Water-drive Reservoirs Research Articles

A novel method to identify preferential flow paths by considering the time-varying effect of petrophysical parameters in ultra-high water-cut reservoirs

The continental clastic reservoirs mainly distributed in the eastern region of China are regarded as the “ballast stone” for ensuring national energy security. After long-term waterflooding, reservoir petrophysical parameters have changed drastically. When the ultra-high water-cut period is achieved, the preferential flow paths are widely distributed inside the reservoir, resulting in severe ineffective water circulation and high difficulty in inhibiting water cut rise and stabilizing oil production. Due to the slow calculation speed and low identification accuracy of the existing methods, it is crucial to propose a novel method to identify preferential flow paths by considering the time-varying impact of petrophysical parameters in ultra-high water-cut reservoirs. To tackle this issue, massive dynamic and static data are collected from typical water-drive reservoirs in the Daqing oilfield to analyze the dynamic characteristics of preferential flow wells and the time-variation laws of reservoir parameters. A rapid evaluation index system for preferential flow paths is thereafter established. By describing the time-variation of reservoir permeability and fluid apparent viscosity and introducing a dynamic flow resistance coefficient to infer the inter-well or inter-layer connectivity, a novel method with the time-varying effect of petrophysical parameters considered is developed to quickly identify preferential flow paths in ultra-high water-cut reservoirs. A critical criterion of preferential flow paths is further constructed. Finally, the proposed method is used to determine the spatial distribution of preferential flow paths in a typical block of the Daqing oilfield. Results demonstrate that, once a preferential flow path is formed, some distinct dynamic characteristics of injectors and producers will be exhibited. Based on the estimated dynamic flow resistance coefficient, the preferential flow paths are further classified into four types: non-preferential, primary preferential, intermediate preferential, and strong preferential flow paths. Using the proposed method, the identification accuracy of preferential flow paths exceeds 95%, and the identification speed is more than 10 times faster than the traditional methods.

Diagnostics of gas-dynamic connection between gas caps and their influence on the product composition of the North Caspian production wells as per tracer tests

Diagnostics of gas-dynamic connection between gas caps and their influence on the product composition of the North Caspian production wells as per tracer tests

Investigation on the mechanism of heating effect influencing emulsifying ability of crude oil: Experimental and molecular dynamics simulation

Water flooding can create a transient heating effect that causes oil and water to self-emulsify. This study sought to understand how this effect impacts crude oil's emulsifying properties by conducting oil-water emulsification experiments and investigating the effects of initial temperature, heating rate, and effective time. Additionally, asphaltene dispersion, adsorption behavior, and viscoelasticity of crude oil and its interfacial components were analyzed to unravel the mechanism behind the heating effect on crude oil's emulsifying capacity. The heating effect was observed to suppress interaction force dissipation between asphaltene molecules effectively from low to high temperatures. This increased both the interfacial film thickness and steric hindrance, improving crude oil's emulsifying ability. However, at high temperatures, the interfacial film became unstable, which led to the normalization of crude oil's emulsifying ability after the effective time. These findings provide insight into the emulsifying mechanisms of water-drive reservoirs and the in-situ emulsifying theory of underground crude oil.

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.

Field Validation of a Non-logging Alternative Method for the Prediction of the Location of Water-Cresting in Horizontal Wells for Water-Drive Reservoirs.

A previously reported method for a non-logging alternative method for the prediction of the location of water-cresting in horizontal wells for water-drive reservoirs is validated in a field test for the first time in this study. Using this method, the wellbore trajectory, variation in the reservoir permeability, and the pressure gradient data were used to calculate what is called the breakthrough coefficient for the different segments along the length of a set horizontal well with the largest calculated breakthrough coefficient corresponding to the most likely location of the actual water-cresting occurrence. This method was field-validated and found to be in good agreement with log testing for a group of seven wells in an oilfield in Northern China. Another calculated parameter derived from the breakthrough coefficient which is called the variation of the breakthrough coefficients that characterize the effect of the variation of water production along the length of the horizontal well due to the effect of the variation of the wellbore trajectory, permeability, and pressure gradient on the oil production is also introduced. This field validation found variation of the breakthrough coefficients to be weakly and inversely correlated to the oil production in application to a group of 27 wells in the same field.

