Injection Wells Research Articles

Technique Evaluates Polymer Injectivity in High-Salinity/High-Temperature Carbonates

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211451, “Assessment of World-First Two-Polymer Injectivity Tests Performed in Two Giant High-Salinity/High-Temperature Carbonate Reservoirs Using Single-Well Simulation Models and Pressure-Falloff Analysis,” by Juan M. Leon, Shehadeh K. Masalmeh, SPE, and Ali M. Al-Sumaiti, SPE, ADNOC, et al. The paper has not been peer reviewed. _ The complete paper presents the interpretation of two polymer injectivity tests (PITs) performed in two giant light-oil high-salinity/high-temperature (HS/HT) carbonate reservoirs onshore Abu Dhabi. The detailed data acquired in both tests were used to evaluate both polymer injectivity at representative field conditions and in-depth mobility reduction. The interpretation of the pressure transient analysis (PTA) of the pressure falloffs (PFOs) and the mechanistic 3D simulation models of the two PITs confirmed the generation of polymer banks and demonstrated effective propagation of the polymer into the reservoirs at target concentrations and representative rates of future interwell pilots. Introduction The reservoirs tested in the PITs can be described as heterogeneous carbonate reservoirs divided into upper and lower zones. Upper-zone porosities range between 20 and 30%; permeability ranges from 10 to 1000 md. In contrast, the lower zone has porosities and permeabilities ranging from 10 to 30% and from 1 to 20 md, respectively. The main production mechanisms in the reservoirs are peripheral water injection, middip-pattern water injection, and crestal hydrocarbon gas injection in the gas cap. The reservoirs have been developed through long horizontal wells oriented into the lower zones to allow a more-homogeneous sweep. However, the injected fluids in the lower zone travel quickly through the upper zone not far from the injection wells and around the producers into the lower zone. This water or gas inverse coning results in bypassed oil in the lower zone. To face this challenge, the operator has investigated simultaneous injection of miscible CO2 gas and polymer (SIMGAP) for reservoirs with an approximately 10-fold permeability contrast between the lower and upper zones and simultaneous injection of water and polymer (SIWAP) for reservoirs with a permeability contrast of 100-fold or greater between the lower and upper zones. These techniques rely on reducing mobility by polymer injection in the upper zone to provide a pressure barrier and reduce crossflow of the higher-mobility fluid injected into the lower zone. PIT Simulation Model Setup A single-well radial simulation model was built for PIT 1 to assess near-wellbore phenomena by minimizing in-situ velocity and shear-rate calculation errors compared with Cartesian coordinate grids. For interpretation of PIT 2, a mechanistic Cartesian 3D thermal black-oil simulation model was built by extracting a subsector from the last available static geomodel, preserving well architecture and grid resolution in the extracted subsector. The radial simulation model was found unsuitable for PIT 2 because the injector well presented a very high deviated section in the target reservoir, while the long string presented a long horizontal section. Therefore, the polymer injectivity and polymer bank propagation in the upper reservoir might not be represented properly using a vertical well. Different local-grid-refinement (LGR) levels were implemented around the perforation length (upper zone), while the lower zone was in the root grid. The minimum cell radius in the model was determined to be 1.3 ft to avoid errors in well-index calculations considering the well-flow model. Thus, three LGR levels were applied.

