Injection Wells Research Articles

Prediction and optimization of productivity and lifespan in multi-well enhanced geothermal system

Engineering case studies have revealed that multi-well enhanced geothermal system is efficient for large-scale geothermal energy utilization. However, current research on the productivity and lifespan of multi-well enhanced geothermal system is limited to rough estimation by thermal storage volume, without a fast and accurate prediction method. To solve this problem, the multi-well enhanced geothermal system is divided into several double-well enhanced geothermal systems. The numerical simulation and previous empirical formulas for double-well enhanced geothermal system are used to propose a new multi-well enhanced geothermal system empirical formula in this study. The proposed formula is applicated using the Rehai geothermal field in Yunnan, China by three-well model and six-well model respectively. The results show that the heat production and lifespan of the enhanced geothermal system with six wells arrangement are higher compared to the three wells arrangement. Moreover, the productivity and lifespan of enhanced geothermal system with injection pressure difference and injection temperature of 1.0 MPa and 293.16 K for thermal medium are significantly better than those of 2.5 MPa and 353.16 K, respectively. Therefore, during enhanced geothermal system construction, both productivity and investment should be considered, and the number of injection wells should be maximized. Low-temperature thermal medium and low injection-production pressure differences should be selected for maximum heat production during the operation. This research presents a fast and accurate prediction method for predicting and evaluating the heat transfer performance of large-scale multi-well EGS which is helpful for EGS commercial use.

Modelling of Nano Silica Formation from Geothermal Silica Using Co-Precipitation Method

Nanosilica is a nanotechnology product with many substantial functions in many industries. Previous research showed that nano silica can be synthesized from geothermal silica, that caused silica scaling in injection well and turbine in geothermal power plant, reducing its power plant capacity by 40%. This research used geothermal silica as a precursor for nanosilica production with co-precipitation to recover amorphous silica from silica geothermal to reduce scaling while also increasing its economic value. The objectives of this study were to determine the model to represent the co-precipitation method for nano-silica by using nucleation and growth modelling, therefore help the scale-up process of nanosilica production. The experiment was conducted in four steps. (1) Silica washing utilized distillate water with a ratio of water to silica of 10:1 and sulfuric acid of 20% with a ratio of acid to silica of 4:1, both as a washing agent. (2) Preparation of HCl with concentrations of 3% and 9%. (3) Preparation of sodium silicate solution by reacting washed silica and NaOH to obtain sodium silicate. (4) Preparation of primary and secondary sodium silicate by diluting sodium silicate by two and four times to obtain primary and secondary sodium silicate, respectively. (5) Precipitation of sodium silicate with HCl consists of two steps using primary and secondary sodium silicate. The result showed that the model fit concentration data, with Sum of Squared Error (SSE) 1.9297.10-4, mass transfer coefficient rate is 9.8.10-3 dm/min, and the average relative error is 3.5%.

Monitoring seismicity triggered by geothermal site shutdown with a surface DAS array at Brady Hot Springs

SUMMARY Seismicity induced by fluid injection including wastewater injection, hydrofracking and enhanced geothermal system (EGS) site production draws public attention. Dense arrays have been deployed to improve monitoring capability. In 2016 March, the PoroTomo experiment deployed an 8.6-km-long fibre-optic cable for distributed acoustic sensing (DAS) in the geothermal field at Brady Hot Springs, Nevada, covering an area of 1.5 by 0.5 km. The goal was to assess an integrated technology for characterizing and monitoring temporal changes in the rock mechanical properties of an EGS reservoir in three dimensions. We applied a neural network designed for earthquake detection called ADE-Net2 to the DAS data set to detect seismic events in continuous records. We were able to detect a total of 90 earthquakes, which included 21 events that had not been reported by a previous template-matching study. Additionally, we were able to successfully detect almost all of the active source signals, with only seven events being missed. We used the STA/LTA (short-/long-term average) method to pick arrivals and a clustering method to remove outliers. We initially tried a standard event location algorithm, but the low signal-to-noise ratio resulted in significant picking uncertainty that is up to ∼0.5 s, leading to large location uncertainty. Therefore, we developed a new location method based on the similarity between the theoretical traveltime curve and picked moveout. A grid search scheme was adopted to find the optimal point at which the traveltime curve is most similar to the picked one. Most newly detected earthquakes locate southwest of the DAS array, where five earthquakes were reported by a local seismic network. The plant began shutting down at 19:15 UTC on the March 13, and most earthquakes occurred on the March 14, indicating a relationship between the seismicity and the pressure changes caused by the shutdown of the plant. The pressure changes at epicentres obtained from a simplified model range from 71 to 157 kPa, exceeding a typical earthquake trigger threshold of 10 kPa.

