Vertical Injection Wells Research Articles

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.

Stress and permeability modelling in depleted coal seams during CO2 storage

Depleted coal seam gas reservoirs are considered as one of the best sites for underground CO2 sequestration which can contribute to climate change mitigation. Due to coal's high internal surface area, a large amount of CO2 can be stored in the coal matrix. Despite the high CO2 storage capacity, the swelling of coal near the injection wells remains a major challenge. Most field trials have shown a significant decline in injection rate and permeability in the vicinity of vertical injection wells, while horizontal wells showed no such decline. It is not well studied how matrix swelling and well trajectory affect permeability in horizontal carbon dioxide injection wells. In this study, a mathematical model is developed to determine stress distribution and permeability around vertical and horizontal CO2 injection wells in depleted coal seams. The model incorporates injection pressure, matrix swelling effect, in situ stresses, and wellbore trajectory. The results indicate that during CO2 injection, matrix swelling significantly impacts the stress path and increases both horizontal stresses. Stress distribution and permeability around the well are affected significantly by wellbore trajectory and swelling. As CO2 injection continues in vertical wells, radial, tangential, and mean effective stresses increase near the well and within the reservoir. As a result, permeability declines during injection in a vertical well. In horizontal wells, however, tangential and mean horizontal stress near the wellbore decrease with injection. Hence, the model confirms no decline in permeability near a horizontal injection well which is in good agreement with the field trial observations.

Visualization Experimental Study on Well Spacing Optimization of SAGD with a Combination of Vertical and Horizontal Wells.

For oil sand reservoirs, the steam-assisted gravity drainage (SAGD) technique is one of the most efficient thermal recovery technologies. However, the high oil viscosity and the severe heat loss seriously affect the production effect of SAGD in developing thin oil sand reservoirs by the traditional SAGD technology. Therefore, it is essential to improve the SAGD technology to enhance the recovery of the thin oil sand reservoir. In this paper, SAGD with a combination of vertical and horizontal well (VH-SAGD) technology was adopted, and the influence of different well spacings (horizontal distance between vertical steam injection wells and horizontal production wells) on the development of steam chambers was investigated. By the similarity criterion, the experimental parameters were obtained. After that, an improved 2D visualization physical model was designed with 9 × 9 high-precision thermocouples installed inside the device to monitor the real-time temperature. This experimental physical model can not only accurately capture the temperature distribution but also display the continuous change process of the chamber inside the model by the visible window. Finally, different well spacing cases (10, 15, and 20 cm) were tested to observe the development of the steam chamber and analyze the production data. Both the temperature distribution and visual window showed that the steam chamber has four obvious stages, and reasonable well spacing can promote the development of the steam chamber. When the well spacing is relatively small, the unswept area of the cold oil on both sides is large, and the area of the steam chamber overlaps more. When the well spacing is relatively moderate, the steam chamber is the most complete and the recovery factor is the highest. When the well spacing is relatively large, although the unswept area of the cold oil on both sides is small, the middle cold oil area is larger than the previous two groups. Therefore, the best well spacing for oil sand reservoirs of about 15 m thickness is 15–20 m, where the VH-SAGD method has a better displacement effect and higher oil recovery. The experimental conclusions can provide theoretical support for the production of thin oil sand reservoirs.

An efficient method for injection well location optimization using Fast Marching Method

