a series of two-dimensional quantitative experiments and visualization experiments were conducted to study the influence and mechanism of the VR and N2 system in controlling water cresting. The results show that compared to N2 control of water cresting (recovery improved by 2.70%), the compound system greatly improved the water control and oil increase effects of the horizontal well (recovery improved by 26.38%). The VR enters the area with high oil saturation through osmosis to reduce the viscosity of heavy oil and the water-oil mobility ratio. N2 enhanced the osmosis of the VR in the reservoir. In addition, rheological tests were performed of heavy oil mixtures, and the viscosity reduction mechanism of the VR was analyzed via diffusion-ordered spectroscopy (DOSY) and scanning electron microscopy (SEM). The experiment shows that after addition of the VR, the size of heavy oil deposit was reduced and the asphaltene surface was broken. The VR reduced the viscosity of heavy oil by depolymerizing macromolecular aggregates in heavy oil and preventing them from coming together again. Finally, a field test was conducted in a horizontal well, with a cumulative oil increase of 9286.86 bbl. The research results provide an important guiding significance for water control and oil recovery of horizontal wells.

On improving the system of the management of the drinking water quality under implementation of federal project «Clean water»

Introduction. During the implementation of the federal project “Clean Water”, the Federal Service for Supervision in Protection of the Rights of Consumer and Man Wellbeing (Rospotrebnadzor) provides the following directions: control over the implementation of target indicators of the federal project “Clean Water”; improving the efficiency of the control for the drinking water quality; methodological support for the management of the assessment and monitoring for drinking water quality, and informing the population about drinking water quality. The purpose of the study: analysis of the implementation of measures by Rospotrebnadzor to achieve the targets of the federal project “Clean Water” with the subsequent development of proposals for improving the control for drinking water quality. Materials and methods. The study used the forms of federal statistical observation: No. 18, No. 2-20; federal information fund of social and hygienic monitoring data, state report “On the state of sanitary and epidemiological well-being of the population in the Russian Federation in 2021”. The methods of system and content analysis are applied in the work. Results. During the period of the federal project “Clean Water” Rospotrebnadzor has equipped laboratories with modern equipment. Guidelines have been developed and approved for drinking water quality assessment and organizing its monitoring, laboratory control, and conducting a water quality integral assessment. An information system has been developed to inform the population about the drinking water quality. Limitations. The study did not take into account the results of drinking water production control. This is due to the difficulties of collecting information, its standardization and analysis. Conclusion. A system for drinking water quality monitoring in the Russian Federation has been established. Methodological support for drinking water quality monitoring and assessment has been developed, and public information about drinking water quality has been managed. The following questions need to be further addressed: it is necessary to update social and hygienic monitoring programs, organize the receipt and exchange of information on the results of production control of the quality of drinking water, moderate the procedure for assessing the risk to public health.

Laboratory Evaluation and Field Application of a Gas-Soluble Plugging Agent: Development of Bottom Water Plugging Fracturing Technology

The currently reported bottom water sealing materials and fracturing technologies can hardly simultaneously achieve the high production and low water cut of gas reservoirs due to the complexity of various formation conditions. Therefore, without controlling the fracturing scale and injection volume, a kind of polylactide polymer water plugging material with a density of 1.15–2.0 g/cm3 is developed, which can be used to seal the bottom water of a gas–water differential layer by contact solidification with water and automatic degradation with natural gas. This technology can not only fully release the production capacity of the gas reservoir but also effectively control water production and realize the efficient fracturing development of the target gas reservoir. Laboratory test results show that the smart plugging agent has a bottom water plugging rate of 100%, and the low-density plugging agent has a dissolution rate of 96.7% in methane gas at 90 °C for 4 h and a dissolution rate of 97.6% in methane gas at 60 °C for 6 h, showing remarkable gas degradation performance. In addition, settlement experiments show that the presence of a proppant can increase the settlement rate of a plugging agent up to many times (up to 21 times) in both water and guanidine gum solution. According to the actual conditions of well J66-8-3, a single-well water plugging fracturing scheme was prepared by optimizing the length of fracture, plugging agent dosage, and plugging agent sinking time, and a post-evaluation method was proposed. It has guiding significance to the development of similar gas reservoirs.