Czynniki wpływające na proces piaszczenia w odwiertach kierunkowych

Many wells of offshore fields in Azerbaijan are subject to sanding and plugging. This is especially observed in wells at a late stage of development. The process of plug formation in directional wells is known to be characterized by a variety of factors associated with both natural conditions and the parameters of their development and, most importantly, operation. The degree of influence of the factors varies, in addition to the fact that all of them (directly or indirectly) are interconnected. Sand production is often observed during completion (development) and operation of wells, especially when the productive reservoirs are represented by weakly cemented rocks. It is worth noting that in the case of sand plug formation, the permeability of which is 200 times greater than the per-meability of the productive formation, the oil production rate decreases by 34%. This sand contains up to 5% of oil and poses a problem upon its removal, as it results in environmental contamination. In addition, it deposits in pipelines, surface equipment, causing erosion. This kind of complication is almost universal. Sand removal is one of the main reasons for the formation of cavities and collapse of columns. This problem has acquired particular relevance with the development of thermal methods for the extraction of high-viscous oils: the viscosity of oil decreases, and its fluidity increases. In this case, some reservoirs lose their cementing binder - viscous oil. During planned and emergency shutdowns, when the coolant injection stops, the reverse flow of the coolant enters the injection wells and removes mechanical impurities. This also leads to the formation of sand plugs in the wells and prevents the normal injection of the coolant. The existing methods of operating wells affected by sanding can be divided into two groups: 1) operation of wells with the removal of sand from the reservoir; 2) prevention of sand production from the formation.

Study on the flow characteristics of tight oil reservoirs with linear injection and production for volume-fractured horizontal wells

New technology for developing horizontal well linear injection and production can reduce the spacing and establish an effective replacement system. However, the seepage mechanism needs to be studied systematically. This study considers the outcrop cores in the Ordos Basin using a high-temperature, high-pressure large-scale physical simulation system. A corresponding plate model is used to research the development of volume-fractured horizontal wells with linear injection and production in tight oil reservoirs. The effects of different injection and production spacings and fracture lengths are analyzed and discussed. The results show that the water flooding oil displacement efficiencies of 50 × 50 × 3 and 50 × 40 × 3 cm3 models are different for the same 0.11 MPa/m injection pressure gradient. The latter model has the highest oil displacement efficiency of 32.91%, and its injection spacing is 18 cm. The injection water is first conducted symmetrically and uniformly along the two injection fractures to the single production fracture direction and advanced uniformly. The pressures at the two ends of the injection fracture are V-shaped and symmetrically distributed relative to the production fracture location. A longer fracture length corresponds to a higher oil displacement efficiency in the models with 36, 41, and 46 cm fracture lengths and the oil and water flow linearly. The seepage distance is smaller than the row distance of conventional well network injection and production wells, so the seepage resistance is significantly reduced, effectively increasing the oil-repelling range. The oil-repelling efficiency is at least 8% higher than the depletion development, demonstrating considerable application potential.

EXPERIENCE IN USING PRE-CROSSLINKED POLYMER SYSTEMS FOR ENHANCED OIL RECOVERY IN CARBONATE RESERVOIRS

Recovering residual oil reserves and reducing the level of water cut in produced wells at minimal cost are urgent tasks for mature fields. In such conditions, the use of tertiary methods of reservoir stimulation is relevant, among which a significant share is occupied by chemical methods of enhanced oil recovery. The principle of using flow diverting technologies is to supply small rims of chemical reagents to the reservoir through the reservoir pressure maintenance system, aimed at reducing the permeability of water-flushed zones by installing a waterinsulating barrier in them and redirecting water filtration flows to reservoir zones that were not previously covered by flooding.
 In this paper, we consider the possibility of using the technology of water-swellable preformed particle polymer systems as flow-diverting reagents to increase oil recovery from reservoirs with complicated geological and physical conditions that limit the use of many reagents used in EOR.
 On the example of a reagent sample, which is a pre-crosslinked acrylamide polymer, which contains particles of clay powder (up to 40% wt.), The paper shows the results of laboratory study and experience in applying the technology based on the preformed particle polymer systems at one of the objects of the Ural-Volga region, the reservoirs of which are presented carbonate rocks. The filtration experiment showed that the injection of the preformed particle polymer systems leads to a significant redistribution of fluid flows from a more highly permeable model to a less permeable one. As a result of the research, the main features of the applicability of technology based on the preformed particle polymer systems have been identified. The analysis of the conducted field work was carried out by determining the change in the injectivity profile of the treated injection wells and estimating the additionally produced oil from the reacting production wells. Based on the results of the analysis, additional laboratory studies were carried out, on the basis of which ways were proposed to increase the efficiency of injection well treatments with preformed particle polymer systems.