Hydrodynamic model application to create a reverse oil cone in water-oil zones

For the conditions of the development of bottom water-drive reservoirs in terrigenous deposits with low permeability of oil-saturated rocks in the dome of the formation, we propose a technology of reverse oil cone creating for effective residual oil reserves development. To visualize the oil recovery process, we created a hydrodynamic model, which makes it possible to increase the efficiency of the proposed technology, as well as to regulate the technology parameters. We considered the issues of the following models creating: the water cone formation during the near-roof part of the formation perforation; the a cone of oil formation in the process of water withdrawing from reservoirs with cutoff water saturation; erosion of the oil cone during its production from the interlayers with the highest oil saturation. The parameters influencing the efficiency of proposed reverse cone technology application are determined.

Absolute open flow (AOF) potential evaluation for watered-out gas wells in water-drive gas reservoir

This paper presents a gas-water two-phaseLaminar-Inertial-Turbulent (LIT) flow equation for watered-out gas wells, which can be solved through the incorporation of daily production, gas-water relative permeability and PVT data, and then Q AOF and formation factor (Kh) are obtained. Field case study in Long Wang Miao (LWM) water-drive gas reservoir shows that for watered-out gas wells, the single-phase LIT equation can result in overestimation of Q AOF by 30–80%. Water invasion performance can be relieved after reducing the production rate of watered-out gas wells, and water invasion behavior before breakthrough can be diagnosed with the decline trend of Kh values.

Natural Dumpflood in Malaysia Succeeds as Low-Cost Offshore Oil-Recovery Method

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 196498, “First Natural Dumpflood in Malaysia: A Successful Breakthrough for Maximizing Oil Recovery in an Offshore Environment With Low-Cost Secondary Recovery,” by Muhammad Abdulhadi, SPE, Toan Van Tran, SPE, and Najmi Mansor, Dialog Group, et al., prepared for the 2019 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 29–31 October. The paper has not been peer reviewed. The complete paper describes the first successful implementation of natural dumpflooding offshore Malaysia as a case study to provide insight into the value of using the approach to maximize oil recovery in a mature field, particularly in a low-margin business climate. Background Field B, located offshore Balingian province approximately 80 km northwest of Bintulu, has a water depth of 90 ft and is highly compartmentalized and faulted, with almost 100 faults present. The field features three subfields further divided into nine major fault compartments. Eight primary reservoirs exist, with more than 20 subreservoirs stacked atop one another with multiple drive mechanisms, including water drive, gas-cap drive, and solution gas drive. Several of these subreservoirs are thick sands between which communication exists through juxtapositions, shared gas caps, or aquifer. Other subreservoirs are isolated by thin layers of shale apparent in certain wells but absent in others. The high complexity of Field B requires any opportunity identified to be thoroughly evaluated and examined before execution. Field B is a moderately sized field discovered in 1976, with production commencing in 1984. During the 30 years of oil production, the field peaked at 30,000 B/D in 1990 and dipped to 3,000 B/D in late 1999. The facilities consist of four drilling platforms, a processing platform, and a compressor platform. A total of 48 wells were drilled in the field, with most wells completed as dual-string producers. The recovery factor (RF) of the reservoirs ranges from 10% for solution gas drive to 50% for strong water drive. The behaviors of these reservoirs are starkly different. The solution gas-drive reservoirs have poor-quality sand (less than 200 md), a low productivity index, limited sand thickness (less than 30 ft), limited sand connectivity, and sharp pressure decline after 2 to 3 years of production. The water-drive reservoirs, however, have good-quality sand (up to 5,000 md), a high productivity index, thick sand (greater than 40 ft), extensive sand connectivity, and limited pressure decline. The stark differences in the reservoirs’ behavior further complicate field management. The field currently is in late life, with recovery to date of 19% with an RF of 23%. Most of the water-drive reservoirs are already swept up to the crest, while the solution gas-drive reservoirs are depleted nearly to abandonment pressure. After 30 years of production, the total field water cut was at 80%, while oil production was approximately 5,000 B/D, signifying the diminishing economic life of the field.

