Повышение эффективности использования ресурсной базы жидких углеводородов в юрских отложениях Западной Сибири

Given the problems of multiple natural microfractures developed in Chang 6 reservoir of Huaqing oilfield in Ordos Basin, the injected water flows along with the natural fractures during water injection development, resulting in low water drive recovery. The concept of volume fracturing is introduced into water injection well fracturing, and the technical idea of reconstructing the seepage field through volume fracturing of water injection well is proposed to improve the water flooding effect. On the basis of previous studies, firstly, the development of fractures and the rock mechanical properties of reservoirs are studied, and then the expansion law of volumetric fracturing fractures in the study area is analyzed. Combined with numerical simulation research, the feasibility of improving water drive by volumetric fracturing in water injection wells is demonstrated. Based on the above research, field tests of three well groups are carried out. The test shows that the volume fracturing of water injection wells can form a fracture zone along the direction of the maximum principal stress (with an average bandwidth of 56 meters), and then change the original dominant direction of water drive to realize the effective matching between fractures and injection production well pattern; the row spacing is reduced, and the effect of waterflooding is improved obviously. After the test, the average daily oil production of a single well increased from 0.6 tons to 1.0 tons, the water cut decreased from 74.6% to 42.0%. The oil recovery rate increased from 0.44% to 0.77%. The recovery increased by 5-8%.

A dynamic scale location monitor method to predict oilfield blockage during water flooding

Based on the development of the offshore water drive reservoir, the determination of reasonable water injection of monolayer and single well affects the distribution of remaining oil and development effect of oil field water flooding, so this paper, using the grey correlation analysis method, studies the main factors influencing the dividing coefficient of water-injection and weight. This method takes into account the effective thickness, permeability, injection-production well spacing, the number of injection-production wells, and the direction of formation coefficient factors such as the influence of the dividing coefficient for injection. The formula for water-injection multi-factor controlled is established, at the same time, applying water injection formula of this article and the conventional on injection allocation of A-platform offshore injection wells. And the difference of single-well injection-allocation quantity in layers is analyzed. Based on a platform offshore, layers exist in the process of water flooding and the problems such as the contradiction between the layers, put forward the necessity of layered water injection through this article to determine water injection formula and injection allocation on a platform of injection wells by implementing effect which can be found. A platform for water flooding development of water cut under control, natural decline rate reduced to verify the reliability and practicability of the formula to determine injection in this paper. It has certain guiding significance to the offshore for the water-injection development oilfield.

Effective reservoir management is critical to the success of water flood developments. Continuous monitoring of downhole parameters such as pressure, temperature and flow profile in water injector wells is vital in order to optimize the water-flood sweep efficiency and to avoid early water breakthrough in nearby oil producer wells. The target field has three stacked tight carbonate reservoirs with low reservoir energy and as such is being developed with water injection scheme from day one. As such, effective monitoring of downhole injection parameters is important from an early stage. A common industry practice to monitor these parameters is to install Permanent Downhole Gauge (PDHG) and Distributed Temperature Sensing (DTS) system. Recently, a new smart Hybrid Technology has been developed to measure the downhole data at surface. This paper describes the successful application of this hybrid technology in a green onshore oil field development. Details are presented about the well bore segmentation design of the DTS system, the hybrid cable installation and the operational challenges with the hookup to the wellhead control system. The paper also presents the data acquired during commissioning job, and interpretation of the temperature data which was used to generate the injection profile along the wellbore. Finally, a strategy for future implementation of the DTS system is discussed. Overall, this technology showcases the application of the smart hybrid completion for real-time monitoring of the water injection profile, including the pressure and rates along with injection volume per segment in the horizontal section. Real-time data from the hybrid technology has been integrated to digital oil field implementation to enhance the real time decision making to optimize the injection rates and to allow the operator to implement the decisions without any delay. This technology optimized the cables requirement and maximized the utilization of cable for multi-application environment to support acquiring Pressure, DTS and DAS data to generate real time injection profile.