Well placement is one of the challenging steps in field development optimization. Finding optimal locations with fewer function evaluations and less time is crucial when dealing with giant models. In this study, we propose a method based on the combination of Fast Marching Method and Particle Swarm Optimization to decrease the number of function evaluations in optimizing the location of vertical injection wells. The idea is to restrict the optimization algorithm's search space to a region around the drainage boundary of producers. Thereby, the optimization algorithm can find good locations with fewer function evaluations compared to direct optimization. Drainage boundaries are predicted based on the diffusive time of flight (arrival time) calculated by the Fast Marching Method. First, the performance of the proposed method in predicting the drainage boundaries is evaluated by verifying the drainage boundary of four producers on two synthetic models using the fast marching method and streamline simulator which showed a good match. Next, the approach is applied to two- and three-dimensional example cases, including four synthetic models and a real field case to test the robustness and efficiency of the proposed method. Results are compared with the direct optimization approach and showed that the proposed approach can provide higher Net Present Values with fewer function evaluations most of the time. Finally, a comparison between the computational efficiency of the fast marching method and streamline simulator showed that the time needed by the fast marching method to predict the drainage boundary of the wells was orders of magnitude lower than the streamline simulator. • PSO-FMM is used to facilitate the process of finding good positions for injection wells. • PSO-FMM could find appropriate locations for the injectors with fewer function evaluations compared to direct optimization. • FMM could predict the drainage boundary of producers with satisfactory accuracy compared to streamline simulation. • Computational time required by FMM to estimate the drainage boundary was much lower than streamline simulation.

Scenario Reduction of Realizations Using Fast Marching Method in Robust Well Placement Optimization of Injectors

Choosing a representative subset of realizations can reduce significantly the number of simulations and the computational cost associated with optimization under geological uncertainty. Methods that use dynamic criteria, such as full flow simulators, can choose effectively representative realizations and reduce the number of simulations during optimization. However, these methods are expensive computationally. This study aims at investigating the effect of using diffusive time of flight (DTOF) as a feature to select a representative subset of realizations for well placement optimization under uncertainty. The proposed approach is based on the calculation of DTOF for pressure propagation in a reservoir; it was calculated using the fast marching method (FMM). To determine reservoir connectivity, a threshold was used for a number of grid blocks at specific time intervals; it can be used as a measure to evaluate and select the realizations. The proposed methodology was utilized to optimize the location of vertical injection wells on three numerical models, which are three dimensional with equally probable realizations. The optimization results of the proposed method were compared with the results of optimization using the full set and the subset realizations obtained using the K-means clustering method. In this study, 10 realizations were selected from the full set as the representative subset. The selection was based on K-means clustering and FMM. Results show that the FMM-based approach outperforms the clustering method and it can capture the uncertainty range with only a small subset of realizations with a much lower computational burden compared to the full set.

New approach to evaluate the performance of highly deviated water injection wells using artificial neural network

Water injection wells are used to improve the hydrocarbon recovery by maintaining the reservoir pressure and displacing the remaining oil into the production wells. Water injection wells can be vertical, deviated or horizontal wells. Highly deviated wells are used to improve the well injectivity and reduce the injection pressure. Several models were developed to determine the well injectivity for vertical or horizontal injection wells. However, few models are reported to estimate the performance of slanted or highly deviated wells. This study introduces a new approach to evaluate the performance of highly deviated wells used for the water injection applications.In this work, the well injectivity was determined utilizing the reservoir properties and the well geometry. Artificial neural network (ANN) was used to evaluate the injectivity index based on the reservoir thickness, formation permeability and well inclination. More than 550 cases were used to train and test the intelligent model. Two approaches were utilized to estimate the well injectivity; direct and indirect approaches. The reservoir thickness, formation permeability and well inclination were used as input parameters in the direct approach. While, in the indirect approach, all input parameters were combined into one input and then the well injectivity was determined using a single input parameter. Moreover, an empirical correlation was extracted utilizing the optimized ANN model. The extracted equation was verified using validation data, an average absolute difference (AAD) of 1.22 (STB/D/psi) was achieved indicating the effective performance of the developed ANN-based equation.The novelty of this work is that an effective approach is presented to evaluate the injectivity of highly deviated wells. The presented approach proved its reliability in predicting the well injectivity for heterogenous reservoirs. For the first time, an empirical correlation is extracted from the ANN model to estimate the injectivity index. The proposed ANN-based equation outperforms the popular models for determining the performance of highly deviated injection wells. The developed equation allows an accurate, easy and direct determination for the well injectivity for the highly deviated wells.