Method of Predicting the Location of Water Cresting for Horizontal Wells in a Water-Drive Reservoir for Early Prevention

A method of prediction of location of water cresting and characterizing its intensity in a horizontal well in a water-drive reservoir is introduced for the first time. A mechanistic model for water cresting derived from Darcy’s equation incorporating the main parameters reported in the literature affecting water cresting—viscosity, well distance to the aquifer, wellbore pressure gradient, and reservoir heterogeneity—is introduced with two new characterizing parameters. First is a model-derived parameter, called the breakthrough coefficient, which is defined as the ratio of the average time of breakthrough to the time of breakthrough for a segment of the well, with the model-predicted location of water cresting corresponding to the well segment with the largest breakthrough coefficient. The second is the Cresting index, which is the ratio of the maximum breakthrough coefficient to the minimum breakthrough coefficient as a characterizing parameter, with a well with a higher cresting index corresponding to a faster breakthrough in a group of similar wells. This methodology was validated through a series of sophisticated experimental corefloods and found to predict 78% of the location of the water cresting accurately. The cresting index is found to be weakly correlated with the speed of breakthrough among similar wells.

Production of reserves of oil- water zones of low-viscosity oil deposits

The authors state that during the production there is the process of transition of deposits to the category of bottom water-drive reservoirs due to frontal displacement by the injected water. As a result, the nature of water flooding becomes similar to the primary areas of bottom water-drive reservoirs. It is shown that for water-drive areas, the development is characterized by unfavorably high input values of water flooding and its intensive growth in the range of oil recovery factor from 0.1 to 0.3 fractions of units. The nature of the displacement curves of areas with water-oil zones (WOZ) is identical and differs only by the amount of water flooding of oil reserves in a deposit or area, which allows drawing a conclusion about a similar mechanism of oil displacement, which is characteristic of oil reservoir. It is shown that the main feature that characterizes the development of areas and deposits with water-oil zones is the increase in water flooding at the first stage of production.

A New Method for Plane Equilibrium Injection-production Adjustment of Water-drive Reservoir

In view of the lack of theoretical research on plane equilibrium injection-production adjustment in water drive reservoir, the production prediction method under the condition of variable pressure difference of production well is deduced according to Buckley Leverett non-piston displacement theory. Taking the same degree of extraction as the goal, the adjustment method of plane equilibrium injection-production per unit time is put forward. The evaluation coefficient of the optimal equilibrium injection-production scheme is defined, which can guide the optimization of the equilibrium injection-production scheme. Through theoretical model analysis, it is considered that the adjustment method of plane equilibrium injection-production is reasonable and reliable. Seven kinds of adjustment schemes are designed for BZ oilfield in Bohai Sea. Of equilibrium displacement time. When the equilibrium displacement time is more than 10 years, the increment of recovery degree slows down to about 1.8%. Equilibrium injection-production adjustment was carried out for 1195 sand body in BZ oilfield. The sand body increased oil by 25m3/d per day, and the natural decline rate decreased by 1.1%.

Proper Orthogonal Decomposition-Based Method for Predicting Flow and Heat Transfer of Oil and Water in Reservoir.

Calculation process of some reservoir engineering problems involves several passes of full-order numerical reservoir simulations, and this makes it a time-consuming process. In this study, a fast method based on proper orthogonal decomposition (POD) was developed to predict flow and heat transfer of oil and water in a reservoir. The reduced order model for flow and heat transfer of oil and water in the hot water-drive reservoir was generated. Then, POD was used to extract a reduced set of POD basis functions from a series of "snapshots" obtained by a finite difference method (FDM), and these POD basis functions most efficiently represent the dynamic characteristics of the original physical system. After injection and production parameters are changed constantly, the POD basis functions combined with the reduced order model were used to predict the new physical fields. The POD-based method was approved on a two-dimensional hot water-drive reservoir model. For the example of this paper, compared with FDM, the prediction error of water saturation and temperature fields were less than 1.3% and 1.5%, respectively; what is more, it was quite fast, where the increase in calculation speed was more than 70 times.

A coupling model of water breakthrough time for a multilateral horizontal well in a bottom water-drive reservoir

A series of complex production wells have been applied in challenging reservoirs to maximize oil recovery. Multilateral horizontal well has received plentiful attentions in recent years. The multilateral horizontal well technology is especially beneficial in expanding formation drainage area, reducing water cresting and coning, increasing productivity, and postponing water breakthrough time in bottom water reservoir. Since Muskat and Wyckoff introduced the concept of water coning into petroleum engineering field, different models have been proposed to forecast the critical rate and water breakthrough time for vertical and horizontal wells. However, the studies of water breakthrough time for complex structured multilateral horizontal wells have rarely been reported. This paper proposes a new coupling model for estimating the water breakthrough time of complex structured multilateral horizontal wells. The proposed model took multiple factors into account, including the wellbore 3D structure, wellbore vertical location, and reservoir and fluids properties. In addition, a field case study was conducted by utilizing the methods that were proposed in this paper. The practical production data was compared with the results obtained from the analytical model, and this coupling model shows an excellent agreement with the results from the actual scenarios. The proposed methods in this paper can be utilized to forecast the water breakthrough time and breakthrough locations of multilateral wells in bottom water reservoirs.

