Analysis of Fluid Input Wells by Shut-In Pressures

Fundamental understanding and application of process parameters in numerical simulation that leads to optimized gravity drainage oil recovery at field scale is still a major challenge. Reservoir simulations studying the effects of well patterns and type of gas injection wells have not been reported so far. In first ever attempt, the mechanistic benefits of production strategy on gravity drainage oil recovery are identified in this paper. Effects of irregular and regular well patterns and vertical and horizontal gas injection wells are investigated using a fully compositional 3D reservoir model in both the secondary immiscible and miscible modes under the conditions of voidage balance, constant injection and production pressure and injection rates below the critical rate. Regular well pattern provided longer oil production time at a constant rate until CO2 breakthrough compared to irregular well pattern. It then dropped almost vertically at the same cumulative oil recovery even at higher production rates. However, gravity drainage oil recovery was higher at higher rate combination after CO2 breakthrough. Results also suggested that the regular pattern could result in horizontal CO2 floodfront parallel to the horizontal producers, maintaining reservoir pressure, thus optimizing the oil recovery by additional 2.5% OOIP. Vertical injection and horizontal production wells in both the immiscible and miscible modes provided nearly identical cumulative gravity drainage oil recovery compared to the combination of horizontal injection and production wells in the regular well pattern. This suggests that the type of injection wells may not be a significant factor to impact the CO2-assisted gravity drainage mechanism. Results obtained herein would help in the optimization of CO2-assisted gravity drainage EOR process.

This paper presents insights gained from analyzing and modeling acid gas (H2S and CO2) injection well performance over the last 13 years. As the world increasingly develops oil and gas reservoirs that contain significant concentrations of H2S and CO2, the number and size of acid gas injection facilities and their associated acid gas injection wells will increase. A methodology to estimate wellhead operating pressures satisfies a key requirement for design of the injection wells and sizing of the acid gas injection compressors. It may also help inform engineering and operations personnel, and regulatory agencies, of the complex behaviour of acid gas injection wells. The initial impetus for this work was an operator who increased the acid gas injection rate on a well yet saw virtually no change in wellhead operating pressure, which is inconsistent with water injection well operations. To predict wellhead pressures, a numerical simulation model integrates a modified Peng-Robinson equation-of-state for fluid phase behaviour with a wellbore model and a multi-step adaptation of the Cullender and Smith method to account for the friction and hydrostatic pressure changes associated with flow in the wellbore. Pressure gradients in aquifers or reservoirs suitable for acid gas sequestration may range from a normal hydrostatic gradient to extremely sub-normal in depleted hydrocarbon reservoirs. Two injection cases present wellbore pressure profiles for injection into a depleted and a normally pressured reservoir at rates of 20, 100 and 280 103m3/d. Three sensitivity studies illustrate the impact of bottomhole sandface pressure, fluid composition and wellhead temperature on wellhead pressure. Depending on conditions, injected acid gas may undergo phase transitions from a gaseous or two-phase mixture at the wellhead to liquid at the sandface and back to gaseous or supercritical out in the reservoir. The complex interactions between temperature, phase behavior, fluid density and pressure can lead to unusual operating characteristics including an increased injection rate or sandface pressure with little or no change in wellhead pressure.

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.

Geologic parameters, geophysical logging, injection testing, and operational metrics from wastewater injection wells were integrated to develop a preliminary design of a carbon storage facility in the Appalachian Basin. A scattered group of 10–20 commercial wastewater injection wells dispose off produced water from oil and gas wells in the region, utilizing a sequence of stacked deep saline formations for injection zones. These wastewater injection wells provide practical benchmarks for understanding the feasibility of carbon dioxide (CO2) storage. Geologic models were developed based on characterization data from the wastewater injection wells. Reservoir simulations were calibrated according to injection testing and operational data from the wastewater injection wells. Long‐term operational data on injection flow rates and pressures measured in the wastewater injection wells were especially useful to evaluate the performance of carbon storage applications. The simulations were used to estimate injection pressures, radius of CO2 saturation, and pressure response for industrial scale CO2 storage applications. Results were also used to provide a design basis in terms of number of injection wells, well spacing, area of review, injection system components, monitoring plan, and CO2 pipeline distribution system. The analysis demonstrates that there is sufficient injectivity in the deep saline formations in the west‐central Appalachian Basin to store commercial volumes of anthropogenic CO2. The geologic system appears suitable for supporting CO2 injection rates of 0.5–1.0 million metric tons per year at injection pressures below formation fracture pressure in a single well. The long‐term operational data of wastewater injection wells within the study area suggested a lower permeability‐thickness values than indicated by initial reservoir tests. A workflow for developing realistic permeability values for input into reservoir simulations is presented. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd.

