Wellbore Spacing Research Articles

An algorithm to improve magnetic ranging accuracy for cluster horizontal wells with narrow spacings

In order to realize the efficient development of unconventional oil and gas, the measurement accuracy of wellbore spacing in the drilling of parallel horizontal wells is more and more required. Although the Rotating Magnet Ranging System or Magnetic Guidance Tool is used to achieve a good ranging effect in the drilling of dual horizontal wells, the position measurement of the magnetic sub leads to a large ranging error. A new ranging algorithm for the Two Sensor Packages-Rotating Magnet Ranging System is presented in this paper. The algorithm takes the magnetic signal generated by the rotation of the magnetic sub at a fixed position, the tilt measurement data of the two wells, the length of the magnetic sub, and the distance between the two fluxgate sensors as input parameters to avoid measuring the position of the magnetic sub and to reduce the influence of the degree of non-parallelism and the length of the magnetic sub. The simulation and experiment demonstrate that the inclination and azimuth angles of the two wells have a significant impact on the magnetic ranging results when the ranging well sections are not parallel and that the distance between the bottom of the drill bit and the center of the magnetic sub cannot be ignored. Moreover, the accuracy of the relative distance calculated by this new algorithm can reach 97%, and the error of direction calculation is less than 3°. Applying this algorithm in the field can successfully aid in controlling the spacing of cluster horizontal wells more accurately.

Comparative study on heat extraction from Soultz-sous-Forêts geothermal field using supercritical carbon dioxide and water as the working fluid

Energy extraction from the deep subsurface requires engineering using a working fluid circulation in well doublet. This study developed a field-scale hydro-thermal model to examine the heat extraction potential from Soultz-sous-Forêts with CO2 and water as the working fluid. A better understanding of the heat extraction mechanism is established by considering the reservoir response and the wellbore heat exchange. Sensitivity analyses are performed for different injection temperatures and flow rates for 50 years. Results show that the wellbore effect is multiple times higher than the reservoir response to the production temperature. Furthermore, lowering the injection temperature eventuates to a smaller temperature reduction at the subsurface, enhancing the overall heat extraction potential with a minor impact on thermal breakthrough. The cold region developed around the injection wellbore may affect the production fluid temperature due to its proximity to the production wellbore near the top of the reservoir. To reach higher heat extraction efficiency, it is essential to use sufficient wellbore spacing. CO2 can be used as working fluid for over 50 years as it does not show significant thermal breakthrough and temperature plume evolution in the reservoir under studied conditions. CO2 shows lower temperature reduction for all injection rates and temperatures for 50 years of operation.

Thermodynamic Modeling of the Advanced Geothermal System Using Inclined Well Applications

The advanced geothermal system (AGS), also called the closed-loop geothermal technology, requires extremely long horizontal wellbore completion to compensate the deficiency for conductive heat exchange in deep reservoirs, which is technically challenge. The AGS using inclined well configuration has been proposed to improve its efficiency, but it lacks a comprehensive and quantitative evaluation in public domain. In this study, analytical models based on Duhamel’s convolution and natural coupling methods are developed to evaluate the performance of the inclined configuration. The results suggest that the inclined wellbore system can improve the outlet temperature performance of a typical horizontal configuration by 16 %. The inclined system also shows a constant temperature gain (9 °C/km in this case study) for unit increment in lateral length. In multilateral applications of the inclined well system, our sensitivity tests indicate that wellbore spacing can have significant impact on the heat energy production performance due to wellbore interferences if the distance between wells is small in 3D space. At least a 50 m distance between any two wellbores is recommended for the multi-lateral wellbore system in the well pad design. In general, 20 % (3 MWth) more heat energy can be generated and almost 1000 GWhth more heat energy could be produced at the end of 30 years by using a standard 10-laterals inclined well system in our case study.