Development of an effective completion schedule for a petroleum reservoir with strong aquifer to control water production

sA reasonable solution, to deal with oil field water problem, is to minimize the amount of water associated with oil production using effective completion lengths. This work presents an effective method to optimize wells’ completion lengths in an oil reservoir with a strong aquifer. The suggested technique is formulated as a constrained optimization problem that defines a NPV objective function and a set of existing field/facility constraints. An effective algorithm translates the completion lengths to connections number in the dynamic simulation model. In this approach, a genetic algorithm (GA), an adaptive version of simulated annealing (ASA) and a particle swarm optimization (PSO) hybridized with polytope technique are applied to maximize NPV. A comparison is given for their performances in a strong water-drive reservoir where the combinatorial effects of wells’ completion lengths (decision variables) should be addressed. Optimizing the lengths of completions leads to an increased production period, total oil production, retarding water breakthrough, reducing total water production, and finally increasing ultimate recovery. The results showed that total oil production by GA, ASA and PSO algorithm is increased by 11.0%, 2.40% and 2.22%, respectively, related to the initial case. Total water productions are decreased by GA, 9.82%, by ASA 2.11%, and by PSO 1.82% relative to the initial schedule. The best performance belongs to the GA algorithm. Moreover, the average watercut of all wells is decreased through the optimization process. Besides, based on the numerical simulation, closing the worst connections with high watercut decreases total water production, and improves oil recovery, maximum well productivity, and NPV (oil–water ratio is increased 18.2%). Most connections are placed in the layers where water coning can occur later (considering near-well-bore permeability) and slightly far from full water zone.

Evaluation of Ultrahigh-Temperature-Resistant Preformed Particle Gels for Conformance Control in North Sea Reservoirs

Summary Preformed particle gels (PPGs) are 3D, crosslinked, dried polymer particles that can swell to several hundred times on contact with formation water. PPGs have been used extensively to control water production problems in reservoirs with conformance problems. The current state-of-the-art PPGs are polyacrylamide-based hydrogel compositions which lack long-term thermal stability under high-temperature and -salinity conditions. There are many oil reservoirs across the globe exhibiting conditions of temperatures higher than 120°C with high salinity. A novel ultrahigh-temperature-resistant PPG composition (DMA-SSS PPG) was designed to fill up the technology gap between existing polyacrylamide-based PPG technology that degrades readily over 110°C temperatures. DMA-SSS PPG exhibited excellent thermal stability for greater than 18 months in North Sea formation and formation water environments at 130°C. DMA-SSS PPG described herein showed swelling capacities of up to 30 times in different salinity North Sea brines. DMA-SSS PPG’s physiochemical properties like swelling, swelling rate, and rheological behavior were studied as a function of temperature and salinity. DMA-SSS PPGs showed excellent elastic modulus (G’) of about 3200 Pa in formation water of 90% water content. Thermostability of DMA-SSS PPGs was assessed at 130 and 150°C in North Sea brines with different salinity conditions. DMA-SSS PPGs proved to be stable for more than 18 months without losing molecular integrity. Thermostability was further confirmed through different metrics such as cross-polarization magic angle spinning carbon-13 nuclear magnetic resonance (CPMAS 13C NMR), thermogravimetric analysis (TGA), and morphology. Laboratory coreflood experiments were performed to demonstrate the plugging efficiency of open fractures and effectiveness in reducing the permeability. DMA-SSS PPG comprehensive evaluation confirms its novelty for excellent hydrothermal stability, thus can be used to control water production problems for mature reservoirs exhibiting conditions of high salinity and high temperature.

Sensitivity analysis of parameters affecting nano-polymer solution for water shutoff in carbonate rocks

Excessive water production impacts the economics of petroleum reservoir and often leads to their premature shut-in. Production of high saline water represents a major corrosion for casing, tubing, flow lines, and production facilities. Polymer solution has been used to control water production and to plug in high-temperature reservoirs. Most of these polymer solutions consist of polyacrylamide-based polymer and an organic or inorganic cross linker. Polyethylene mine has been used as an organic cross-linked for polyacrylamide. Literature reported that polyethylene mine can also form ringing gels with polyacrylamide copolymers in addition to polyacrylamide concentration. In this study, nano-chemical solutions has been prepared and studied in detail for their efficacy at reservoir condition. The compositions of the nano-chemicals mainly consisted of polyacrylamide mixed with nano particles, cement, coated-clay and polyethylene mine as cross-linker. The aim of using nano particles and coated-clay was to control gel performance and strength under the reservoir condition. Moreover, the effect of nano-chemical composition at higher temperature have been studied extensively on the gelation properties, elastic modulus, viscosity, and swelling ratio. Results showed that the elastic modulus and viscosity improve significantly with the increasing nano particle concentration. Coated-clay can control the gelation time as clay swallows and absorbs more formation water in the target zone, when its thin coated film breaks down, lesser water production can be predicted. Cited as: Soka, S., Sidiq, H. Sensitivity analysis of parameters affecting nano-polymer solution for water shutoff in carbonate rocks. Advances in Geo-Energy Research, 2022, 6(3): 230-240. https://doi.org/10.46690/ager.2022.03.06