This paper describes technical considerations and recommendations for the design and completion of acid gas injection wells. These guidelines are based on acid gas disposal well completion and operating experience in the Jedney field. Initial operating and injection well inspection results are also described. Waste gas from natural gas sweetening plants often contains high Concentrations of carbon dioxide and hydrogen sulphide. Downhole acid gas disposal schemes minimize environmental impact by reducing the release of carbon dioxide and sulphur compounds to the atmosphere. Challenges in the design and construction of Jedney acid gas injection systems included: equipment selection for high concentrations of sour gas, understanding the phase behaviour of acid gas mixtures, use of both new and existing wellbores, accommodation for future well interventions, and safe troublefree operations. P. 17

Review of failures for wells used for CO2 and acid gas injection in Alberta, Canada

This paper provides an overview of the trial implementation of Focused fracture jetting, a solution aimed at effectively stimulating long horizontal open-hole wells in the oil and gas industry. The goal of this method is to create multiple fractures that penetrate deeper into the reservoir, increasing the overall stimulated surface area. Previous techniques, such as HCl stimulations, delayed reaction acid, abrasive jetting, and fishbones, did not achieve the desired improvements in injectivity for microporous water injection and oil producer wells. As a result, alternative methods were explored, leading to the adoption of Focused fracture jetting. This methodology utilizes high velocity jetting and dynamic diversion to create controlled fractures etched with acid, providing permanent increases in effective wellbore area. This paper focuses on the trial implementation of Focused fracture jetting in two water injection wells and one oil producer, named as WI-1, WI-2 and OP#1. In WI#1, 25 stages were pumped over a 700m interval with 30m spacing between stages, while in WI#2, 20 stages were pumped over a shorter interval of approximately 500m with 25m spacing between stages and OP#1, 11 stages were pumped over a shorter interval of approximately 680m with 29m spacing between stages. The stimulation was successful in improving water injection rates, resulting in a significant increase in the initial rate and approximately doubling the stable injection rate as well as production was enhanced drastically from the oil producer OP#1. The deployment of Focused fracture jetting has the potential to unlock the microporous reservoir's development, particularly in tight reservoirs with long open-hole sections, offering competitive costs and sustainable results.

A new tool provides simultaneous recording of measurements from all downhole production-logging sensors used in the analysis of production or injection wells. The system was used to evaluate production-well profiles in the South Swan Hills miscible flood project in Alberta, Canada. The dynamic reservoir picture obtained from the information proved useful in improving reservoir performance. Introduction Production logs have been used for many years to Production logs have been used for many years to evaluate producing and injection wells. In the past, when reservoirs with excess capacity were limited by allowables, production logs were used basically to diagnose a problem on an individual well, such as locating a source of water production or defining a mechanical problem such as a packer leak. Today, with the increased demand for oil and the declining capacity of mature reservoirs, combined with more sophisticated recovery schemes, the oil industry is becoming increasingly aware of the importance of improving fieldwide reservoir performance. With this shift in emphasis, the role of production logging has taken on a much wider scope.For the evaluation and management of a reservoir, the reservoir engineer may get the information he needs by running production logs on selected production and injection wells throughout the production and injection wells throughout the reservoir. By repeating this on an appropriate time scale, a dynamic description of the reservoir can be evolved. This information can be integrated with formation evaluation logs, such as the TDT log and the initial openhole logs, to compare actual performance with indicated reservoir potential. performance with indicated reservoir potential. The analysis of producing wells is rarely simple. Downhole flow usually involves different fluids (oil, water, and gas) having different densities and moving at different velocities. Furthermore, these may vary with time because of well instability. Typically, several measurements are needed to resolve the problem. The effect of well instability can be reduced problem. The effect of well instability can be reduced by obtaining the measurements simultaneously. Much has been published in the literature on the use of flowmeter, thermometer, manometer, Gradiomanometer TM and caliper tools to analyze downhole flow. In addition, a casing-collar locator and a gamma-ray log are useful for depth control and correlation with the formation evaluation logs.In this paper we describe a new 1 11/16-in. (42.9-mm) diameter telemetry-based tool - the PLT (TM) (simultaneous production logging tool) - capable of transmitting all these measurements simultaneously during one trip in the well. It is relatively easy to add new sensors to this flexible system. A new dual tracer ejector tool and a high-precision pressure gauge, which have been added to the above family of sensors, also are discussed.This paper presents the results of a 15-well logging program in which the PLT tool was used to evaluate program in which the PLT tool was used to evaluate a miscible flood project in the South Swan Hills pool in Alberta, Canada. While tracer materials were used to monitor the lateral progress of the flood front, production logging was used to monitor the vertical production logging was used to monitor the vertical distribution in both injection and production wells. JPT P. 191