Application of cumulative-in-situ-injection-production technology to supplement hydrocarbon recovery among fractured tight oil reservoirs: A case study in Changqing Oilfield, China

Due to the lack of knowledge on the influence law of the temperature profile of layered water injection wells, it is still highly challenging to quantitatively diagnose the water injection profile of layered water injection wells using distributed optical fiber temperature sensing (DTS). In this paper, a temperature profile prediction model for layered water injection wells has been developed by considering the micro-thermal effect and non-isothermal reservoir seepage. The influence of various single-factor changes on the temperature profile of layered water injection wells is simulated and analyzed. Orthogonal experiment analysis results demonstrate that the sensitivity of different factors on wellbore temperature from strong to weak is the injection temperature of the water, injection time, water injection rate, wellbore diameter, formation thermal conductivity, wellbore trajectory, and the permeability of injection formations (Tinj＞t＞Qinj＞D＞Kt＞θ＞k). The injection temperature of water, injection time, and water injection rate are the dominant factors affecting the temperature profile of water injection wells. The results of this paper provide a theoretical foundation for the accurate evaluation of the water injection profile and water injection scheme optimization for the layered water injection wells.

The use of a simple data correction procedure which involves the adjustment of bottom-hole flowing pressure prior to a Pressure Fall-Off (PFO) test has been illustrated. The procedure has proved very effective for cases where the early time pressure data are marked by well bore secondary skin effects, which are commonly seen in high capacity water injection wells. The results of field cases considered, including those that may otherwise be considered as normal tests, showed that it is good Engineering practice to routinely apply the new procedure for all PFO tests in water injection wells. Introduction Pressure response profiles observable during PFO tests of water injection wells are sometimes very peculiar, offering no direct clues as to the predominant well bore phenomenon at early test times. This is more so for wells with limited perforations subjected to very high water injection rates. The pressure profiles of PFO tests on these wells are characterized by a substantial separation between the Pressure and the Pressure Derivative curves on the diagnostic (Log-Log) plots. Also the short time pressure response profiles are usually not amenable to analyses using established techniques for the flow regimes observable at short times. The long time pressure and derivative profiles are more descriptive. In view of the fact that PFO tests of water injection wells are of limited application in evaluating permeability of a given reservoir, it would appear that, in dealing with PFO tests of water injection wells, the emphasis should be on Interpretation with a view to understanding the fluid flow phenomenon at the near well bore region, and the reservoir rather than dwelling too heavily on routine analysis for reservoir parameters. We are therefore concerned with down-hole flow and static phenomena and their possible effects on reservoir dynamics involving such reservoir properties as average pressure and skin factors. In the circumstance, it is important that the short time pressure data be left unencumbered as much as possible so that all possible flow regimes can be evaluated without undue error. PFO in Water Injection Wells In order to meaningfully design or interpret a PFO test in a water injection well, it is important to understand, the factors governing the dynamics of this kind of test. We consider an injector at the center of a five-spot pattern. In its simplest form, we can assume that the water front moves radially outwards pushing the oil ahead of it. If we further assume that there is no interference between the injector and the producers within the pattern, we can in general expect to have three distinct zones within the drainage radius of the injector. These zones are made up of the following:A water swept region around the well bore where only water is flowing: designated as the water bank.An Oil/Water transition zone immediately ahead of the water bank where both oil and water are flowing.A virgin reservoir region of unswept oil where only oil is flowing designated as the oil bank.

Fresh-saline water dynamics in coastal aquifers: Sand tank experiments with MAR-wells injecting at intermittent regimes