STUDYING WAYS TO INCREASE THE RELIABILITY OF CRM-APPROACHES IN THE ANALYSIS OF THE HISTORY OF THE WELLS OF SYSTEMS BY INVOLVING ADDITIONAL INFORMATION

Due to the large number of production and injection wells in the field, it is a difficult task to take into account the interconnection and mutual influence of all wells with each other. In this regard, it is advisable to use a proxy reservoir model, which allows to quickly calculate the main development indicators.These algorithms make it possible to predict the production characteristics of wells over the next years, as well as to optimally redistribute the volume of injected fluid between injection wells with minimal costs and high payback. The article calculated 8 cases in which the parameters of well operation control, well commissioning times, the nature of well operation and the change in production well modes on the forecast changed.

Numerical simulation study of closed-loop geothermal system well pattern optimisation and production potential

Previous numerical simulation studies on U-shaped closed-loop geothermal systems (UCLGS) have been based on single horizontal well, but the reservoir temperature influence range of single well is limited and cannot effectively utilize deep geothermal resources. There are few studies on the well pattern design of UCLGS, especially concerning the shape, number, and arrangement of well. Therefore, we proposed a grid-shaped horizontal well heat exchange system of multi-layer and multi-branch to achieve optimal heat transfer and fluid circulation effect. The effects of the well layout location, injection-production ratio, number of grids, and well length on the heat extraction performance were investigated by numerical simulations after establishing a three-dimensional geothermal mining model. We explored the temperature response characteristics of the reservoir. Finally, the actual production characteristics and potential of the grid-shaped horizontal well heat extraction system were characterised using production indicators, such as production temperature, heat production rate, accumulated thermal energy, and generated energy. The results showed that the diagonal well layout is more effective for heat extraction. Multiple injection wells and one production well mode is the optimal design scheme under the conditions of this study. In addition, when using the diagonal well layout, the system’s heat extraction capacity is positively correlated with the number of grids. However, when using the horizontal well layout, it is no longer proportional to the number of grids once the injection rate exceeds 3 kg/s. Increasing the well length can improve heat production efficiency, but it is limited by the total thermal energy storage capacity of the reservoir. When a single-layer well layout cannot meet the heat extraction requirements, a multi-layer well layout can be used to enhance the heat extraction capacity and reduce the interference of the well network system with the reservoir. Therefore, this well design promotes the efficient development of deep geothermal resources.

Remediation of Silty Clay Soil Contaminated with Metal Ions by Electric Field Technology with the Support of Acidic Injection Wells

Remediation of Silty Clay Soil Contaminated with Metal Ions by Electric Field Technology with the Support of Acidic Injection Wells

Effects of different fracture parameters on microseisms induced by hydraulic fracturing

The microseism induced by hydraulic fracturing is of great significance to the development of geothermal reservoirs and the site selection of geothermal systems. In this study, taking geothermal field data from Qiabuqia as a geological reference, several models are developed for hydraulic fracturing simulations based on the models included in the commercial FracMan™ software suit. A series of numerical simulations are carried out to explore the effects of different fracture parameters, including the existence of faults, in-situ stress state, fracture occurrence, and fracture distribution near faults, on the induced microseisms. The results show that during hydraulic fracturing, the existence of faults does affect the propagation direction of the newly generated fractures, causing the fractures to extend toward the fault. The faults also increase the magnitude of microseismic events and make the distribution of microseismic events farther. Under three different in-situ stress states, the magnitudes of induced microseisms and the distance between microseismic events and injection wells are different, mainly due to the different forms of energy release. The total energy of induced microseisms under the reverse faulting stress state (RF) is the largest. Under the normal faulting stress state (NF), the number of microseismic events is the least, with only 28, and these microseismic events are concentrated near the well, with the farthest distribution distance of only 150 m. The fracture occurrence has a significant effect on induced microseisms, mainly affecting the number and distribution range of induced microseisms. With the same number of fractures, as the fracture concentration to the fault increases, both the maximum magnitude and the farthest distribution distance of the induced microseisms increase.

