Number Of Production Wells Research Articles

E&P Notes (June 2021)

E&P Notes (June 2021)

The Application of Numerical Simulation Result for Geothermal Financial Model with Probabilistic Approach: A Comprehensive Study

Feasibility of developing a geothermal project depends on the financial return generated from the investment. One of the strategies to achieve optimum return is formulating a financial model with a high level of confidence. Technical input parameters in the financial model are determined by the amount of available geothermal reserve in the form of a field development scenario. The best method for predicting geothermal reserve is a numerical simulation. The objective of this study is to determine the electricity tariff to generate 30 MW, 60 MW, and 110 MW which meet the 50% of the Rate of Return value will be equal or not exceed 16% (P50) for a specific geothermal field with a probabilistic approach. This study started with determining the technical input parameters: the number of production wells; make­up wells; and injection wells from each development scenarios based on numerical simulation result that has been studied by another researcher. The electricity tariff that meets the P50 of Rate of Return at 16% was calculated for those scenarios. Then, the tariffs were evaluated based on the Average Cost of Electricity Generation (BPP) on the relevant local grid. The result shows that the tariff or/and generation cost need to be negotiated. Moreover, total investment and economic indicators forecasting indicated that the investment was attractive. Lastly, sensitivity analysis shows that Rate of Return strongly affected by well drilling cost and power plant cost (EPCC).

Application of numerical models to assess multi-source saltwater intrusion under natural and pumping conditions in the Great Maputo aquifer, Mozambique

Regional three-dimensional groundwater-flow and saltwater transport models were built to analyse saltwater intrusion in the Great Maputo area, southern Mozambique. Increased water demand has led to many private groundwater abstractions, as the local public water supply network has already reached maximum capacity. Pushing for new strategies to tackle the water-supply shortages exposes the aquifer system to saltwater intrusion from entrapped fossil saline groundwater and seawater. Previous attempts at modelling have been frustrated by data limitations. This study compiled all the available data to build the models, which were subsequently calibrated with observed heads, discharges and salt concentrations. The transport models were used to test hypotheses of potential sources of saltwater resulting in the current salinity distribution. Furthermore, scenarios were simulated to assess the impacts of sea-level rise and projected groundwater abstractions. Results show that saline groundwater is widely distributed in the aquifer’s western sector, where it is a limiting factor for groundwater development, and seawater intrusion is a risk along the coastline. Newly constructed wells (46) along the Infulene River can be operated with some impacts of saltwater upconing and must be closely monitored. Although current groundwater abstractions (60,340 m3/day) are still small compared with groundwater recharge (980,823 m3/day), larger volumes of abstraction are feasible only when using a high number of production wells further away from the city with relatively low yields to avoid saltwater upconing. Capture of fresh groundwater upstream of discharge areas by wells for water supply is possible while maintaining groundwater discharges for groundwater dependent ecosystems.

An Investigation into Sub-Critical Choke Flow Performance in High Rate Gas Condensate Wells

There have been some correlations in the literature to predict the gas and liquid flow rate through wellhead chokes under subcritical flow conditions. The majority of these empirical correlations have been developed based on limited production data sets that were collected from a small number of fields. Therefore, these correlations are valid within the parameter variation ranges of those fields. If such correlations are used elsewhere for the prediction of the subcritical choke flow performance of the other fields, significant errors will occur. Additionally, there are only a few empirical correlations for sub-critical choke flow performance in high rate gas condensate wells. These led the authors to develop a new empirical correlation based on a wider production data set from different gas condensate fields in the world; 234 production data points were collected from a large number of production wells in twenty different gas condensate fields with diverse reservoir conditions and different production histories. A non-linear regression analysis method was applied to their production. The new correlation was validated with a new set of data points from some other production wells to confirm the accuracy of the established correlation. The results show that the new correlation had minimal errors and predicted the gas flow rate more accurately than the other three existing models over a wider range of parameter variation ranges.