Optimization of well placement and operating conditions for various well patterns in CO2 sequestration in the Pohang Basin, Korea

The aquifer consists of multi-layers and has pre-existing faults and heterogeneous reservoir properties that restrict CO2 injection to a certain amount. To store large amounts of CO2 and maintain storage security, it is important to define the optimal injection well pattern, placement, and operating conditions. This study applied various well patterns and optimized their locations and fluid injection rates with monitoring the pressure build-up in the aquifer to improve the storage capacity. Four well patterns in this study were employed: (1) a single vertical injection well (SVI), (2) two vertical injection wells (TVI), (3) a single horizontal injection well (SHI), and (4) two vertical wells for brine extraction and CO2 injection (TVEI). The results showed TVEI at the optimal location and fluid rate that allowed an almost eight times larger volume of CO2 to be stored compared to the base case (simulation result of SVI drilled for the CO2 storage pilot project in the Pohang basin, Korea), and maintained the pressure within the boundary for security. When using a single well (SVI and SHI), SVI injected 126 kton of CO2, which is larger than that of SHI, but storage security of SHI is better than that of SVI due to the difference in CO2 migration. Through this research, the effects of various well patterns in CO2 geological storage in the Pohang Basin can be forecasted and the optimal well pattern and conditions for the largest storage capacity can be determined.

Numerical Simulation of the Impact of a CO2 Flood Pattern Size on Oil Recovery and Carbon Storage

Climate change legislation will not be able to incentivize energy stakeholders nor environmentalist to adopt carbon dioxide sequestration in the short term because of the cost associated with the technology. However, CO2 Enhanced Oil Recovery (CO2-EOR) has the potential to provide a win-win situation. One of the areas that can consider the implementation of this process are heavy oil reservoirs. The global heavy oil estimate is very large. For some countries it can help sustain their daily production simply by understanding reservoir behavior when CO2 is injected into the reservoirs. In recent times, other potential energy issues such as depleting resources and greenhouse gas emissions are playing a bigger role in defining what needs to be contemplated by many nations to obtain energy sustainability. This paper seeks to utilize numerical simulation using a commercial software to evaluate pattern size as a strategy for improving recovery in a heavy oil reservoir on the south east peninsula of Trinidad and Tobago (T&T). Some of these heavy oils can be recovered using conventional oil production followed by currently used enhanced oil recovery techniques. We focus our research on a injecting CO2 into a reservoir labelled field X with analogous data was used from fields in south-west Trinidad. Initially, a homogenous reservoir model was built using the compositional fluid model GMG-GEM and placed on primary production. These models were populated with vertical production and injection wells. Sensitivity analysis was then performed on three development scenarios: 160, 40, and 10 acre five-spots. We then developed a heterogeneous model using geostatistically-generated permeability. Based on the results shown, the 160 acre well spacing would be the most economic option; having a positive NPV and Cumulative Profit after taxes. Although the production was the lowest when compared to the other two patterns, coupled with the low CAPEX, the 160-acre spacing over the 55-year period would be best suited if we consider primary recovery only. While pipelines were found to be the better option for transport for the total 10-year period, the results reveal that trucking was the more attractive initial option; because of its low capital cost and flow-rates of CO2. Trucking initially is a more economic option for shorter injection periods and CO2 flow-rates when compared to pipelines however in the longer term, pipeline would be the better option. The CO2 utilisation rate ranges from 2-16MSCF/bbl over the 10 year injection period. In terms of CO2 storage, although the higher the injection volume, the greater the amount of CO2 stored for the scenarios that we have studied, the most economic case with storage would be the 160 acre spacing injecting a total of 40MSCF/D. However, if at any time there can be economic benefits derived from CO2 storage activities, the economics would drive the higher injection rates. From a storage point of view it is important to choose the right well spacing for not only oil production but for storage projects utilising depleted oil reservoirs. The results showed that on average the heterogeneous cases stored approximately 3% more CO2. For larger projects therefore, will have an impact on storage volumes. Once the reservoir remains unaffected by any breach, the CO2 will remain trapped mainly in the supercritical phase for at least 1000 years.