Water flooding has been widely used as secondary oil recovery method in the clastic reservoirs in PDO. Field development plan of this field requires water injection under matrix injection conditions. The field consists of stacked Gharif sand stone reservoirs with variable degree of depletion. Increased injection volumes at economical rate, could induce hydraulic fracturing where it is very important to manage fracture growth and reducing risk for out of zone injection. The success of water flood development depends on an optimal injection pressure, which requires knowledge of formation fracture pressures and geomechanical rock properties. Efficient geomechanical analysis and workflow integrating data from well tests, field performance, water injection history and monitoring data was implemented for this study to provide guidance on optimum water injection pressure. Field stress tests, such as Leak off Tests (LOT) and micro fracs were analyzed to derive the fracture pressures. Gharif formation in these stacked reservoir formations have been significantly depleted hence a reduction in fracture pressure was required to be assessed. Depletion stress path coefficient, which is the ratio of change of fracture pressure and reservoir depletion, was derived based on historic field data. Data from well tests, field water injection performance was used for Modified Hall plot analysis and other diagnostic plots to provide better insight on active water injection operating conditions (fracture, matrix and plugging). Finally, for injector operating above the fracture pressure, Produced Water Re-Injection (PWRI) model was used to simulate expected fracture dimensions, and quantify the out of zone injection risk. Results of this study indicate that the decrease in fracture pressure in Gharif formations is about 60% of the change in pore pressure (depletion). Qualitative and quantitative analyses were able to characterize the operating injection conditions (matrix vs. fractured) for active injectors. Interpreted fracture pressure from Gharif water injector diagnostic plots demonstrates good alignment with the measured fracture pressure from field tests. The results reveal that most of the water injector wells, particularly in the depleted formations are operating above fracturing pressure. Predicted fracture dimensions form the PWRI model calibrates well with the field monitoring data. Outcome of this study provided fracture pressure estimate for Gharif formation with depletion and provide guidance on optimum water injection pressure to improve waterflood management. Stress path chart provide continuous improvement and quick decision for water flood operation. Results quantified the induced fracturing to mitigate the risk of out of zone injection and/or loss of sweep efficiency. Additionally, the results provide continuous critical input for fracture gradient for drilling and cement design for wells through depleted stacked reservoirs in other field within Gharif formation.

Hydrate blockage has been a problem in Campos Basin subsea producer wells for a long time. Although hydrate formation was not expected in sea water injection wells there were some occurrences in Campos Basin. The formation of hydrate requires the presence of water and gas at low temperature and high pressure condition. As the subsea sea water injection wells always present water at low temperature and high pressure, the missing link to form hydrate is gas. Thus, to explain the occurrence of hydrate blockage in these wells one has to explain how and when gas enters into the well. A study was carried out to determine the causes of gas inflow into the injection strings and to make recommendations on the proper procedures and equipments to avoid hydrate blockage. The literature survey and the Campos Basin occurrences showed initially that gas segregation, water hammer effects and crossflow were the most probable causes for gas inflow during injection plant shutdowns or long time waiting for injection. The crossflow was ignored because the formations are homogeneous in all the cases. The water hammer effects were analyzed with a numerical simulator developed in the study. The final analyses revealed that gas segregation was the cause of hydrate blockage in the water injection wells studied. Other relevant conclusions are that down hole valves, such as deep subsurface safety valves and backflow valves are useless to prevent gas inflow and that water hammer effects can be managed in the sea water injection plant. This paper presents recommendations for water injection wells startups, regarding hydrate prevention, which can be useful for any subsea water injection project.

A new technique is presented which aids in maximizing water injection rates in wells recently converted to injection, thereby accelerating offset oil production response. This method is applicable to waterflood operations where injection wells are surface pressure controlled and where bottom-hole injection just below formation parting pressure (FPP) is desired. Two plotting methods are shown to be instrumental in monitoring the acceleration of fill-up and average reservoir pressure growth in an actual field case. One is the Hall method1: plotting a function of bottom-hole injection pressure versus cumulative water injection, and the other was Introduced by Hearn2: plotting the inverse injec-tivity index versus cumulative water injection. After initiating injection into several converted wells at pressure limits well below the average offset parting pressures, periodic surface pressure increases were made at each well over a period of several months. Monitoring the Hall and Hearn plots as the pressure and rates increased rendered qualitative interpretations of whether the rates were being maintained below FPP. Accelerated reservoir pressure growth was achieved which resulted in earlier than expected offset oil response. Application of these plots also reduce, and sometimes eliminate, the need to perform periodic step-rate tests designed to determine FPP during the injection start-up period, thereby significantly reducing operating costs.

High temperature may adversely affect municipal solid waste (MSW) biodegradation and lead to an increase in the deformation of high-density polyethylene (HDPE) pipes used for the collection of leachate and landfill gas in landfills. The test in this study was to change the waste temperature around the vertical injection well by water injection using a vertical well. The test was conducted intermittently with two different flowrates in a newly filled MSW layer of a landfill. The temperature, gas pressure and leachate level in the test area were simultaneously monitored during this study. The results showed that the waste temperature around the vertical injection well was effectively changed by water injection, which did not result in a significant rise in the leachate level. During water injection, the waste temperature influence distance in the horizontal direction increased with depth from the leachate level to the bottom of the injection well. The bottom temperature of the injection well decreased to near the water-injection temperature. The range of influence of the waste temperature caused by intermittent water injections slightly increased in this test. After water injection was stopped, the waste temperature near the vertical injection well increased quickly initially, and then the increments became more gradual with time. When the leachate level recovered stably, there was still a temperature gradient around the injection well within the range of influence. The temperature and gas pressure in the waste above the leachate level and far away from the injection well were slightly influenced by water injection.