3D coupled hydro-mechanical modeling of multi-decadal multi-zone saltwater disposal in layered and faulted poroelastic rocks and implications for seismicity: An example from the Midland Basin

Knowledge of subsurface coupled pore pressure and stress perturbations due to saltwater disposal (SWD) is crucial for understanding and managing induced seismicity. Current studies choose Biot poroelasticity to implement fluid-rock coupling and perform numerical modeling in relatively simple settings. In this study, we first introduce a general poromechanical framework to capture a broader range of hydro-mechanical coupling and then apply it to model real-world SWD problems with geological and operational complexities. We demonstrate a viable workflow through the case study of a 2500 km2, layered, faulted, and recently seismically awaken area that has undergone multi-decadal multi-zone injection by nearly 200 SWD wells in the Midland basin. The example provides a unique opportunity to study the respective impact of shallow and deep injections across depths and the role of inter-zone interactions, among others. Our modeling suggests over 500 and 250 psi increases in pore pressure and Coulomb stress, respectively, in the deep disposal zone in the last decade, which were 5 to 10 times greater than those accumulated over the past four decades in the two shallower disposal zones. Vertically, shallower injections impacted mostly shallower zones, whereas the deep injection produced changes across depths and dominated especially in the deep zone and the upper segment of the basement. Towards the mid-segment of the basement, changes due to shallow and deep injections were comparable, with the latter 2 to 5 times higher. Laterally, in-zone changes were dominated by pore pressure diffusion in the near field and poroelastic stressing in the far field in shallower zones but were dominated by pore pressure diffusion everywhere in the deep zone, owing to their different hydraulic diffusivities. Faults acted as pore pressure and Coulomb stress sinks for disposal zones and sources for non-disposal zones, and fault-zone permeability structure had a minor impact. Finally, seismological modeling suggests that seismicity in the area was most likely driven by the deep injection.

Hydrocarbon production induced land deformation over Permian Basin; analysis using persistent scatterer interferometry and numerical modeling

The Permian Basin, encompassing Southeastern New Mexico and Western Texas, has been an important source of oil and natural gas for over a century for the United States. With recent advancements in petroleum extraction methods, such as hydraulic fracturing and horizontal drilling, production has increased exponentially. Such rapid developments, along with the disposal of wastewater back into the subsurface, have caused significant changes in the stress regime of the region’s subsurface, resulting in various geohazards including land subsidence. In this work, we used the Sentinel-1C-band SAR dataset acquired between 2016 and 2021 to measure the basin-wide deformation over the entire Permian Basin. We utilized Persistent Scatterer Interferometry (PSI) technique to produce the time-series deformation at millimeter-level accuracy. The average monthly production and injection volumes and well depths over the Delaware Basin in New Mexico were calculated for each well and the impact of the hydrocarbon activities on the deformation was modeled using a distributed point source model from fluid volume and well depth data. The results show that the Permian Basin was deforming at a rate of 3–4 cm/yr., with two large pockets of deformation to the north of the Grisham Fault Zone (GFZ) in the Delaware Basin. The region south of the GFZ shows complex deformation features with linear patterns, indicating the presence of faults hindering fluid flow. Some areas in the Delaware Basin also show an uplift, especially along the Texas side of the border driven by shallow wastewater injection. The Midland Basin is also affected by subsidence with several localized subsidence zones identified in the region. Further, the Midland Basin experienced an increase in intensity and the spatial distribution of the deformation over the last few years. Given both production and injection well data, the modeled deformation results agree with the observed except in two pockets. When only production data is used for the modeling, the modeled deformation shows better agreement with the observed, especially in the interior of New Mexico. The modeling results suggest that the deep wastewater injection has minimal impact on surface deformation in the region. Additionally, it is also possible that the region has undergone inelastic deformation. While we used an elastic model in this preliminary study, a more accurate study requires regional poroelastic modeling to study the interaction between the solid subsurface and fluid hydrocarbons in detail.