CO2MOVE Project: Testing CO2 Monitoring Methods for Onshore CCS

CO2 injection into geological reservoirs has been conducted for many years in Brazil as a method of Enhanced Oil Recovery, without the intention of geological storage. Recently, with pre-salt discoveries in ultra-deep waters and driven by the need to contain climate change, CO2 storage has become more relevant in the national energy production scenario. Therefore, one of the priorities in geological storage projects has been to demonstrate that CO2 is safely stored. This contributes to a better public perception of Carbon Capture and Storage (CCS) as a technological solution to reduce greenhouse gas (GHG) emissions in a short-term scenario. In Brazil, CO2 monitoring techniques and methodologies for onshore CCS purposes have been tested for 6 years supported by PETROBRAS in near-surface experiments with controlled CO2 releases. The first initiative in this sense started in 2012 with the Ressacada Project, in Florianopolis city (Santa Catarina state), and its activities are already closed. Since 2015 the CO2MOVE Project is under development in an area inside PUCRS campus, in Viamao city (Rio Grande do Sul state). This project involves more complex geological conditions and faces more challenges from the technological point of view. While in the Ressacada site prevailed quite sandy coastal marine sediments, the CO2MOVE site has a predominantly argillaceous soil, as a result of weathered granites. Local hydrogeology is characterized by a perched aquifer at about 1.5 meters depth, in which recharge depends on the local precipitation. CO2MOVE project is based on an automated injection system, capable of adding up to 50Kg of CO2 per day and a gaseous tracer injection module that allows incorporating tracers compounds to be tested as trackers of the injected CO2. Monitoring tools were arranged in an area of approximately 3000m2, occupying the entire region surrounding two vertical injection wells of 3 meters depth. Fieldwork involving injection and CO2 monitoring has been developed on two occasions. The first field season was conducted in 2016 for 60 days. The second campaign was conducted in 2017 for 15 days, aiming to obtain tracers response. This paper will present an overview of the CO2MOVE Project and the large experience acquired in these three years of research, approaching the behaviour of CO2 and tracers observed through the multiple research methods covered.

E&P Notes (January 2018)

E&P Notes Sakhalin-1 Extended-Reach Well Eclipses 15000 m Matt Zborowski, Technology Writer The Sakhalin-1 consortium has drilled a 15000-m horizontal well from the Orlan platform at Chayvo field in the Sea of Okhotsk, topping four previous wells drilled between 2013 and 2015 that reached between 12,450 ft and 13,500 ft. Partner Rosneft described the well as “super complex” with a 14129-m stepout drilled about 5 km offshore. Sakhalin-1 has been a proving ground for extended-reach drilling (ERD) technology since the first well was drilled there more than a decade ago. More recently, development well O-14 in 2015 was drilled to 13500 m, well Z-40 in 2014 reached 13000 m, and in 2013 wells Z-43 and Z-42 extended to 12450 m and 12700 m, respectively. Case Study: Drone Technology Inspection of UK North Sea Facility Stephen Whitfield, Senior Staff Writer Intel and Cyberhawk, a company that uses drones for asset inspection, released a case study in which commercial unmanned aerial vehicle (UAV) technology helped automate an existing oil and gas inspection workflow within a live structure. The study involved the successful inspection of a gas terminal in St. Fergus, Scotland, with the Intel Falcon 8+, a drone designed to provide unobstructed data capture for 3D reconstruction. The Falcon 8+ captured 1,100 images, translating to 12 GB of data, over the span of 2 days. The data could be used for asset maintenance including premaintenance inspection, repair work, resource planning, and maintenance prioritization. ConocoPhillips Brings Another North Slope Development on Production Matt Zborowski, Technology Writer ConocoPhillips’ operated 1H NEWS viscous oil development, or Northeast West Sak, has started production at the Kuparuk River Unit, 40 miles west of Prudhoe Bay on Alaska’s North Slope. The company expects 1H NEWS to flow 8,000 B/D at peak in 2018. The development, which involved a 9.3-acre extension to the existing Kuparuk Drill Site 1H, comprises 19 new wells with several vertical injection wells supporting horizontal multilateral production wells. Drilling began in August 2017. Production started 2 months ahead of schedule, ConocoPhillips said, adding that the project’s estimated cost of $400 million gross is $60 million lower than the company’s initial estimate. Permitting for 1H NEWS was announced in 2014, and funding and development for the project was approved in 2015. Total Boosts LNG Business With Purchase of Engie Assets Matt Zborowski, Technology Writer Total is expanding its global LNG presence by acquiring assets from Engie for up to $2.04 billion. The deal will provide the French supermajor with 2.5 million tonnes per annum (mtpa) of liquefaction capacity, including a 16.6% interest in Louisiana’s Cameron LNG export terminal—where three trains are under construction and two more can be added—as well as a 5% interest in the first train of Egypt’s Idku LNG project. Total will expand its portfolio of LNG purchase-and-sale contracts, adding supply from Algeria, Nigeria, Norway, Russia, Qatar, and the US with outlets between Europe and Asia. The firm also will gain access to 14 mtpa in regasification capacity in Europe and add 10 LNG tankers to its three existing carriers. AIME Releases Report on Council of Excellence Innovation Efforts The American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME) has released a report titled, “In Pursuit of Technological Innovation,” that outlines the goals and initial analysis of the AIME Council of Excellence, established in 2014 by Behrooz Fattahi, the AIME President at the time. The report is available for free download at www. aimehq.org/programs/collab-orative-efforts/council-of-excellence/article-1. The mission of the AIME Council of Excellence is to convene highly regarded technical experts representing the AIME member societies to continuously identify technologies (mature and/or leading edge) that might have innovative application in the industries served by these societies. These member societies include TMS (The Minerals, Metals, and Materials Society), SME (Society for Mining, Metallurgy, and Exploration), AIST (Association for Iron and Steel Technology), and SPE (Society of Petroleum Engineers). The 2003 TMS President, Dan Thoma, and 2007 TMS President, Robert Shull, are the TMS representatives to the Council of Excellence and coauthors of the report.