Seafloor subsidence induced by gas recovery from a hydrate-bearing sediment using multiple well system

Abstract The response behavior of the methane exploitation from natural gas hydrate (NGH) using multiple well system is complex and needs to be investigated, as gas production from a single vertical well generally cannot meet commercial demand. This study numerically investigates the production performance and geomechanical response of an unconfined hydrate deposit in Shenhu area, South China Sea, under single and multiple vertical well conditions. For a single vertical well with a mild constant bottom-hole pressure, gas production is relatively stable. However, seafloor subsidence exhibits an initial rapid drop and a subsequent mild drop stage. The vertical displacement is highly developed at the top and bottom of the production zone. The results from doublet and triplet vertical wells indicate that both the gas and water production and seafloor subsidence increase with the increase in number of production wells. The superimposition of subsidence leads to a deterioration in subsidence and the change in location for the largest subsidence, which may affect the risk location of well instability. The interference of pore pressure and subsidence increases with the decrease in well spacing. However, gas production decreases and water production changes insignificantly. Furthermore, a same subsidence at seafloor cannot indicate the same evolution of subsidence in the vertical and lateral direction. The results presented in this study help in balancing the production and subsidence of the NGH exploitation in complex well configurations.

Quality of surface and underground water at the resorts of the Caucasian Mineral Water regions — problems and solutions

The results of long-term environmental monitoring of small rivers in the Caucasian Mineral Waters resorts region are presented. The characteristics of the surface water and groundwater at the resorts are considered. The degree and nature of their pollution were evaluated, and the main causes of water pollution in the region—including heavy-metal compounds, petroleum products, and nitrogen-containing compounds—were identified and analyzed. Data on mineral water from a number of production wells that are not compliant with the requirements of GOST R 54316-2011 are given. The analysis of hydrogeodynamic and hydrogeochemical regimes of exploitation of the Kislovodskoye field, recommendations for improving the quality indicators of the main source of the “Narzan” field are given.

A Study on the CO2-Enhanced Water Recovery Efficiency and Reservoir Pressure Control Strategies

CO2 geological storage (CGS) proved to be an effective way to mitigate greenhouse gas emissions, and CO2-enhanced water recovery (CO2-EWR) technology may improve the efficiency of CO2 injection and saline water production with potential economic value as a means of storing CO2 and supplying cooling water to power plants. Moreover, the continuous injection of CO2 may cause a sharp increase for pressure in the reservoir system, so it is important to determine reasonable reservoir pressure control strategies to ensure the safety of the CGS project. Based upon the typical formation parameters of the China Geological Survey CO2-EWR test site in the eastern Junggar Basin, a series of three-dimensional (3D) injection-extraction models with fully coupled wellbores and reservoirs were established to evaluate the effect of the number of production wells and the well spacing on the enhanced efficiency of CO2 storage and saline production. The optimal key parameters that control reservoir pressure evolution over time are determined. The numerical results show that a smaller spacing between injection and production wells and a larger number of production wells can enhance not only the CO2 injection capacity but also the saline water production capacity. The effect of the number of production wells on the injection capacity and production capacity is more significant than that of well spacing, and the simulation scenario with 2 production wells, one injection well, and a well spacing of 2 km is more reasonable in the demonstration project of Junggar Basin. CO2-EWR technology can effectively control the evolution of the reservoir pressure and offset the sharp increase in reservoir pressure caused by CO2 injection and the sharp decrease of reservoir pressure caused by saline production. The main controlling factors of pressure evolution at a certain spatial point in a reservoir change with time. The monitoring pressure drops at the beginning and is controlled by the extraction of water. Subsequently, the injection of CO2 plays a dominant role in the increase of reservoir pressure. Overall, the results of analysis provide a guide and reference for the CO2-EWR site selection, as well as the practical placement of wells.