Microbial characteristics and potential mechanisms of souring control for a hypersaline oil reservoir

The production of hydrogen sulfide (H2S) had caused huge economic losses and security risks to oil fields, which had attracted the attention of many researchers. Studies focused on hypersaline oil reservoirs were scarce. Here, we simulated H2S inhibition by adding NO3 - and NO2 - in anaerobic bottles and up-flow sand-packed bioreactor in the laboratory using water samples from injection wells in the Jianghan reservoir. The microbial characteristics, pH, salinity, sulfate, sulfide, NO3 - and NO2 - were measured at every stage. The content of H2S and elemental sulfur (S0) gradually reduced to 0 mg/L with injected 400 mg/L of NO3 - and 300 mg/L of NO2 -. Halophilic nitrate-reducing bacteria (NRBs) related to Halomonas and Arcobacter could suppress the activity of sulfate-reducing bacteria (SRBs) through the accumulation of nitrite toxicity and the competition of organic substrates with SRBs. When SRBs activity could not be suppressed, the sulfur-oxidizing bacteria related to Sulfurimonas, Thiomicrospira and Acrobacter were accumulated for souring control through microbial sulfur cycle of H2S production and oxidation. Salinity could be a key parameter affecting microbial development and interactions. This study provides a fundamental data to souring control in the hypersaline oil reservoir by reinjection produced water amended with NO3 - and NO2 -.

Deep intracochlear injection of triamcinolone-acetonide with an inner ear catheter in patients with residual hearing.

In a previous study, an inner ear catheter was used to deliver low- and high-dose steroids into the cochlea prior to cochlear implant electrode insertion. With this approach, more apical regions of the cochlea could be reached and a reduction of electrode impedances in the short term was achieved in cochlear implant recipients. Whether intracochlear application of drugs via the catheter is a safe method also for patients with residual hearing has not been investigated hitherto. The aim of the present study was therefore to investigate the effect of intracochlear triamcinolone application in cochlear implant recipients with residual hearing. Patients with residual hearing were administered triamcinolone-acetonide (4 mg/ml; n = 10) via an inner ear catheter just prior to insertion of a MED-EL FLEX28 electrode. Impedances were measured at defined time points (intra-operatively, post-operatively and at first fitting) and retrospectively compared with a control group (no steroid application) and low- and high-dose group. Hearing thresholds were measured preoperatively, 3 days after surgery and at first fitting by pure tone audiometry. Pre- to postoperative hearing loss was determined at first fitting and compared to results from a previous study. The median hearing loss after implantation (125-1,500 Hz) was 20.6 dB. Four patients (40%) showed a median hearing loss of less than 15 dB, three patients (30%) between 15 and 30 dB and three patients (30%) more than 30 dB. The median hearing loss was similar to the results obtained from our previous study showing a median hearing loss of 24 dB when using FLEX28 electrode arrays. No difference in residual hearing loss was found when comparing application of triamcinolone-acetonide using an inner ear catheter prior to the insertion of a FLEX28 electrode array to the use of the FLEX28 electrode array without the catheter. Thus, we conclude that application of drugs to the cochlea with an inner ear catheter could be a feasible approach in patients with residual hearing.

ECOANALYTICAL CONTROL OF SURFACE WATERS IN THE ZONE OF INFLUENCE OF THE YAMBURG OIL AND GAS CONDENSATE FIELD

The article is devoted to the actual problem of surface water monitoring in the zone of influence of oil and gas producing enterprises.
 Aims and Objectives – comprehensive pollution assessment of natural water bodies located in the zone of influence of wastewater injection landfills of the integrated gas treatment plants IGTP-1 and IGTP-2 of the Yamburg Oil and Gas Condensate Field using the water pollution index.
 The pollution assessment of natural waters was carried out in accordance with State Standard 17.1.3.07-82 «Nature protection. Hydrosphere. Procedures for quality control of water in reservoirs and stream flows». The average regional values of the controlled components correspond to the «Handbook on the use of average regional values of controlled Component content at monitoring Sites when assessing the state and level of environmental pollution in the Yamalo-Nenets Autonomous Okrug».
 It has been concluded that, on average, the water pollution index of the studied territory for the period since 2019 up to 2021 corresponds to the 2nd quality class («clean»), excluding from the calculation the concentration of iron – a typomorphic element of the natural waters of the North taiga zone.