Reservoir Characterizations and Reservoir Performance of Mishrif Formation in Amara Oil Field

Mishrif Formation is the main reservoir in Amara Oil Field. It is divided into three units (MA, TZ1, and MB12). Geological model is important to build reservoir model that was built by Petrel -2009. FZI method was used to determine relationship between porosity and permeability for core data and permeability values for the uncored interval for Mishrif formation. A reservoir simulation model was adopted in this study using Eclipse 100. In this model, production history matching executed by production data for (AM1, AM4) wells since 2001 to 2015. Four different prediction cases have been suggested in the future performance of Mishrif reservoir for ten years extending from June 2015 to June 2025. The comparison has been made between these different cases to select the best case for developing the field that gives the highest recovery factor. The case-4 was chosen to be the best case involved adding 20 vertical production wells, 5 horizontal production wells and 5 vertical injection wells in the reservoir with plateau rate of 50MSTB/D in starting of prediction and dropping to reach 13.5 MSTB/D in end of the prediction and the cumulative production from the reservoir equal to 82 MMSTB and recovery factor reaching 9.06% at the end of 2025.

Determination of vertical/horizontal well type from generalized field development optimization

Field development planning entails determination of the optimal number of wells (horizontal/vertical), well types (producer/injector), well locations, and well controls. The numerous variables to be estimated and the reservoir geological uncertainty complicate the problem of determining the optimal development plan. The improvements in computational science have advanced the use of automated optimization for field development decisions.In this paper, we present a generalized field development optimization methodology for estimating vertical and horizontal well-types in developing a hydrocarbon reservoir. Two approaches for the generalized field development optimization are presented. One approach is based on the well control zonation (WCZ) procedure; the other is based on the mixed integer non-linear programming (MINLP) procedure. In the WCZ procedure, five zones were identified, each signifying a region of either horizontal injection wells, vertical injection wells, no wells, vertical production wells or horizontal production wells. In the MINLP approach, separate variables were defined for the determination of the well type. Additionally, we present an efficient method to constrain the minimum well spacing of the horizontal and vertical wells to predetermined parameters. The aim was to optimize the number of wells, the well types, the well locations and the well controls (production rates). These operational variables were estimated simultaneously. Particle swarm optimization (PSO) algorithm was used as an optimizer to determine the optimal parameter values.The WCZ and MINLP approaches were tested with two examples to determine which methodology was more effective. The results indicated that both methods could successfully determine the optimal parameters while satisfying the spacing constraints imposed by the user. The comparison of the results showed that the WCZ approach was more effective than the MINLP approach.