A comprehensive review of in-situ polymer gel simulation for conformance control

Gel treatment has been widely applied in mature oilfields to improve sweep efficiency and control water production. Correct numerical simulation is of major importance to the optimization design and prediction of a successful gel treatment. However, there exist many problems in current simulation studies in published literature. This paper first presents a comprehensive review on the major factors that have been considered at different gelation stages during gel treatment, the models used in the commercial/in-house simulators, and current numerical simulation studies on both laboratory and field scales. Then we classify the current in-situ gel numerical simulation problems as 1, deficient model problem that has published numerical model but has not been applied in simulator and application studies; 2, missing model problem that does not have published quantitative model; and 3, inaccurate application problem that does not consider the major factors of gel performance, based on the reasons from some questionable results of current simulation studies. Finally, we point out the major research efforts that should be made in the future to better simulate in-situ gel treatment process. The review indicates that numerous simulation studies using commercial software packages intend to predigest the gel treatment, many of which, however, ignore important mechanisms and mislead the operation of gel treatment. In fact, a full assessment of simulating in-situ gels cannot be achieved unless the quantitative models can be qualified in terms of transport and plugging mechanisms based on the experimental results.

Incorporating adaptive well conditions into numerical reservoir simulators constrained by well and reservoir performance data

Using fixed boundary conditions has always been the way wells are modelled in reservoir simulators for prediction runs. This commonly results in oil wells being shut-in due to increasing production of water or gas or triggering a workover option shutting-in a section of the wells perforated interval. These actions are late reactive actions instead of being proactive actions that can help prolong a wells life. In actual field operations, well flow rates and bottomhole pressures are often adjusted to better suit reservoir management strategies and control water and gas production. This paper introduces a novel yet simple implementation of adaptive well conditions that updates well boundary conditions based on wellbore or near-wellbore performance. This methodology can be executed using a commercial simulator alongside a small instructing application, or internally integrated as done here with an inhouse reservoir simulator built to present this work as proof of concept. Three case studies are presented in this paper with increasing complexity. We show that an improvement in the amount of recovered oil, an increase in the lifetime of assets, and a reduction of produced water and gas are all possible with adaptive well controls. In one of the three cases, adaptive well controls resulted in an oil recovery increase as high as 20%. We also discuss the differences between well-data and reservoir-data dependencies of the adaptive well-condition algorithms in terms of dynamic response and physical application. Implementing adaptive well controls can help in reconsidering business plans by reducing water and gas production and avoiding early abandonment of wells. It was also considered that one of the main advantages of adaptive well conditions is the potentially significant reduction in number of variables for future optimization studies due to the elimination of control steps.

In-depth isolation of highly permeable zones for reservoir conformance control

In-depth isolation of flooded-out reservoir zones is widely used in water injection and water production control in oilfields. This paper looks at the research results of a new technological solution – a method and mechanism of deep-penetrating insulation of highly permeable reservoir areas. Approximate mathematical models are used to describe oil-saturated reservoirs flooding with chemical compositions used as a displaced fluid. The mathematical model of the problem is reduced to a partial differential equation with initial boundary conditions. The article also presents the results of the numerical implementation of the transfer equations of concentrations of gel-forming components and a thickener. In a non-uniform grid domain, the problem at hand is replaced by a discrete problem using a combination of an explicit and implicit-difference scheme that increases the order of accuracy and is solved by the run-through method. Effective algorithms for solving the one-dimensional problem are obtained, taking into account the equations of adsorption and convective diffusion. The developed method increases the efficiency of the in-deep isolation treatment of flushed zones and can be applied to related reservoir flooding projects.