Study on the Variation Law of Reservoir Physical Properties in High Water Cut Stage

Difficulty in water injection during the water injection development (water injection production refers to the injection of water into the reservoir from injection wells during the development process of an oil field; due to its good economic efficiency and high feasibility, it has become the main method of oil field development) process of the G block reservoir is an important problem to solve. Three cores of the G block are used as the object of this study, and the laser particle size test is conducted on the target core to obtain the particle size distribution of the core. X-ray diffraction mineral content analysis is used to obtain the proportion of different mineral contents. On this basis, online nuclear magnetic technology is used to carry out the research on the change of reservoir physical properties during the high-magnification water injection process. The experiment shows that three cores (cores 8-2, 16-1, and 9) are identified as medium sandy fine sandstone with silt (the three-level naming method was adopted and the name has been changed to medium sandy fine sandstone containing silt, because the proportion of fine sand is greater than 50%, the content of medium sand is between 25%~50%, and the content of silt is between 10%~25%), medium sandy fin sandstone containing silt, and silt fine sandstone, by laser particle size testing. Their clay mineral contents are 2.47%, 2.51%, and 4.76%, respectively; the permeability (water) of the three cores continues to decrease with the increase in water injection, but the nuclear magnetic porosity and the signal intensity of different fluids in the nuclear magnetic T2 and nuclear magnetic two-dimensional spectrum show different variation patterns with the increase in water injection. The clay minerals of core 8-2 and core 16-1 are relatively small. The nuclear magnetic porosity increases rapidly to the maximum value and then decreases slowly with the increase in water injection. The right peak signal intensity in the T2 spectrum rises first and then drops, while the clay mineral content of core 9 is relatively high. The change trend of nuclear magnetic porosity is firstly decreasing and then increasing, and the signal intensity of the right peak in the T2 spectrum decreases first and then increases. The research concludes that in the early stage of water injection, clay minerals undergo hydration and a small amount of particle migration; in the later stage of water injection, due to the scouring effect of water, the fine silt and clay minerals in the cement easily fall off and migrate to the pore throat to the block. Some damage to the pore throat leads to a decrease in permeability, thus affecting the development effect.

Cracking property and brittleness evaluation of granite under high-temperature true triaxial compression in geothermal systems

Cracking property and brittleness are critically important to the drillability of injection and production wells of enhanced geothermal systems. This paper is devoted to evaluating the cracking property and brittleness of the Gonghe granite under high-temperature true triaxial compression conditions through a series of laboratory tests. Thermal–mechanical coupled true triaxial compression tests were conducted on Gonghe granite samples under four representative temperatures (20 °C, 120 °C, 180 °C, and 240 °C) and three different minimum (5, 10, and 30 MPa) and intermediate (40, 60, and 75 MPa) principal stresses that correspond to the in-situ conditions of Gonghe geothermal reservoir. The strength, deformation, and cracking characteristics of the Gonghe granite are quantitatively evaluated from macro- to micro-scales based on the experimental results. Meanwhile, a novel brittleness index evaluation method considering both energy and failure surface roughness is proposed to accurately assess the brittleness strength of the Gonghe granite. We found that the strength of Gonghe granite is reduced by more than 20% when the temperature increases from room temperature to 240 °C. Higher temperature contributes to a smoother fracture surface and reduced brittleness of the Gonghe granite under thermal–mechanical coupled true triaxial compression. Our findings provide new insights for brittleness evaluation of the Gonghe granite formation and assist in efficient wells drilling design of enhanced geothermal systems.