Thermal effects of freshwater injection on flow and salinity distributions in tidally-affected coastal unconfined aquifers

Freshwater injection is a practical and efficient solution to mitigate seawater intrusion in coastal aquifers, but its thermal impacts on groundwater flow and salt transport are still poorly understood. This study investigates the dynamic characteristics of salinity distributions and seawater recirculation in coastal unconfined aquifers subjected to freshwater injection and tides. The results show that the seaward development of thermal plume modifies the transience of upper saline plume and saltwater wedge, significantly prolonging the aquifer response to injected freshwater. Three temporal variations of upper saline plume due to freshwater injection are driven by pressure waves of injected freshwater, thermal plume-induced changes of hydraulic gradients and saltwater wedge, and the hydraulic conductivity within the upper saline plume. Moreover, a delayed reduction in seawater recirculation in response to the thermal impacts of cold-water injection induces a significant and long-lasting overshoot of total water efflux. An increased tidal amplitude facilitates thermal effects on flow and salinity distributions. A deeper injection well extends the flow path of injected freshwater and thermally regulates discharge rates along the beach surface, thereby enhancing overshoot magnitude of total water efflux. These results improve the understanding of underlying processes related to freshwater injection in coastal aquifers and provide guidance for better managing coastal groundwater resources.

A new process to develop marine natural gas hydrate with thermal stimulation and high-efficiency sand control

The development of marine gas hydrate from low-permeability offshore reservoirs with serious sand incursion issues is a challenging task. Currently, there are no mature technologies in the world. Therefore, we proposed a comprehensive development process, including the following measures: (1) Vertical injection-production well pattern enhanced by multi-layer fracturing and hot water injection by seawater source heat pump. (2) An advanced multi-layer hydraulic fracturing technique incorporating cold fracturing fluid, low-temperature consolidation proppant, multi-stage sliding sleeve packer, and a chemical diverting agent. (3) A series of sand control measures including hydraulic fracturing, consolidation proppant, and stand-alone screen. (4) Several rounds of hot water injection-soaking-production (huff-n-puff) on injection wells, and finally continuous injection-production, with depressurization. Then, we built a gas hydrate decomposition rate model to simulate this process. The results show that hot water injection combined with multi-layer hydraulic fracturing can significantly improve the gas hydrate dissociation rate compared with the schemes without hot water injection or fracturing. Combining hot water injection by seawater source heat pump, multi-layer horizontal fractures by advanced hydraulic fracturing technique, and a set of sand control techniques, can efficiently control sand while producing gas hydrate.

Coupled modeling of well and reservoir for geo-energy applications

The energy transition is inevitable since approximately two-thirds of the current global GHG emissions are related to energy production. Subsurface can provide a great opportunity for innovative low-carbon energy solutions such as geothermal energy production, hydrogen storage, carbon capture, and sequestration, etc. Well and borehole operations play an important role in all these applications. In order to operate wells intelligently, there must be a robust simulation technology that captures physics and the expected production scenario. In this study, we design a numerical framework for predictive simulation and monitoring of injection and production wells based on the general multi-segment well model. In our simulation model, wells are segmented into connected control volumes similar to the finite-volume discretization of the reservoir. Total velocity serves as an additional nonlinear unknown and it is constrained by the momentum equation. Moreover, transforming nonlinear governing equations for both reservoir and well into linearized equations benefits from operator-based linearization (OBL) techniques and reduce further the computational cost of simulation. This framework was tested for several complex physical kernels including thermal compositional multiphase reactive flow and transport. The proposed model was validated using a comparison with analytic and numerical results.