Inverted-ESP Completion Boosts Oil Rate While Disposing of Produced Water

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 187624, “Subsurface Disposal of Produced Water and Simultaneous Increased Oil Production Achieved Within the Same Wellbore Using Inverted ESP—North Kuwait Case Study,” by Shamseldin Z. Elaila, Elred Anthony, Nora H. Al Maqsseed, Mohammad K. Al-Banai, and Sara N. Al-Mutairi, KOC, prepared for the 2017 SPE Kuwait Oil and Gas Show and Conference, Kuwait City, Kuwait, 15–18 October. The paper has not been peer reviewed. This paper aims to provide an introduction to the early management of downhole produced water in strong waterdrive reservoirs using inverted electrical-submersible-pump (ESP) technology. This technology facilitates a method of downhole water disposal within the same wellbore and, therefore, reduces the costs associated with bringing water to the surface or subsurface for treatment. The technique also saves the costs needed for drilling disposal wells. Problems Associated With Produced Water Water produced with petroleum is growing in importance from an industrial and environmental standpoint. In the past, this water was considered to be waste and required disposal. Early on, little attention was paid to the fate of the produced water in the environment. Later, it became clear that possible contamination from produced-water disposal, especially on the surface, needed to be considered. This unwanted water is also a limiting factor in the productive life of the well. Many factors influence the drive for improved water control—loss of hydrocarbon production, environmental effect of disposal, government regulations, and public opinion. The environmental issues and costs related to produced water and its disposal are becoming major considerations for producers. The economic factors of reducing water production far outweigh the cost of typical water-control treatments. Historically, water-control treatments have often failed because of one or more of the following problems: the source of the problem was not properly identified, the wrong treatment was carried out, or the correct treatment was performed improperly. For disposal or injection into reservoir rocks, this water must be processed and treated through a series of time-intensive and costly operations. Suspended solids and oil must be removed to an appropriate degree to reduce oil losses and prevent plugging of the disposal formation. Also, increasingly stringent regulations on the entrained and dissolved oil and other chemicals in the produced water must be met. Economics of Produced Water Except in the case of gas production from coal seams, water-production rates usually start slowly from the initial development of a property. Facility designers may forestall construction and installation of water-handling equipment deliberately at the beginning of a project to reduce initial capital costs. The eventual appearance of water production requires the addition of capital investment and operational expense to handle the growing water rates, which do not generate revenue to offset the cost. The natural tendency for companies is to minimize the immediate expense; as a result, companies often underdesign the equipment or fail to budget properly for operational expenses.

налитическая методика оценки эффективности технологии отбора прикровельной нефти из водоплавающих залежей, верифицированная на гидродинамической модели

налитическая методика оценки эффективности технологии отбора прикровельной нефти из водоплавающих залежей, верифицированная на гидродинамической модели

Systematic Evaluation Method of Water Aquifer Energy for Water-Drive Gas Reservoir

On the basis of present relevant research about water aquifer energy for water-drive gas reservoir, systematic evaluation method of water aquifer energy for water-drive gas reservoir is constructed from water invasion recognition, water aquifer size calculation, water influx volume calculation, water aquifer active degree evaluation and drive energy composition analysis. According to static and dynamic data of an actual typical water-drive gas reservoir, water aquifer energy was evaluated systematically. Research results indicated that this method can evaluate water aquifer energy of water-drive gas reservoir quickly and systematically, which can offer reference to development performance forecast and development adjustment of this kind of gas reservoir, and realize reasonable and effective development of this kind of gas reservoir.