The Effectiveness of the Introduction of the Water-Alternated-Gas Injection on the example of a Carbonate Field in Kazakhstan

Background: Water-Alternated-Gas Injection (hereinafter referred to as WAG) is considered to be a suitable analogue of gas injection and waterflooding, which increase the efficiency of displacement. With continuous gas injection, the displacement front is unstable due to the low viscosity of the gas, which leads to the formation of gas tongues due to a significant difference in the mobility of gas and oil. Alternate injection of water and gas is considered a suitable option in eliminating this problem and in stabilizing the displacement front.
 Aim: The purpose of this work was to generalize the main factors affecting the efficiency of the process, based on the world experience in applying the WAG technology. The effectiveness of this technology application in a carbonate field was also considered.
 Materials and methods: This article analyzes the efficiency of oil displacement using the WAG method in a carbonate field in Kazakhstan. In order to study the proposed oil production technology, the alternate injection of water and gas into the reservoir was simulated on the ECLIPSE 100 simulator. First of all, the process of optimizing the parameters was carried out based on two injection wells. As a result, it was found that for the studied field, the duration of water and gas cycles of 3 months and the sequence of "gas water" are the optimal conditions for observing the greatest effect from WAG. Further, based on the selected parameters, WAG was scaled to the entire field, for the implementation of which several options were developed with 3, 5, 6 and 12 injection wells.
 Results: As a result of the research, the optimal oil displacement option was selected, which involves 5 injection wells with high injectivity and a large volume of injected gas.
 Conclusion: Due to the hydrophilicity of the reservoir, the effect of alternating WAG turned out to be not as significant as it could be expected, due to the effect of hysteresis of relative phase permeabilities, which can be a topic for future research.

Hydraulic fracturing using high-boiling fraction of oil as a fracturing fluid

Background: In recent years, there has been a trend towards deterioration in the structure of residual reserves at the fields of Kazakhstan. A significant part of the reserves is located in low-permeability reservoirs and in the zones not covered by flooding. The main factor negatively affecting the productivity and efficiency of development is the heterogeneity of oil reservoirs.
 Oil-saturated formations are an alternation of permeable oil-saturated sand or limestone and impermeable clay or dolomite layers, lenses and interlayers. Up to 1020 interlayers can be distinguished within the reservoir, which indicates a strong compartmentalization of the reservoirs. Due to the complexity of the structure of oil deposits, it is very difficult or impossible to ensure complete drainage of the entire volume of the deposit and complete coverage of oil displacement by water into production wells through injection wells.
 Aim: Increasing oil recovery in a cost-effective way.
 Materials and methods: Experimental studies of the processes of impact on the bottomhole formation zone with high-boiling oil components were carried out using a laboratory machine for diamond drilling, an installation for determining the permeability of a rock in terms of liquid and gas, an installation for determining oil viscosity, and an installation for pumping fracturing fluid into the reservoir model.
 Results: As a result of applying the hydraulic fracturing method using high-boiling oil components, it is possible to increase the permeability of low-permeability formations and significantly increase oil recovery.
 Conclusion: Due to the geological structure of multi-layer oilfields, water-based gel fracturing fluids to increase oil flow to wells are considered ineffective due to the adsorption of gels with long molecules in the pores of the formation and swelling of the clay particles of the reservoir when they interact with the water-based fluid.

Seismicity Analysis and Velocity Structure of Two-phase Geothermal Field in Southern Bandung

Over a duration of six months, we conducted a microearthquake analysis to characterize the subsurface conditions in the two-phase geothermal field located in Southern Bandung. Throughout the study, a total of 754 microearthquake (MEQ) data were recorded from at least 15 monitoring stations. After selection process of the dataset, 362 events were selected based on their azimuthal gap angle being less than 180°. Initially, the earthquake locations were determined using the Geiger method. Subsequently, we updated the hypocenter locations through simultaneous inversion, incorporating 1D velocity structure and 3D tomographic inversion. Our analysis revealed three primary seismicity clusters, which likely correspond to the injection and production activities within the geothermal field. The southern cluster aligns with the injection wells, extending from a depth of 1 km to 8 km, suggesting that the MEQ events were induced by injection activity. In the production area, a higher concentration of events is observed, densely distributed between depths of 1 km and 3 km. We suspect that the third cluster is associated with the development activity of a steam-dominated geothermal field located east of the main field. Notably, low Vp/Vs values near the surface are detected and exhibit increased thickness towards the north. These characteristics are interpreted as indicative of the steam zone, as the anomaly's location aligns closely with the production area. The thickening of the low Vp/Vs zone towards the north suggests the presence of steam as the impact of fluid extraction in the region, leading to a decline in pressure.