A new method to determine reasonable well pattern density in low-permeability gas reservoirs

The productivity evaluation of gas reservoirs is used to determine the optimal number of well pattern, which is an important part of the preparation of gas reservoir development plan. Using integral transformation and asymptotic analyses to solve the pseudo steady-state flow model in closed rectangular gas reservoir of constant thickness, analytic solution of pressure distribution of eccentric well can be obtained. This paper presents mathematical model of multiple wells producing from a closed gas reservoir by applying the principle of pressure superposition. The pseudo steady-state dimensionless production index is introduced to solve the multiple well mathematical models under the constant pressure, and the number of production wells and cumulative production in different production interval are obtained. The results of the calculation shows that the curve of the cumulative production and economic benefits have a maximum value when the producing time, gas price, and drilling costs are given, so it can determine the optimal number of wells and provide the basis for making gas reservoir development plan.

An accurate method for permeability evaluation of undersaturated coalbed methane reservoirs using early dewatering data

Accurate determination of permeability is critical for the efficient development of coalbed methane (CBM) reservoirs. Permeability determination is mainly based on the feature straight-line analysis method and the plate fitting method requiring pressure build-up data. Although few analytical methods only require dynamic production data, they usually have limitations in application due to complicated solution processes or insufficient consideration of CBM reservoir characteristics.This study improves the previous method for determining the permeability of undersaturated CBM reservoirs. Firstly, mathematical models are established for calculating permeability of undersaturated CBM reservoirs with constant permeability and variable permeability due to pulverized coal output/blockage, matrix shrinkage, and stress dependence during the production process. Secondly, the proposed models are validated by numerical simulation, analytical, and pressure build-up test methods. Finally, the models are applied to the Muai CBM reservoir in Sichuan Basin, China. High-, middle-, and low-permeability zones of the Muai reservoir are classified.The results show that when bottom-hole pressure and water production data of CBM wells during single-phase water flow period are processed by the proposed method and plotted in a rectangular coordinate system, a strong linear relationship can be obtained for CBM reservoirs with constant permeability and variable permeability. The slope of the fitted equations can be used to determine permeability efficiently and accurately. Compared with previous methods, the new method provides better interpretation results for CBM wells with strongly fluctuating production data since the use of the integration of fluctuating data and cumulative water production reduce the effect of production fluctuation on the results.Due to its conciseness, this method can rapidly calculate reservoir permeability around a large number of production wells and obtain permeability distribution in the reservoir, providing guidance for CBM productivity forecasting and development policy adjustment.

Security of Storage in Carbon Dioxide Enhanced Oil Recovery

The Pembina Cardium CO2 Monitoring Pilot was used as a test site to determine the relative roles of trapping mechanisms. Two methods to assess this distribution are presented. A geochemical approach using empirical data from the site was used to determine the phase distribution of CO2 at a number of production wells that were sampled monthly during a two-year CO2 injection pilot. In addition, a simplified reservoir simulation was performed. Results indicate that significant amounts of CO2 are stored in the oil phase thus reducing the amount of CO2 available as a buoyant free phase and hence increasing storage security.

DEVELOPMENT AND RESEARCHING OF DRILLING FLUIDS PROPERTIES TO CARRY OUT WORKS UNDER CONDITIONS OF ABNORMALLY HIGH RESERVOIR PRESSURES

The article presents systematization and comparative analysis of the killing the well technologiesusing fluids based on organic and inorganic salts. Based on its results it was found that the common practicein Ukraine to kill the wells with abnormally high reservoir pressure is to use clay weighted drilling muds.In order to develop solutions requiring minimum funds for manufacturing of selectedreagents, it was specified the list of drilling fluids for further research and development to carry outworks under conditions of abnormally high reservoir pressures.The article shows the results of research of drilling fluids composition such as solubility inacid and corrosive action. Based on those parameters, the optimum types of fluids for Ukrainianfields, with abnormally high reservoir pressure, were chosen.In Ukraine the number of production wells that are moving to the final stage of developmentis growing every year, which increases the need for workover operations. Each undergroundoperation of well workover is necessarily accompanied by killing the well with furthertechnological completion after the casing repairing. Qualitative fluid with minimal corrosion actionfor killing the wells is the key to success in further completion, testing and exploitation.