Comprehensive evaluation of a high-temperature resistant re-crosslinkable preformed particle gel for water management

Gel treatment has been widely applied to control conformance for improving oil recovery and control water production in mature oil fields. However, most of the hydrogel systems are limited when being applied in the harsh environments of high temperatures. A systematic evaluation was conducted in this study to evaluate a modified PPG product, the high temperature resistant re-crosslinkable preformed particle gel (HT-RPPG) which can re-crosslink to form a bulky material and keep thermostable in the large-opening features after placement. This material was developed to overcome the limitations of conventional PPGs in the reservoirs with large- opening features such as open fractures, void conduits, wormholes, and so on. The HT-RPPG can swell up to 18 times of its original size at room temperature (23˚C), and the swelling ratio is independent of brine concentration and types. We conducted a series of experiments to evaluate the effect of particle size, temperatures, swelling ratios, brine types on re-crosslinking time, as well as the gel strength, blocking performance and thermostability after re-crosslinking. Smaller particle sizes result in the HT-RPPGs swell and re-crosslink much faster. Higher temperatures increase the swelling and re-crosslinking rate, while the larger swelling ratios (more feeding brine) can slow down the re-crosslinking time. HT-RPPG re-crosslinking process can be delayed when the particles contact with Ca2+. Additionally, the re-crosslinking of HT-RPPG is a temperature-responsive reaction which can only start after reaching the target temperature of 100 °C or above. The HT-RPPG has kept its volume and strength stable at 100 to 130 °C for over 10 months so far. A blocking performance test was conducted by using the tubing model to simulate void-space conduit (VSC), and breakthrough pressure reached to 427 psi/ft.

Water leak control for the oil-producing wells using Downhole Water Sink Technology

Casing or tubing leaks cause unwanted water production from oil-producing wells. Many chemical and mechanic water control technologies can be used to solve this problem, including squeezing chemical shutoff fluids into the targeted zone or using plugs, cement, packers, patches to block the leakage. Although those methods are field-proven to be effective, the mechanical solutions may require well logs to detect the water entry point in the well. Chemical methods may present environment risks. In this study, an alternative method, Downhole Water Sink, is proposed to solve the problem of unwanted water production from a casing or tubing leak. The effectiveness of this method to control water production in a well with casing or tubing leaks is tested using the Hele-Shaw experimental model. The results show that this method can control unwanted water production via dynamic control of the pressure drawdown in the reservoir. From a technical standpoint, the advantage of this technology is that it eliminates the need to run logs to locate the water entry point and does not require chemical injection into the formation. From an environmental standpoint, this technology has the circular economy elements. Because the produced water in this technology contains little or no oil, it can be reused for reinjection into the reservoir for water flooding or pressure maintenance purposes. Therefore, a production-reinjection process to recycle the produced water is established to reduce the pollution caused by discharging the wastewater into the environment.

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

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.

Water Production Problem in Gas Reservoirs: Concepts, Challenges, and Practical Solutions

Gas resources play a key role in nowadays energy supply and provide 24% of the diverse energy portfolio. Water encroachment is one of the main trapping mechanisms in gas reservoirs. It decreases recovery by reduction of reservoir life, limits productivity and efficiency of wells, and elevates safety risks in gas production. The lack of a comprehensive study about water production problems is the primary motivation for this study. Contrary to the serious concern over the standalone investigation of an actual water production case study, less concern is put to deal with the problem comprehensively through an investigation of all potential sources and mechanisms, required methods, and available techniques. This study presents the potential sources of the problem, methods to identify it, and approaches to address it. Firstly, possible sources are described. Secondly, the diagnostic techniques are expressed. Then, practical solutions used in actual cases to overcome problems are elaborated. The solutions include both well- and reservoir-oriented approaches. Finally, all proper strategies are summarized to tackle the water problems in gas fields. The current study comprehensively presents the available methods for water control problems in parallel with conceptual and qualitative comparison. The finding of this study can be very constructive for better understanding of water sources, available diagnostic tools, and solutions for controlling water production in gas reservoirs and, consequently, taking the best decision in real case studies before attempting many water shut-off approaches.