Corrosion tests were conducted in a high-temperature high-pressure (HTHP) autoclave to simulate the conditions of CO2 auxiliary steam drive in gas injection wells. Weight loss tests were performed with the sheets of N80 and 9Cr steels under the testing conditions. The morphology and composition of corrosion products were explored by SEM, EDS, XRD and XPS. The corrosion resistance of 9Cr steel was better than that of N80 steel under the testing conditions. The corrosion rates of N80 and 9Cr met the application requirements in CO2 auxiliary steam drive. The results broke the constraint in ISO-15156 standards. The corrosion process of N80 steel was mainly affected by the flow velocity. However, the corrosion process of 9Cr steel was mainly affected by temperature. The corrosion resistance of 9Cr steel depended on the FeCO3 content of Cr-rich layer, which was closely related to temperature. The low flow velocity influenced the diffusion process of N80 steel corrosive ions, whereas the high flow velocity influenced the integrity of corrosion scales. Considering the influence of flow velocity on the corrosion of tubing and casing, in the gas injection well, 9Cr steel and N80 steel were, respectively, selected as the materials of tubing and casing.

Underground gas storage is a common activitity in countries with major transport and distribution gas pipeline infrastructures, which allows to efficiently resolving demand seasonality problems. The first ever underground gas storage project in Turkey is being carried out in the KM field with injection and withdrawal operations. Optimization of gas storage field was enabled by an improved reservoir and geologic description, including the evaluation of deliverability and storage capacity in the reservoir. Based on available information and those generated by simulation model, KM field is the best candidate for underground gas storage. The KM offshore natural gas field was discovere in 1988 located about 3 km off the shore of Silivri in the Marmara sea. The field was initially planned to be developed with 3 wells, but recently 2 additional wells were added during the development of the field hence increasing the depletion rate. In this study, after gathering necessary reservoir, fluid, production and pressure data, IMEX (CMG) simulation program was used for history matching of depletion of the field. Reservoir performance after history matching using depletion scenario was predicted and depletion last for 4 years. In 2005, 5 ERD wells were drilled in KM field from onshore drilling site location for gas storage application. Five scenarios were developed for forecasting of injection and withdrawal performance of the reservoir. These scenarios were used 5 newly drilled horizontal wells with combination of existing vertical wells. With a predetermined injection rate of 65 MMscf/day was set for all the wells and among all scenarios, 5 horizontal – 5 vertical injectors and producers was the most successful in hamdling the gas inventory and he injection period was 5 months and production period was 7 months, respectively. After the determination of the well configuration, the optimum injection rate for the entire field was obtained as 65 MMscf/day by using horizontal gas injection wells. The total produced gas volume until 2012 was estimated as 394 Bscf with this optimum gas injection where the maximum average reservoir pressure was 1901 psi and cushion gas pressure was 1270 psi by withdrawal.

Monitoring of CO2 plumes is required to verify long-term sequestration of injected CO2, detect possible leaks from the storage zone, and infer deviations in plume path due to unforeseen large-scale geologic anomalies like flow barriers or high permeability streaks. Although several alternatives are available for monitoring plume path deviations during injection, the cost of monitoring still is a paramount concern for operators. The conjecture of this work is that dynamic data measured at injection wells are informative of the presence of heterogeneities large enough to affect plume paths. Hence geologic models updated using injection data can be used to predict better the trajectory of CO2 plumes and to design operational schemes that will ensure long term containment of the injected CO2. To test this conjecture, we have adapated a probabilistic history matching software (Pro-HMS) originally developed for oil field applications. The software assimilates injection data commonly monitored at active and inactive wells into models for the subsurface aquifer/reservoir. The algorithm yields an ensemble of realizations geologically consistent with the initial model such that the uncertainity in CO2 plume location can be easily assessed. We illustrate the approach with synthetic examples (a deep, heterogeneous aquifer with a long streak of large or small permeability) for which the reference bottomhole pressure and rate responses from injection and inactive wells were obtained from simulation. The updated models obtained after the history matching process detected the presence of the streak, and the subsequent estimation of CO2 plume location was much more accurate. Pressure data recorded at inactive wells were essential for detecting the streak. Monitoring such wells is thus expected to provide valuable information about geologic heterogeneities. The results confirm that injection rate and pressure data provide an inexpensive option for monitoring CO2 plumes.