The matrix acidization operation has been extensively associated with unconformity. The challenge remains to distribute the acid treatment fairly along the wellbore. It has been observed that acid prefers the less resistance spots along the wellbore which are characterized by high permeability streaks / fractures. During the operation, the injection to these areas is highest which further increases its permeability whereas low permeability zones never receive the similar treatment and are left out with lower permeability. To counter this challenge, an approach of utilizing an advance completion consisting of Autonomous Outflow Control Device's (AOCD) was implemented. Although there are multiple case histories of successful installation of AOCD in water injection wells for conformance, the high rate of stimulation operation poses a major challenge. This study involves developing a methodology to ascertain that a similar performance of acid stimulation can be achieved with much lower rates through optimization. This will be possible by conforming stimulation fluids through the wellbore, allowing operation to be executed at lower rates than Open hole or standard completion. The solution will also provide cost effectiveness as a much less volume of fluids will be required to produce better performance as compared to non-optimized completion. The study also involved upgrading a stimulation software to convert it into a fit for purpose platform which will incorporate the operational envelope of AOCD. The AOCD is a rate-controlled device. At the heart of the device is a spring-based mechanism that reacts to the pressure drop/flow rate across the nozzle. Once a predefined upper flow-rate limit is reached at a zone, the valve autonomously closes. This eliminates the impact of the thief zone on acid injection conformance and maintains a prescribed acid distribution. The technology is proven in water or polymer injection wells; this study highlights the value addition that AOCD can bring to matrix stimulation operations; further presenting AOCD as a fit for purpose solution for injection wells irrespective of the injection type or application. A novel approach is developed through modelling to display that Autonomous Flow Control Devices can provide substantial value in stimulation operations. This will enable the operators to minimize the impacts of heterogeneity on the acid conformance and the completion system will autonomously respond to a dynamic change in reservoir properties, specifically the growth of wormholes.

In a multilayer heterogeneous oil reservoir developed and exploited by water flooding, most of the remanant oil is distributed in the unflushed part of the developed reservoir. Improvement of the conformance factor and the displacement efficiency should be the main EOR technique. Profile modification in an injection well is an effective technique in the improvement of the volumetric sweep efficiency of the water flooding. This paper gives a summary of the application of the profile modification technique in the injection wells in Chinese oil fields and its further development. Some examples on the effectiveness of this technique are presented and analyzed.

In this study, deformation curves and induced stress changes around injection wells, before and after the water flooding process, have been investigated in the Asmari carbonate reservoirs of the Ahvaz oil field, located in the southwest of Iran. To achieve this, two types of tests were conducted on six carbonate core samples from the reservoir: (1) flooding device test and (2) triaxial compressive test. The results of these experiments revealed that Mohr’s circles, deformation curves, and induced stresses around the injection well were affected by the water flooding process. By utilizing flooding devices and triaxial testing, as well as intergating their results, changes in parameters, geomechanical coefficients, and Mohr’s circles were analyzed for all six carbonate core samples. The analysis was based on the Hooke-Brown and Mohr-Coulomb failure criteria under both natural production conditions and during production. In the current study, a novel and sequential approach was employed to integrate data collected before and after the water flooding process, including full set log data, results from water flooding and triaxial tests, and the experimental data from water flooding operations in the carbonate reservoir of the Ahvaz field. Using MATLAB software, the induced stresses around the injection well were simulated and analyzed through three-dimensional diagrams. The findings demonstrated that after water flooding and the associated pressure increase, the induced stresses around the injection well—namely vertical, radial, and tangential stresses—undergo significant alterations. Before the water flooding process, the maximum stresses for the three carbonate core samples were approximately 68, 91, and 107 MPa, respectively. Following the water flooding process, these values increased to approximately 94, 118, and 142 MPa, respectively. The results reveal that, following the water flooding process, the minimum stress remains unchanged while the maximum stress increases. Consequentially, Mohr’s circle becomes larger compared to the initial state.