A Novel Multi-Phase Strategy for Optimizing CO2 Utilization and Storage in an Oil Reservoir

In this paper, an innovative multi-phase strategy is developed and numerically tested to optimize CO2 utilization and storage in an oil reservoir to support low carbon transition. In the first phase, the water-alternating-gas (WAG) injection is conducted to simultaneously store CO2 and produce crude oil in the reservoir from the respective injection and production wells. In the second phase, the injection and production wells are both shut in for some time to allow CO2 and water to be stratigraphically separated. In the third phase, CO2 is injected from the upper part of the reservoir above the separated water layer to displace water downwards, while fluids continue to be produced in the water-dominated zone from the lower part of the production well. Lastly, the production well is finally shut in when the produced gas–water ratio (GWR) reaches 95%, but CO2 injection is kept until the reservoir pressure is close to the fracture pressure of its caprocks. The numerical simulations show that implementing the proposed multi-phase strategy doubles CO2 storage in comparison to applying the WAG injection alone. In particular, 80% of the increased CO2 is stored in the third phase due to the optimized perforation. In addition, the CO2 injection rate in the last phase does not appear to affect the amount of CO2 storage, while a higher CO2 injection rate can reduce the CO2 injection time and accelerate the CO2 storage process. In the proposed strategy, we assume that the geothermal energy resources from the produced fluids can be utilized to offset some energy needs for the operation. The analysis of energy gain and consumption from the simulation found that at the early stage of the CO2-WAG phase, the energy gain mostly comes from the produced oil. At the late stage of the CO2-WAG phase and the subsequent phases, there is very little or even no energy gain from the produced oil. However, the geothermal energy of the produced water and CO2 substantially compensate for the energy loss due to decreasing oil production. As a result, a net energy gain can be achieved from the proposed multi-phase strategy when geothermal energy extraction is incorporated. The new multi-phase strategy and numerical simulation provide insights for practical energy transition and CO2 storage by converting a “to be depleted” oil reservoir to a CO2 storage site and a geothermal energy producer while enhancing oil recovery.

Application of the closed loop industrial internet of things (IIoT)‐based control system in enhancing the oil recovery factor and the oil production

AbstractA non‐linear large scale stochastic optimisation model for enhancing the oil production and the recovery factor of the offshore oil reservoirs is proposed. The model aims at minimising the miss‐match between mathematical model and the actual dynamic behaviour of the reservoir and the exploitation time, while maximising the oil production and the recovery factor. The model involves the three dimension (3D) oil reservoirs equipped with a few vertical injection and production wells. The limited number of wells is one of the major features of the common oil reservoirs in the middle‐east region. The proposed model consists of the primarily mathematical model of the 3D reservoir, a model update algorithm and a large scale constrained non‐linear optimisation algorithm. The input to this model is the daily production rate of the oil, natural gas and water produced from the oil reservoir and the output is the optimal injection rate to be injected to the injection wells in order to maximise the oil production and the recovery factor. In order to evaluate the performance of this model, the authors apply this model on part of one of the Iran's offshore oil reservoirs and study the performance improvement due to the proposed model and compare its performance with the performance of the available Improved Oil Recovery (IOR) technique. It is illustrated that the proposed model can increase the oil production from the reservoir up to 47.96% and reduce the exploitation period up to 66.66% compared with those of the available technique.

Pressure-Transient Behavior of Vertical Wells Considering Dynamic Water Hammer and Dynamic Induced Fracture: Theory and Case Studies.