Numerical modeling of hydraulic fracture propagation behaviors influenced by pre-existing injection and production wells

As experience in field development shows, unplanned growth of injection well cracks does not always have a positive effect on the development of oil reserves, but, on the contrary, causes premature flooding of producing wells. Currently, most of the fields are at the final stages of development, and an increase in reservoir coverage by flooding is an important task of developing oil fields. The article discusses and analyzes the effect of injection well capacity on the growth of self-induced fracturing fractures and the relationship with oil production on the example of one of the fields in Western Siberia. Using the hydrodynamic simulator and the geomechanical module, the best option was chosen and the positive effect was evaluated. An example is a production well of a highly watered stock. The reasons for the premature well flooding are considered by analyzing the graphical dynamics of capacity and flow rate of injection and production wells. As confirmation of the fracture growth or closing, the results of the adaptation of a single-layer two-phase model using the automatic hydraulic fracture are presented. The analysis of the geomechanical properties of the layers was carried out, during which the dependence of the crack length on the bottomhole pressure was determined. This dependence is compared with the results of the model adaptation. According to this adaptation of the hydrodynamic model, several variants of calculations were made in order to identify the optimal bottomhole pressure and compare this variant with the actual one. According to the data obtained, it was found that with optimal injectivity, a positive effect was observed already in the first month. The information obtained during the analysis of actual data and calculation on the hydrodynamic and geomechanical module, confirms the need to control bottomhole pressure at injection wells. Calculations show that there is a significant loss of oil production after the crack has opened. Using a calculation on the geomechanical module, optimal bottomhole pressures were given for a given injection well, at which there would be no increase in the crack of the injection well followed by watering of the production well. Calculations to determine the optimal values of the bottomhole pressure of the selected injection well can be applied to the wells of other fields.

This article is a synopsis of paper SPE 72108, "Intelligent Internal Gas- Injection Wells Revitalize Mature S.W. Ampa Field," by Hon Chung Lau, SPE, Robert Deutman, SPE, Salim Al-Sikaiti and Victor Adimora, Brunei Shell Petroleum Co., originally presented at the 2001 SPE Asia Pacific Improved Oil Recovery Conference, Kuala Lumpur, 8-9 October.

In many respects formation damage challenges in CO2 storage wells are similar to those in conventional oil and gas production wells and water and gas injection wells. But there are some differences from "conventional" well formation damage challenges. This paper outlines some issues specific to CO2 injection wells and proposes changes in focus prior to and during drilling and completion of these wells. CCS (Carbon Capture and Storage) store can generally be split in to two categories – saline aquifers and depleted hydrocarbon reservoirs. Wells drilled and/or completed in these stores share some well injectivity challenges with conventional wells but also have some challenges specific to the store properties. In conventional injection wells it is generally accepted that well clean-up or back production prior to injection is beneficial as formation damage necessarily induced during well drilling and clean-up may be partially or fully removed. For saline aquifers and depleted hydrocarbon stores, well clean-up is normally not possible or practical. Direct injection after well completion is often required. A new workflow capturing the key steps required to assure optimum well injectivity over the well life cycle has been developed and will be outlined in the paper. This includes but is not limited to: detailed analysis of CO2 phase behaviour in and beyond the lower completion; lower completion selection criteria specific to CO2 stores; laboratory testing and modelling focussed on CO2 store formation damage challenges; direct injection challenges and successful mitigations; ice scale and hydrate challenges in CO2 storage wells. With increasing focus on CO2 storage globally, the workflow outlined presents an integrated approach to formation damage challenges. It demonstrates that although many of the challenges are similar to those in conventional wells, there are also some that are different and unique – the same, but different!