Polymer Injection as a Development Strategy to Improve Oil Recovery in the BKH Layer of YDP Field

There are still have a potential oil to be produced, the reduced reservoir pressure due to continuous oil production at a high rate, and the high water cut value are the background for the polymer injection process in the BKH Layer of YDP Oil Field. Due to a high water cut value, the study then conducted using a polymer injection method. Screening criteria for polymers injection was conducted to see the suitability of the reservoir, and then carry out an advanced scenarios using polymers of various concentrations to be compared, and see a cumulative incremental oil production and recovery factor. The stages including collecting and preparing data, processing and analyzing RCAL, SCAL, and PVT data, input data to simulation model with actual conditions. The reservoir simulation performed including initialization, history matching and PI matching, carry out polymer injection scenarios with certain polymer concentrations, then predict and analyze the scenario results, and finally determine the best polymer injection scenario to be applied in the BKH layer of YDP field. Based on the results of the study, it is shows that the scenario IV-A is the best scenario for polymer injection compared to other scenarios. Scenario IV-A performed by injection of polymer with a peripheral pattern with an additional 5 (five) injection wells, injection pressure of 1200 psi, injection rate of 300 bbl/d, polymer concentration of 0.6 lb/bbl, incremental recovery factor of 2.01%, and oil production cumulative obtained until December 2035 is 5087 MSTB.

Optical fiber flow sensor based on a lever-hinge configuration.

Based on a lever-hinge structure, a target-type fiber Bragg grating (FBG) flow sensor is proposed. Differential measurements of temperature and pressure are achieved using two FBGs. The design idea of the sensor is demonstrated from both theoretical and experimental aspects, and the relationship between FBG wavelength and temperature and the relationship between FBG wavelength and volume flow rate were established, respectively. The sensor is compact with good resolution, high stability, wide measurement range, and easy fabrication, and can be applied to measure temperature and volume flow rate in injection wells.

Predicting the magnitude of injection-induced earthquakes using machine learning techniques

Predicting the magnitude of injection-induced earthquakes using machine learning techniques

Modeling Fluid Flows in Oil Fields Using the Kalman Filter

In this paper, we present a statistical model of the relationship between injection and production wells on an oil field. The model is based on analysis of fluid flows occurring in the oil field; it is a modification of the Kalman filter model. An EM-algorithm for estimating the parameters of this model is developed.

Bayesian Monte Carlo Inversion of InSAR Time Series Deformation Induced by Wastewater Injection: A Case Study in West Texas

AbstractWastewater disposal can induce detectable surface uplift, which may cause ground instability and threaten infrastructure. The distributions of local hydro‐geomechanical parameters, especially Young's modulus and hydraulic conductivity, play an essential role in these geohazards. To constrain these parameters, we have inverted spatio‐temporal deformation measured by Interferometric Synthetic Aperture Radar (InSAR) and injection information using a Bayesian Monte Carlo approach with a poroelastic finite element model. Sentinel‐1A/B imagery from 2014 to 2020 is processed to track the spatio‐temporal deformation in Winkler county, West Texas, USA. The posterior distribution of subsurface effective volumes reveals under‐reported volumes in the well near the deformation center. In addition, the inversion results provide better constraints for the parameters than those solely obtained based on the cumulative spatial deformation or temporal development of the deformation center.

Evaluation of facial artery course variations, diameters, and depth by Doppler ultrasonography

The facial artery (FA) is the main blood vessel supplying blood to the face. It is essential to understand the anatomy of FA around the nasolabial fold (NLF). This study aimed to provide the detailed anatomy and relative positioning of FA to help avoid unexpected complications in plastic surgery. FA was observed from the inferior border of the mandible to the end of its terminal branch in 66 hemifaces of 33 patients with Doppler ultrasonography. The evaluation parameters were: (1) location, (2) diameter, (3) FA-skin depth, (4) relationship between the NLF and FA, (5) distance between the FA and significant surgical landmarks, and (6) the running layer. The FA course is classified based on the terminal branch. The most common FA course was Type 1, which had an angular branch as the final branch (59.1%). The most common FA-NLF relationship was that the FA was situated inferior to the NLF (50.0%). The mean FA diameter was 1.56±0.36mm at the mandibular origin, 1.40±0.37mm at the cheilion, and 1.32±0.34mm at the nasal ala. The FA diameter on the right hemiface was thicker than that on the left hemiface (p<0.05). The FA mainly terminates in the angular branch, running in the medial NLF and in dermis and subcutaneous tissue, with a blood supply advantage in the right hemisphere. We suppose that a deep injection into periosteum around the NLF may be safer than an injection into the superficial musculoaponeurotic system (SMAS) layer.