Analisis Performance Sumur X Menggunakan Metode Standing Dari Data Pressure Build Up Testing

The number of production wells refers to the performance of the well, which is shown in the graph of inflow performance relationship (IPR). Reservoir characteristics influence on performance of the well, type of welltest and methods that be used in the determination of IPR. By using the IPR curves, maximum flow rate and the optimal flow rate of the well will be known. Pressure Build Up test is used to know performance and a maximum flow rate of the X well. Well test conducted for 15 hours. The well produced at a constant flow rate than close the wellhead. The Pressure data and time data obtained from the well test. The result of Pressure build-up testing analysis among permeability, skin and flow efficiency. After analyzing the Pressure build-up testing permeability obtained 190 mD, skin + 1,68 and 0,83 flow efficiency. Based on the value of flow efficiency Standing method is the most appropriate method is used to analyze the productivity of X well. Standing appropriate method for wells with skin ≠ 0 and flow efficiency ≠ 1. The maximum flow rate of the X well using Standing Method on the 0,83 flow efficiency was 13,91 MMSCFD

A meta-study of the effect of thermodynamic parameters on the efficiency of geothermal power plants worldwide

As global energy demand rises, the search for viable alternative fuel sources continues. The practicality of geothermal energy to meet this demand is highly dependent on optimizing thermal efficiency. While geothermal energy is currently used in places like Western Australia for direct-heat applications such as leisure centres, developing a geothermal power plant in such an area depends on predicting which thermodynamic parameters optimize thermal efficiency. This meta-study focuses on the effect of geothermal operation parameters such as inlet pressure, temperature, mass flow rate, well depth and number of production wells on the thermal efficiency of geothermal power plants. Drawing data from 61 geothermal power plants around the world ranging in design capacity (MWe) and size, a meta-study on the thermal efficiency of plants operating under different thermodynamic cycles, namely single-flash, double-flash, binary Organic Rankine Cycle (ORC) and Kalina, is offered. These various thermodynamic parameters are analysed to determine the presence of observable thermal efficiency patterns or trends that may lead to the optimization of operation parameters for new geothermal plants. Based on the available published data reviewed, there are few trends which indicate how geothermal operation parameters affect thermal efficiency. Well depth may be an indicator of efficiency for geothermal power plants using ORC and double-flash cycles, however further data is required to support this conclusion.

The Use of Tracer Data To Determine Polymer-Flooding Effects in a Heterogeneous Reservoir, 8 Torton Horizon Reservoir, Matzen Field, Austria

Summary Polymer-injection pilot projects aim at reducing the uncertainty and risk of full-field polymer-flood implementation. The interpretation of polymer-pilot projects is challenging because of the complexity of the process and fluids moving out of the polymer-pilot area. The interpretation is increasingly more complicated with the heterogeneity of the reservoir. In the polymer pilot performed in the 8 Torton Horizon (TH) reservoir of the Matzen field in Austria, a polymer-injection well surrounded by a number of production wells was selected. A tracer was injected 1 week before polymer injection. The tracer showed that the flow field in the reservoir was dramatically modified with increasing amounts of polymer injected. Despite short breakthrough times of 4 to 10 weeks observed for the tracer, polymer breakthrough occurred only after more than 12 months although injection and production rates were not substantially changed. The tracer signal indicated that the reservoir is heterogeneous, with high flow velocities occurring along a number of flow paths with a limited volume that are strongly connecting the injection and production wells. By injecting polymers, the mobility of the polymer-augmented water was reduced compared with water injection, and led to flow diversion into adjacent layers. The tracer response showed that the speed of the tracer moving from injection to production wells was reduced with increasing amount of polymer injected. This response was used to assess the changes of the amount of water flowing from the injection well to production wells. After a match for the tracer curve was obtained, adsorption, residual resistance factor (RRF), and dispersivity were calculated. The results showed that, even for heterogeneous reservoirs without good conformance of the pilot, the critical parameters for polymer-injection projects can be assessed by analyzing tracer and polymer response. These parameters are required to determine whether implementation of polymer injection at field scale is economically attractive. Along the flow path that is connecting injection and production well, as shown by the tracer response, an incremental recovery of approximately 8% was achieved. The polymer retention and inaccessible pore volume (IPV) in the reservoir were in the same range as in corefloods. Incremental oil recovery caused by acceleration along the flow path was estimated at approximately 20% of the overall incremental oil production caused by polymer injection and 80% was attributed to improved sweep efficiency.