Water injection can result in the creation of induced fracture by connecting natural fractures. The induced fracture penetrates the entire reservoir, leading to the interconnection of injection and production wells and ultimately resulting in water breakthrough and the abandonment of production wells. During well work, the induced fracture exhibits dynamic behavior characterized by extension and closure, known as the dynamic-induced fracture phenomena. During the shut-in process, fracture closure phenomena are often accompanied by water hammer phenomena, which can be detected bottom hole pressure data. However, numerical simulation methods are difficult to describe their dynamic processes. Therefore, we urgently need a mathematical model to fill this gap. In this work, we developed a waterflooding-induced dynamic fracture (WIDF) model. Dynamic water hammer phenomena, multi-dynamic closure phenomena, and fracture storage phenomena are introduced into the WIDF model to describe the induced fracture dynamic behavior. Field cases demonstrate that the WIDF model can improve the accuracy of interpreted parameters and correct incorrect model selection. Green function and Newman product method are used to characterize single-phase water flows within tight reservoirs. Then, the induced fracture is discrete into N segments through the boundary element method. Discrete-induced fractures are divided into n parts. Based on the induced fracture bending property, conductivity variation is independent in each part. The feature line method is used to solve the pressure response of the dynamic water hammer. The Duhamel principle is applied to couple the storage effects and reservoir pressure response. The Laplace transform method transforms the model into Laplace space so that it can be solved easily, and the Stehfest numerical inversion method transforms the model into real space to obtain the final solution. Our results show that the dynamic water hammer flow (DWH) regime with an oscillation curve and the multi-dynamic closure flow (MDCF) regime with peaks exist on the type curve. Resistance coefficient (f) and inertia coefficient (I) control the DWH regime. Fracture storage coefficient (Cf), dynamic fracture closure rates (Delpatm), and induced fracture closure half-lengths (xdfm) control the MDCF regime. It is worth noting that the peak position can be adjusted by the Delpatm and xdfm parameters, achieving a more accurate match to the field cases. The Cf is identified, which corrected for the amplified wellbore storage coefficient. Obtained permeability is also in a reasonable range of permeability for tight reservoirs. In summary, a series of mathematical methods are used to develop and solve an injection well model to identify the dynamic behavior of the induced fracture. Numerical simulation methods are used to verify the accuracy of the WIDF model. Two field cases from X Oilfield demonstrate the practicability of the WIDF model. Dynamic identification of the induced fracture would help engineers develop appropriate injection schemes to prevent water breakthroughs.

Effects of water injection on the stress field in the changning shale gas field, Sichuan Province, southwest China

It is generally considered that injection-induced seismicity is related to injection duration, injection volume, geological settings, and spatial relationships between the wells and preexisting faults. The seismicity in the Changning shale gas field, which is the largest shale gas field in China, has increased significantly since 2012. A 3D finite element model based on this area is established in our study for calculating the effect of injection on the regional stress field. The modelling results show that the permeability of sedimentary rock is a key factor for determining the fluid diffusion range and affects the stress field in deeper strata by controlling the gravity load. This effect is sufficient to induce earthquakes under critical conditions. Under a reasonable permeability (1.45 × 10−15 m2), injection may induce shallow-focus earthquakes (<3 km) by pore pressure increase and deep-focus earthquakes by increasing the gravity load. In addition, the low-permeability detachment surface below the injection well may buffer the perturbation of the stress field beneath it during injection.

Simulation of liquid production and water cut dynamics using fluid flow model and neural networks

In the oil industry, there is a noticeable tendency to use proxy modeling of various levels of complexity to perform operational predictive calculations, in particular machine learning methods that are actively developing in the context of digitalization and intellectualization of production processes. In this paper, using the example of a synthetic oil reservoir model development element, we present an approach to the joint use of a physically meaningful fluid flow model and machine learning methods for solving adaptation and prediction problems. A feature of the considered synthetic model is the presence of a pronounced zonal inhomogeneity of the permeability field. Within the framework of the proposed approach, a single-phase filtration model, simplified in comparison with the original formulation was used, the history matching of which was carried out by restoring the field of reservoir filtration parameters using a network of radial basis functions. Based on the reconstructed field, the connection coefficients between the wells were calculated, which qualitatively and quantitatively correspond to the true well connections. The next step was to train a recurrent neural network in order to predict the water cut of the produced fluid. The use of a recurrent neural network made it possible to reproduce the characteristic non-monotonic behavior of the water cut of the produced fluid, caused by non-stationary modes of operation of injection and production wells. A combination of the presented models makes it possible to predict the volume of the produced fluid and its phase composition. To assess the predictive properties of the models, the actual data set was divided into training and test intervals.