CO2MOVE Project: The New Brazilian Field Lab Fully Dedicated to CO2 MMV Experiments

After the Ressacada Project experience acquired from 2011 to 2015 when PUCRS, UNESP and other institutions conducted three controlled CO2 release experiments, PETROBRAS, the national oil company that is sponsoring the project, has launched a new challenge to its partners. The company stimulated the implementation of a new Brazilian experimental site where there will be a deepening of studies in geologically more complex conditions and more challenging from a technological point of view.The choice of an area inside PUCRS campus, in Viamão - Rio Grande do Sul state, was motivated by a predominantly clay subsoil and the privileged location of the site in terms of ease logistics and security, which is required for a project of this size that houses high-tech equipment with significant cost.The CO2MOVE project started at 2015 with the subsurface characterization of the site and the assembly and manufacture of an automated system for CO2 and gas tracers with injection capacity for 5 to 50 kg/day. Based on physical characterization studies and on numerical modeling that is being developed, the site infrastructure will be completed in the next months with the positioning of vertical injection wells, monitoring wells, and other equipment and monitoring mesh.Monitoring tools should be arranged in an area of approximately 100m2, occupying the entire region surrounding the injection wells. Fieldwork involving CO2 injection and monitoring should have a 60 days duration of which 15 days are for preliminary surveys (pre-injection), 30 days for injection and CO2 monitoring and the last 15 days for post-injection measurements. Following this work, the collected data will be analyzed in the university labs.Similarly to Ressacada Project, this experiment will run measurements of soil CO2 flux with accumulation chambers, CO2 turbulent fluxes with Eddy Covariance, subsurface gases and groundwater monitoring, and resistivity measurements. Other monitoring methods still not tested by the research team will be held as gas tracers monitoring and laser measurements.

Guest Editorial: Why Can’t We Apply Advanced Technologies More Often to Vertical Wells in Mature Fields?

Guest editorial When I started working in the oil and gas business in the 1970s, we spent a great deal of time designing vertical wells. The horizontal well was by and large a far-fetched idea on everyone’s wish list—the capability to have a completion go through the sweet spot was almost too good to be true. Fast forward to 2017 and we are now drilling horizontals everywhere, surpassing drilling times again and again. But what about vertical wells, are we not still drilling those? The answer is “Yes, we are.” From 2011 to 2016, the industry drilled 117,624 vertical wells in the United States while, in that same time frame, it drilled 84,200 horizontals. The fact is, vertical wells still have several key applications: They are typically used as the preliminary wellbore in exploration, production, and acreage delineation, and can be used for infill drilling, injection, and disposal. So, can we not apply advanced technologies more often to mature vertical wells? We can, but two factors need to be considered when doing so—technology and cost. First, embracing advanced technologies. Some energy and production companies lead the way in innovation while others are more risk-adverse. Regardless, new technologies are consistently being developed, refined, and eventually adopted more broadly. For example, vertical injection wells can be refractured using more advanced diversion technology, ultimately extending the life of the well or even potentially adding more reserves. Or we can accurately apply acid in a vertical well to establish better communication with a reservoir. Such applications are now part of the mature field landscape, but the widespread adoption of newer technologies often moves at a glacial pace. The second factor is cost. We know that the application of advanced technologies can prolong the life of mature fields, but it has to be done cost-effectively. Mature fields are exceptionally cost-sensitive, and any high-dollar application must yield acceptable returns: You are not going to pump an expensive chemical into a well for a 0.5% return—it just does not make sense. Looking ahead, the well intervention market for mature fields will be demanding more and more of our attention. By 2019, it is expected to be in the range of USD 13 billion per year globally.