Optimization of enhanced coal-bed methane recovery using numerical simulation

Although the enhanced coal-bed methane (ECBM) recovery process is one of the potential coal bed methane production enhancement techniques, the effectiveness of the process is greatly dependent on the seam and the injecting gas properties. This study has therefore aimed to obtain a comprehensive knowledge of all possible major ECBM process-enhancing techniques by developing a novel 3D numerical model by considering a typical coal seam using the COMET 3 reservoir simulator. Interestingly, according to the results of the model, the generally accepted concept that there is greater CBM (coal-bed methane) production enhancement from CO2 injection, compared to the traditional water removal technique, is true only for high CO2 injection pressures. Generally, the ECBM process can be accelerated by using increased CO2 injection pressures and reduced temperatures, which are mainly related to the coal seam pore space expansion and reduced CO2 adsorption capacity, respectively. The model shows the negative influences of increased coal seam depth and moisture content on ECBM process optimization due to the reduced pore space under these conditions. However, the injection pressure plays a dominant role in the process optimization. Although the addition of a small amount of N2 into the injecting CO2 can greatly enhance the methane production process, the safe N2 percentage in the injection gas should be carefully predetermined as it causes early breakthroughs in CO2 and N2 in the methane production well. An increased number of production wells may not have a significant influence on long-term CH4 production (50 years for the selected coal seam), although it significantly enhances short-term CH4 production (10 years for the selected coal seam). Interestingly, increasing the number of injection and production wells may have a negative influence on CBM production due to the coincidence of pressure contours created by each well and the mixing of injected CO2 with CH4.

A Comprehensive Evaluation of SAGD and Fast-SAGD Application in Three Major Formations of Alberta's Oil Sand

This article presented a comparative evaluation between the conventional SAGD and the Fast-SAGD application in three typical formations of Alberta's Oil Sand that included McMurray, Clearwater, and Bluesky formations. Three reservoir models with a series of numerical simulations under various operation conditions were developed to achieve the most unprejudiced comparison between two bitumen recovery processes. The simulation results proved that significantly recoverable bitumen was produced from offset wells in the Fast-SAGD system and leads to a higher recovery factor. There is only a slight increase in cumulative oil recovery when two processes were performed in the same pattern with a similar number of production wells. The results also indicated that the difference of 10 kPa between steam injection pressure and reservoir pressure in the literature is not enough for both SAGD and Fast-SAGD operations. Finally, a precious guideline was recommended in order to achieve the most success on SAGD and Fast-SAGD application at those formations.

Optimal Control of Petroleum Reservoirs

The flow of fluids in a petroleum reservoir can be modeled using a set of nonlinear second order partial differential equations. To produce the fluids, especially oil, a number of production wells are drilled through the reservoir formations. The well model, which describes the interaction between the well and the reservoir, can be considered as the boundary conditions for the flow equations. The amount of produced fluid is usually controlled by changing the bottom hole pressures via control valves. Because the reservoir could contain undesirable fluids, e.g., water or gas, setting the bottom hole pressures to the maximum production limit could cause high water or gas production, which would decrease the oil revenue. The present paper describes an optimal control method for maximizing the oil revenue in petroleum reservoir systems. The flow equation is discretized in a space variable to yield a state space representation model. The valve openings are considered as the control variables and are written as piecewise constant functions. Furthermore, the gradient of the oil revenue with respect to the control variable is computed using the adjoint method and the optimal control setting is obtained using a line search method. A numerical example of a water-flooding case is presented to illustrate the application of the method.