METHOD FOR ESTIMATING THE LENGTH OF MAN-CAUSED FRACTURE DEPENDING ON BOTTOMHOLE INJECTION PRESSURE

Most of Russia's recoverable oil reserves are hard-to-recover reserves. One of the key technologies for the development of these reservoirs is the use of a reservoir pressure maintenance system. The evolution of the development of flood control methods does not stand still. Today, the issue of studying the propagation of self-induced hydraulic fracturing cracks is one of the most important challenges. Over time, as the transition to the development of zones with low permeability values and an increase in down hole pressure in injection wells, the manifestation of the self-induced hydraulic fracturing effect began to be widespread. This was confirmed not only by the dynamics of the water content of products with an increase in the pick-up of neighboring injection wells, but also by hydrodynamic studies of wells, tracer studies, adaptation of the hydrodynamic model taking into account the cracks of the self-induced hydraulic fracturing. Over time, according to the results of studies of geomechanical properties in the deposits of Western Siberia, the direction of the regionally stressed state was established, which coincides with the azimuthal direction of the development of self-induced hydraulic fracturing cracks. Modern development systems take into account the direction of the regional stress state. These systems are mainly located parallel to the cracks of the self-induced hydraulic fracturing to exclude breakthroughs from injection wells to producing wells.&#x0D; Estimation of the parameters of auto-fracturing fractures depending on the injectionmodes is an urgent task that requires the creation of appropriate calculation methods. Control of the waterflood modes for a group of injection wells under conditions of critical bottomhole pressures exceeding the value of the rock fracture pressure is the purpose of this work. A method for estimating the parameters of man-caused fracture from given initial parameters is proposed.

ANALYSIS OF THE OPERATING RISKS OF HORIZONTAL FLARE UNITS UNDER UNSTEADY EQUIPMENT REGIME CONDITIONS

The article focuses on complications that arise when new water and gas injection wells are brought on regime and operation of horizontal flare units (HFU), which are part of the reservoir pressure maintenance (RPM) system in the simultaneous water and gas injection mode. In the process of bringing on regime there is a procedure to warm up and maintain working pressure in gas pipelines, for this purpose the associated petroleum gas is redirected to the HFU of the well pad. The existing design of the HFU does not allow maintaining technological parameters of gas injection into the well because of the lack of a regulating device in front of the HFU. The present article describes the measures aimed at ensuring stable operating pressure required when starting up new wells of the reservoir pressure maintenance system in the mode of simultaneous water and gas injection. Modernization of the existing HFU design with installation of a choke diaphragm, providing maintenance of operating pressure in the system of gas pipelines, is offered. The selection and calculation of the choke diaphragm were performed. The results of calculations of HFU with the new design of the choke diaphragm show the possibility of maintaining the working pressure in the gas pipeline when redirecting gas to the HFU during the launch, adding new water and gas injection wells in the system of reservoir pressure maintenance. Calculations of temperature distribution over the HFU surface are performed and dosages of hydrate inhibitor to ensure hydrate-free operation are specified.

TARASOVSKOYE OIL AND GAS CONDENSATE FIELD OIL FACILITY OBJECT BP14 DEVELOPMENT SYSTEM TRANSFORMATION RESULTS

In article, the technological effect of oil production increase by the inverted nine-point development system into a single-row system transformation is quantified. The anticipatory watering of the production wells located on the same row with the injection wells in the direction of regional stress in the inverted nine-point development system implemented at the oil facility BP14 object is shown. The effect of anticipatory watering is explained by the formation and growth of auto-hydraulic fractures on injection wells. With the effect and in order to increase the watering implementation coefficient the program of transferring highly watered and idle production wells to injection was started at the aim to form the single-row development system directed along the lineregional stress. Analysis of the ten-year project implementation actual results showed that the system transformation on BP14 object will increase the cumulative oil production on nearby 20 % on the latest stage of development.