Near-Wellbore and Reservoir Effects in In-Situ Combustion

Summary To operate fields under in-situ combustion (ISC), the near-wellbore dynamics and far-field conditions have to be considered. In the near-wellbore region of vertical injection wells, the flow advancement of the combustion front is characterized by high velocities. Farther away from the injection wells, the advancement rate of the combustion front is much smaller. For a line-drive configuration, the advancement of the front slows down from several meters per day near the wellbore to several centimeters per day in the far-field region. To investigate the effects in the near-wellbore region and far-field conditions, laboratory experiments and simulations were performed and compared with the behavior of a Central European field produced by using ISC. The laboratory experiments covered the kinetics in the near-wellbore region as well as the far-field region by applying various heating rates and by preheating a kinetic cell before injecting air. The dynamic effects were investigated with a combustion tube. Mechanistic numerical simulation was based on the kinetics derived from the kinetic-cell experiments and applied to the combustion tube. The same set of conditions was then used to simulate the near-wellbore conditions in the Central European field and far-field conditions. The results show that, in the near-wellbore region, the advancement of the combustion front is fast compared with heat conduction ahead of the front. Hence, low-temperature-oxidation (LTO) reactions and high-temperature-oxidation (HTO) reactions, as derived from the kinetic-cell experiments, are occurring in different distances from the injection well. In the far field, heat conduction ahead of the front and the flow of hot combustion gases preheat the reservoir before oxygen arriving at the combustion front. For these conditions, LTO and HTO reactions are occurring at the same location. In the Central European field produced with ISC, the various operating conditions are shown at an example well. Four different phases of production can be seen: (1) oil production with cyclic steam stimulation (CSS), (2) shut-in of the well to stabilize the combustion front that is approaching, (3) oil-production response of the combustion front, and (4) conversion of the well for air injection. The air-injection rate is slowly increased to avoid too-high temperatures in the early-injection phase (faster advancement of the heat front than heat conduction). The distance of the wells is approximately 70 m to allow sufficient oil recovery per well and speed of the combustion front.

A field-scale investigation of residual and dissolution trapping of CO2 in a saline formation in Western Australia

In a typical carbon capture and storage project, residual and dissolution trapping is expected to play a significant role in minimising the risk associated with the containment. Various methods of maximising each trapping mechanism individually have been proposed in the literature. Yet, in actual projects, it is expected that these trapping mechanisms occur interactively. This area still remains unexplored.This paper presents the results of a numerical investigation of technically feasible engineering designs to co-optimise both trapping mechanisms. It integrates a geological model developed for an actual saline formation in Australia, along with other available reservoir engineering data using a compositional numerical reservoir simulator. The scenario involves injecting supercritical CO2 at a commercial rate into a thick, deep, layered, heterogeneous, high porosity, high-permeability sandstone formation that initially contains only water of high salinity. The design objective is to inject more than 200 million tonnes of CO2 over 40 years. Compositional interactions between formation water and injected CO2 are modelled using the Peng–Robinson equation of state. We examine different injection schemes to find out the scenario that maximises dissolution and residual trapping. These schemes include vertical wells, horizontal wells, water alternate gas injection (WAG) and simultaneous water and gas injection (SWAG).The results show that heterogeneity has a significant effect on the location of perforations. The middle region of the Wonnerup Member appears to be the optimum location for CO2 injection where desired amount of CO2 can be injected while a maximum benefit of residual trapping can be achieved. Horizontal wells appear to enhance residual trapping the most, whereas WAG enhances dissolution trapping the most. Furthermore, WAG scenarios result in the least mobile CO2, and therefore, show the highest cumulative potential for both residual and dissolution trapping. However, in terms of relative economics, vertical injection wells appear to be the most viable option.