Effective-Well Method for Matching and Predicting Oil Production

Decline curve analysis (DCA) is a traditional method for production prediction, which is still being used because it works in many cases and it is relatively simple to apply. However, DCA methods can neither match nor predict the fluctuating oil production during the early period when applied to entire reservoirs. The change in oil production may be because of variation in production conditions or the number of injection/production wells. In this study, we focused on the latter problem, change in the number of production wells. Obviously, there would be a significant oil production boost during a specific time period if more oil wells are drilled. The traditional DCA approach cannot match the increase in oil production due to the increase in the number of oil production wells. We have developed a method to match the oil production of entire reservoirs for the life span by considering the change in the number of production wells. The main idea of this approach came from the concept of effective wells. We applied this approach in several sandstone oil reservoirs with different permeabilities. The proposed effective-well model could match the oil production data in different reservoirs, even during the early period of production when the oil production rate change with time because of the variation in the number of producers. Comparison with the existing models (exponential, hyperbolic model, and harmonic models) was made and the results showed the proposed approach had the best fit to the production history in the cases studied.

Building capabilities to deliver high well count developments

In September 2008, Origin completed a $9.6 billion transaction with ConocoPhillips to form Australia Pacific LNG (APLNG)—a fifty-fifty coal seam gas to liquified natural gas joint venture. As the upstream operator, Origin is planning to ramp up production to more than five times present production levels. In a two-year period, Origin tripled Queensland CSG production volumes to 300 Tj per day. This expansion was based on existing business systems and processes and it was recognised that additional capability would be required to further ramp up production and associated activities. A project was commissioned to build operational capability and capacity—processes, systems, organisation design and people—to efficiently drill the required number of production wells. This priority project addressed a business objective to step up the drilling of CSG production wells from approximately 60 to 350–400 per annum. The transformational solution comprised three key components: business process re-engineering, technology development, and organisational re-design. The solution included the definition, documentation and transformation of business processes—this ensured consistent, repeatable and scalable processes capable of drilling of 350–400 wells per annum. The processes are now enabled by resource scheduling and document management systems that are fully integrated. The resultant well delivery system is managed by a team that provides the business with decision making information regarding the resource use required to support the delivery of the APLNG commitments. Given the transformational nature of the solution, the delivery of all three components was under-pinned with change management impact assessments, education, communications and deployment. The total solution was deployed in August 2010.

枯渇油・ガス田の有効利用

Teikoku Oil Co., Ltd. operates Minami-Nagaoka gas field, one of the biggest natural gas fields in Japan. Increasing demand of natural gas requires that Teikoku Oil should reinforce its production capability, including number of production wells, in Minami-Nagaoka. From a viewpoint of stable supply of gas resources, importance of natural gas underground storage has been widely recognized. Teikoku Oil established, for the first time in Japan in 1969, the underground storage system in Sekihara gas field, which was a depleted gas reservoir located a few kilometers north to Minami-Nagaoka. Since then, it has played a great role for peak shaving and/or emergency stockpile in Minami-Nagaoka gas production operation. At present, approximately 140 MMNm3 of natural gas is stored with the maximum deliverability of 1.6 MMNm3/day. Some technical issues encountered and solved during the storage operation for these 30 years are discussed in this lecture. In addition, Teikoku Oil notices that its experiences gained through the underground storage of natural gas in Sekihara could be directly applied to underground storage of carbon dioxide. Namely, injecting and storing man-made emissions of carbon dioxide, a greenhouse gas, in underground is considered as one of the possible measures against a global warming problem. Teikoku Oil is a member of a national research project on the underground storage of carbon dioxide led by RITE (Research Institute of Innovated Technology of Earth) and SEC (Safety and Environment Center for Petroleum Development). A pilot test to inject and store 15, 000 tons of carbon dioxide into a water zone is scheduled in and after 2003, for which one injection and two observation wells have already been drilled in Minami-Nagaoka. This noteworthy project is also introduced in this lecture. A key concept common to the both topics above is “utilization of depleted gas/oil reservoirs.”