Material Selection and Corrosion Rate Analyzed for CO2 Injection Well

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21818, “Material Selection and Corrosion-Rate Analysis for CO2 Injection Well: A Case Study of K1 Field CO2 Sequestration Project,” by Mohd A. Abu Bakar, Wan Amni Wan Mohamad, and M. Wahidullah M. Wahi, Petronas, et al. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission. _ Typical materials used for CO2 injector wells are either corrosion-resistant alloys (CRA) or epoxy-lined tubulars. The most widely adopted CRA material is 25Cr, which features a high well-application cost. Application of materials other than 25Cr for CO2 injector wells are uncommon but may be fit for purpose. The complete paper describes material-selection methodology and corrosion studies performed in the K1 field CO2 sequestration project using materials other than 25Cr in an effort to optimize well costs and improve overall project economics without jeopardizing CO2 injector-well integrity. Introduction K1 field is in the Sarawak Basin at a water depth of 453 ft. It was discovered by an exploration well in 1972 and appraised by a dedicated well in 1992. The field features a gas column of 324 ft from the free water level at 4,990 ft true vertical depth subsea. Gas initially in place for this field is estimated at approximately 2,800 Bscf. CO2 storage screening studies had identified an opportunity to use the K1 field as a storage site. The source of CO2 gas is a nearby field, from which separated CO2 gas will be transported through a 130-km pipeline to the K1 field’s new injection-wellhead platform. The current plan is to inject and store the CO2 inside one of the depleted carbonate reservoirs until an increase in reservoir pressure to the initial pressure of 3,440 psi is observed. The reservoir temperature is approximately 120°C. Injection-Fluid Composition and Presence of Water Injection fluid contains a high mol% of CO2, methane, and other impurities such as nitrogen and hydrogen sulfide (H2S) gases. Injection fluid will be injected above the CO2 supercritical condition. Based on the injection fluid’s composition, CO2 will be the main source of corrosion in the presence of water when exposed to unprotected tubulars in the wells. The presence of H2S denotes the effect of stress corrosion cracking (SCC) and sulfide stress cracking (SSC), which must be considered in selecting tubing material for the injector wells. A small percentage of water (approximately 0.0086 mol%) also exists in the injection fluid. This will be detrimental to the injection wells in terms of corrosion if it is in the aqueous phase. To study this, the well’s shut-in and injection pressures and temperatures were plotted against the water-phase diagram. During these conditions, water in the injection fluid exists as vapor phase. Considering the possible risks of a higher percentage of water in the injection fluid, a more- conservative approach was taken in the selection of tubing material for the injector wells.

Waterflooding, water-gas method and generation of carbon dioxide in the reservoir – methods of enhanced oil recovery and technology development

This article discusses reservoir pressure maintenance methods: flooding and SWAG technology. The accumulated experience of waterflooding technology introduction described in literature sources is analyzed. Identified such disadvantages of waterflooding as reservoir watering due to significantly low viscosity compared to the viscosity of reservoir oils and low oil recovery factor. A method for detecting and preventing the instability of the front of displacement of residual reserves by injected water is indicated. Particular attention is paid to the innovative method of reservoir stimulation, which consists in the generation of carbon dioxide in reservoir conditions. The essence of the technology, method of implementation, advantages compared to gas injection through injection wells are described. Water-gas methods are investigated. The advantage of SWAG technology with the use of pump-ejector systems in comparison with other modifications is proved and the results of the latest research are presented, which cover data on the characteristics of pump-ejector systems, the topical issue of the technology for obtaining water-gas mixtures and the processes of interaction of gas bubbles when pumping mixtures through wells into the reservoir, as well as ways to implement the technology, taking into account the geological and field conditions of potential targets for implementation. This analysis will allow you to correctly choose the method of stimulation of the reservoir and operate the facilities as efficiently as possible. It should be noted that the considered gas and water-gas methods involve the injection of carbon dioxide, associated, exhaust, flue gases into the reservoir, which makes these technologies the most attractive from an environmental point of view.