Impact of parameters׳ time variation on waterflooding reservoir performance

Currently, most oil reservoirs are in high water cut stage due to long term waterflooding, especially for those water-drive naturally fractured formations. Long term waterflooding changes the microscopic pore structure, rock skeleton, and clay minerals of these reservoirs through complex physical and chemical reactions during the process, and causes reservoir and fluid parameters changing over time. Our experimental data show that rock permeability, wettability, and oil viscosity are time-variant parameters during waterflooding, and they are closely related to the continuous water flow through the porous media, which is important to characterize water-drive reservoirs and understand fluid flow in them. In this paper, experimental statistic data from cores of Shengli oilfield, China were utilized. Firstly, the relationship between permeability/wettability/oil viscosity and the ratio of flow-through water volume to pore volume were presented. Secondly, the ratio of grid flow-through water volume to pore volume, denoted as Rwpv, was used to describe the parameter time-variation mechanism. Finally, a numerical simulation software package was developed by introducing Rwpv into the traditional black oil model to characterize the time-variation mechanism in water-drive reservoirs. The new simulator was verified through comparing with commercial reservoir simulator ECLIPSE and experimental data. Simulation results show that the time-variation of permeability and oil viscosity decreases the ultimate recovery compared to the cases without considering time-variation effects; and wettability time-variation makes the reservoir rock more water-wet, which leads to higher ultimate recovery. This research found that both time-variation effects affect the ultimate oil recovery, but in different ways; and time-variation impact becomes increasingly significant as the waterflooding process becomes longer. Both the experimental results and numerical simulations significantly improve the interpretation of the parameters׳ time variation mechanisms and effect on waterflooding.

Well Placement, Infrastructure Design, Facility Allocation, and Production Planning in Multireservoir Oil Fields with Surface Facility Networks

Managing oil fields with multiple reservoirs and shared surface networks optimally is a challenging practical problem. The majority of studies on optimal well placement have focused on either the interactions within the surface network facilities or the dynamic states of the subsurface environment. This work holistically integrates both surface and subsurface sections and addresses well placement, surface network design and allocation, and production/injection planning in a field with multiple irregular-shaped reservoirs. We consider the dynamic, economic, and operational interdependencies of the reservoirs, shared surface network, and common oil market through a complex, nonconvex, and deterministic mixed integer nonlinear programming model. Our approach determines the optimal number and locations of wells, design or retrofit of surface network, connections/allocations of wells with surface facilities, and optimal injection/production planning in water-drive reservoirs. We illustrate the complex interplay of well operations and throughputs using a literature example.

Research on a Computational Method for Reservoir Pressure of a Water-Drive Condensate Gas Reservoir

Reservoir pressure of condensate gas reservoir is an indispensable parameter for calculation of gas reserves, gas well productivity evaluation, dynamic analysis, and evaluation of anticondensate. The water-drive condensate gas reservoir is ranked among the most complex types during development. In the development process, reservoir pressure declines, condensate oil dropouts, and content of water vapor in condensate gas increases, while edge water invades continuously, thus accurate calculation and prediction of reservoir pressure is particularly difficult and important. Calculation of retrograde gas condensate influenced by porous media adsorption and capillary pressure, and water vapor content in condensate gas tested under different pressure, according to material balance principle, material balance equation of water-drive condensate gas reservoir is established by consideration of absorption in porous media, capillary pressure and water vapor as well, and finally reservoir pressure at any time during production could be computed by iteration. Case study shows that the reservoir pressure calculated by this method gets much closer to actual reservoir pressure and it finally shrinks the workload in field testing and brings more convenience to scientific research and production management.

The Effect of Temperature, Pressure, and Mixing Ratio of Injection Water with Formation Water on Barium Sulfate Scale Formation in Siri Oilfield

Enhanced oil recovery methods are used to recover the percents of oil that are not naturally recoverable from reservoirs. Water injection as a secondary recovery is used to maintain the pressure in water-drive reservoirs. An important point for having a successful injection is the compatibility of injection and formation waters. OLI ScaleChem software predicts mineral scaling potentials of 54 solids for virtually any oil and gas well and processing facility in the world. There are several advantages over other commercially available scaling software: (1) By including all brines in the calculations, the well and processing facility are modeled more accurately; (2) Scaling potential and scale buildup are reported at each calculation point; (3) Automatic correction of pH and charge balance, therefore the chance of unexpected problems from bad water analyses decreases. Also, more effective treatment can be made; (4) Automatical removal of organic acid concentrations from the measured alkalinity, therefore producing a true brine alkalinity; (5) Accurately predict the behavior of any mixture of chemicals in water and mixed solvent. This article presents the predicting of barium sulfate scale tendency of formation water, injection water, and mixing of injection water with formation water at different conditions. The experimentally measured chemical analyses of formation water and injection water were used by OLI ScaleChem software to determine the tendency of scale formation at different conditions. As pressure and temperature were increased, the scaling tendency of the barium sulfate scaling brine was found to decrease, as was predicted by OLI ScaleChem software.