A pseudo-SAGD scoping model for evaluating economic viability of heavy oil projects

Abstract Unlike the Canadian heavy oil and bitumen resources, which are mainly produced using steam assisted gravity drainage (SAGD) process, production from many of the US heavy oil reservoirs relies on steam injection through vertical wells. To utilize existing vertical injection wells and other surface infrastructure, conventional steam flooding projects may be modified to operate in a pseudo-SAGD mode that use vertical steam injection and horizontal production wells. However a preliminary feasibility study is necessary to reliably analyze a single well pair as a stand-alone project before launching comprehensive simulation studies. For this purpose, a reservoir scoping model coupled with economic analysis template that is easy to apply and use by individual reservoir engineers, was developed. The scoping model was then used to evaluate the economic viability of a heavy oil lease in California. The scoping model developed in the present study is based on two well-known models namely the Jones model and the Sawhney, Liebe, and Butler model. The model results are comparable with the reported performance of two heavy oil horizontal well projects in the San Joaquin Valley, California, that used vertical steam injection scheme. The economic template is capable of handling a multitude of different scenarios. Any variable can be readily changed to allow users not only to forecast specific scenarios but also to see what variables will have greatest impact on project viability. The scoping model results suggest that the studied heavy oil lease can be effectively produced in pseudo-SAGD mode. Steam flood application with vertical injection wells at a rate of 246 barrels of cold water equivalent (BCWE/D) per well is determined to effectively promote oil production in a horizontal well at rates over 500 barrels per day (BOPD) for several years. The life span of the project is expected to be to 10 years with an initial capital investment of 6.5 million dollars. Even at relatively high minimal acceptable rate of return (MARR) of 42.5%, the project remains an economical venture with minimum oil price of $84/barrel at the beginning of the project with an annual increase of 2.5% in oil price during the project span. In a downside scenario of $50/barrel crude oil price and 40% tax on income, project can be still economically viable, if 22% or less MARR is acceptable.

A study on development effect of horizontal well with SRV in unconventional tight oil reservoir

Unconventional tight oil and gas are the main body of the increase of reserve and production in Ordos Basin. Based on the tight oil reservoir in Ordos Basin, a 7 point pattern well group numerical mechanism model with a multi-stage and multi-cluster horizontal production well in the middle and 6 vertical injection wells on the edge is established. PR3 equation of state model is used in the numerical model. The stimulated reservoir volume of horizontal well is realized by local grid refinement, and the wire-mesh model is used to simulation hydraulic fracture network. Application of the model, the development effect factors of tight oil reservoir are analyzed, which contain development methods (depletion development, water flooding development and CO2 flooding development), reservoir permeability, SRV size, fracture density, fracture conductivity and cluster spacing. The results of this paper can offer suggestions to fractured horizontal well design and tight oil reservoir development.

Effect of well pattern and injection well type on the CO2-assisted gravity drainage enhanced oil recovery

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 secondary immiscible and miscible modes under the conditions of voidage balance, constant pressure of injection and production wells 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.

Increasing of Oil Field Productivity by Implementation of Re-entry Horizontal Injection Well, Case study

Water flooding is one of the most important methods used in enhanced production; it was a pioneer method in use, but the development of technology within the oil industry, takes this subject toward another form in the oil production and application in oil fields with all types of oils and oil reservoirs. Now days most of the injection wells directed from the vertical to re-entry of full horizontal wells in order to get full of horizontal wells advantages.This paper describes the potential benefits for using of re-entry horizontal injection wells as well as combination of re –entry horizontal injection and production wells. Al Qurainat productive sector was selected for study, which is one of the four main productive sectors of South Rumaila oil field. A simulation model – named as SRFQ was used in the present work to predict the re-entry horizontal wells performance.Four scenarios were suggested to cover the full scope of the study; those scenarios are different in manner of wells combinations. Cumulative oil production, ultimate recovery percentage are two criteria were used to predict the performance and comparison of scenarios.Results from simulation model (SRFQ) runs revealed that the productive sector can be continue to gain 1564.331 MMSTB till 2020, without changing to any existing injection and production wells status, which is called the base scenario. While scenario no.1 needs some of work over and remedies jobs, which gives more cumulative oil production reaches to 1698.481 MMSTB till 2020.On another side, scenarios no. 2 and 4 are the most important scenarios because re-entry horizontal injection wells were implemented. Very good and encourage results were gained over the bas scenario from the sector under study.At last, scenario no.3 was suggested just to predict the production capacity of the Al Qurainat sector with re-entry horizontal production wells and existing vertical injection and production wells, while the cumulative oil production reaches 3398.481MMSTB.