Study For Water Shutoff Using Tandem Through Tubing Bridge Plugs Technique, Case Study

Increasing water production rate is from one of the well knownmain problems that face any oil producer in the world. Although this problem is most happen in old wells, this can also happen in new drilled wells as well. It causes differenteconomic problems for oil produced companies. First, increasing water production affectsproduced wells performance and reduced their production lifetime. The high percentage of the water in the wellbore increasing the hydrostatic pressure (weight of the fluid column) which cause increasing in the lifting power required. which increasingoil and gas production cost per barrel and causing toreduce the drawdown. As an example, if the well is gas lift well, the quantity of gas needs to be injected for lifting the fluid from the wellbore to the surface is increasing with the production of heigh water cut than without producing water. Increasing water cut percentage and Water production also increases the possibility of corrosion, scale and has negative effect on the field equipment starting from the wellbore itself to the surface facilities. Also another serious and important problem is increasing produced water separating cost, treatment, and disposal is a great challenge to oil producers budgets. It costs almost $1.1 billion/year in averageforseparation and disposal of the produced water. Found solution for that type of production help in minimizingcost for the operators and increasing the yearly profit of their operations. Then, water shutoff jobs and operations are very essential. Finally, bythe good understandingfor the formation characterizations and otherfield problems of the field, we can avoid un-necessary water production during the wellbore designing stage.Through tubing bridge plugs (TTBPs) as one of water shut-off (WSO) workovers in the Belayim Fields resulted in average gradualproduction increasing of 2450 bopd.The Average water cut percentage (WC) reduced from 54% to 15%. 87WSOworkoversjobs done since December 1991. Technical evaluation and economical income successful evaluation approaches 90%. Just below 4.5 million dollars companies spent for an average cost of 60,500 dollars per job. Costs spent in less than two days equal to using income from a13 dollars per barrel from crude oil price. Depend on achieved results during the last 4.5 years, these WSO (water shut off)workoversdone in Belyim Field as an effective and on-going cases history for running and set zone water production control. Water production probleminBelayim Field gradually increasing during the last 10 years.Which result indropping inoil production rates.Depend on the reservoir characteristics; lower water zone isolated using through tubing bridge plugs (TTBPs)usingSchlumberegerelectric line units. Dump bailer tools used to put a 14 feet cement cap above the TTBPs to have means of a permanent pressure seal. After 24-hourswaiting on cement time, wells returned back to production with a great change and higher oil rate and very good reduction in Water Cut. Rigless cost for TTBP water shut off workover becomes much less than conventional rig water shut offoperations which result in averaged more than 450,000 dollars per job. Before December 1990,conventional rig operationsWSOwasonly the method used in Belayim Field. now, riglessWSOworkovers becomesa very important for reducing cost or to control cost with financial language.Rigless WSOoperations becomes alsovery important reservoir control tool forincreasing oil production and reducing water production which helps to save reservoir energy.

Mathematical modeling of in-depth gel treatment for water control in a heterogeneous oil reservoir: gel kinetics coupled by flow transport model

ABSSTRACT This paper studies the performance of in-depth gel treatment in a heterogeneous oil reservoir. A two-dimensional numerical model considering the disproportionate permeability reduction mechanism is developed to study the effects of gel on water permeability reduction and water viscosity enhancement. To describe the in situ gel formation, kinetic equation is provided to address polymer-crosslinker reaction. We investigate the impacts of gel treatment on oil and water production rates, water cut and oil recovery in both homogenous and heterogeneous reservoirs. Results reveal a proper water-control in both reservoirs. The presented approach is considered useful in designing gel injection techniques to control water production.

Investigation of Different Scenarios in Simulation of Controlling Water Production in Oil Wells Using Silica Gel Treatments

Excess water production is one of the limiting factors in oil recycling, which reduces production efficiency and leaves a lot of costs. In this paper, water control methods were investigated in order to find the best way to control excess water production. For this propos first, a real model was made using the history match of one of Iran's oil fields that produced excess water because of canalization and different simulation scenarios for gel treatment have been investigated. In the study of more scenarios, comparing the water production in the early times and later injecting the gel, the percentage of water production for injection in the early times has been further reduced. When the gel is injected for a fixed period of 6 months in the production and injection wells The best results for lowering the rate of production water are obtained when the gel is injected simultaneously into the injection and production well, which reduces the water production rate by 12,000 barrels, and the best oil production efficiency for when simultaneous injection is performed in the production and injection well. The best treatment method is injection of high concentration gel in the early stages of water production and it's better to inject gel in deeper wells.

An efficient design for a downhole water loop to control water production from oil wells

This work presents an effective design of downhole water loop (DWL) based on a case study from literature. At the beginning, a comparative study of conventional production and DWL is performed to s...