An approach for the performance-impact of parent-child wellbores spacing and hydraulic fractures cluster spacing in conventional and unconventional reservoirs

The objective of this paper is focusing deep insights on the impacts of the spacing between parent and child wellbores and between hydraulic fractures on the performance of conventional and unconventional reservoirs. The target is developing a quantitative approach for determining these impacts on pressure responses, flow regimes, and productivity indices during the entire production life of these reservoirs. The motivation of this study is the willing to set-up and define clearly the criteria for the optimum spacing between wellbores and fractures that could give the maximum productivity considering different reservoir configurations and wellbore types.The methodology used in this study consists of four tasks. The first includes developing several analytical models for pressure behavior, and productivity index of reservoirs depleted by multilateral wells intersected by multiple hydraulic fractures. These models are applicable for conventional and unconventional reservoirs. The second demonstrates the solutions of these models using a state of the art computational tools and considering different spacings between these laterals and different spacings between fractures. The third concentrates on characterizing the production interference caused by the narrow spacing between fractures and short spacing between wellbores. This interference can be predicted from the changes in the flow regimes seen on pressure derivative curves. The last task focuses on proposing a quantitative measure for the optimum spacing between parent-child wellbores and optimum spacing between hydraulic fractures that could give the maximum productivity during the entire production life of the reservoirs.The observations are summarized in: 1) The impact of parent-child spacing is more influential than the impact of hydraulic fracture spacing. A significant increase in the productivity index is pointed out by increasing the number of the wellbore and decreasing the spacing between them while a very slight increase is seen in spite of the large increase in the number of hydraulic fractures. 2) The interference caused by parent-child spacing is seen after the interference of fracture spacing. The first one impacts linear flow regime when reservoir fluids flow from the drainage area beyond fracture tips to the area between hydraulic fractures while the second one impacts bilinear flow regime when reservoir fluids move toward hydraulic fractures. 3) The Frac-Hit, represented by the direct contact between hydraulic fractures of two adjacent wellbores, could cause a significant decline in the total productivity index of the production system. 4) The optimum wellbore spacing in fractured reservoirs depends on the number of hydraulic fractures propagated from these wellbores.The novel points presented in this study are: 1) New approach for estimating the optimum wellbore spacing and fracture spacing in conventional and unconventional reservoirs. 2) The possibilities for predicting the starting time of production interference caused by narrow spacings between fractures and wellbores. 3) The optimum spacing between hydraulic fractures is in the range of (10−30acres) for each fracture.

Investigation of the synergy potential of oil and geothermal energy from a fluvial oil reservoir

Geothermal projects, as renewable energy projects, are not economically attractive in most places of the world at the current state of development; for this reason, subsidies are required by energy and environmental authorities in order to increase the interest in such projects. In this paper, we assess and model strategies for integration of geothermal energy with oil productions of the Moerkapelle oil field in the Netherlands. To do so, numerical simulations have been employed to analyse the feasibility of a fluvial oil reservoir for the synergy potential of oil and geothermal energy exploitation. In order to implement the simulation studies, single phase and two-phase non-isothermal fluid flow modelling are utilized for the geothermal well doublet system and for water flooding in an oil reservoir (including facies heterogeneity), respectively. A series of simulations have been conducted to investigate how hot water from a geothermal reservoir beneath a heavy oil reservoir in the fluvial sedimentary system of the West Netherlands Basin can be used for Thermal Enhanced Oil Recovery (TEOR) and geothermal energy production.This study finds that the high degree of heterogeneity in fluvial oil reservoirs could significantly affect oil recovery improvement and hence the synergy strategy. High values of a) Net to gross (N/G) b) Bottom Hole Pressure (BHP) and c) horizontal wellbore length are favourable for oil recovery. In contrast, wide horizontal wellbore spacing and high oil viscosity have an adverse effect on oil recovery enhancement. Furthermore, the results display that the enhanced oil production helps to reduce the required subsidy for a single doublet geothermal project up to 100%. Consequently, the extra amount of oil produced by utilising the geothermal energy, could make the geothermal business case independent and profitable.

Application of fast analytical approach and AI optimization techniques to hydraulic fracture stage placement in shale gas reservoirs

In the last decades, natural gas from unconventional reservoirs has become a major portion of total gas supply due to advances in horizontal well drilling and multi-stage hydraulic fracturing as well as reduction of operational costs and capital expenditures. However, hydraulic fracturing technique is a still costly and resource intensive production strategy that requires optimal planning to conform to the best safety practices and to obtain the highest returns on investments. Thus, the proposed fast and reliable hydraulic fracture (HF) placement optimization technique based on physics and analytical equations is the key tool to balance between gas production costs and anticipated revenues.In this study, we develop an analytical model in which the modified Wattenbarger slab model with the pseudo-pressure approach are integrated into the Net Present Value (NPV) as the objective function. We consider four decision variables including number of HF stages, HF spacing, HF half-length, and wellbore spacing and use three stochastic gradient-free optimization methods (i.e., genetic algorithm (GA), differential evolution (DE), and particle swarm optimization (PSO)) to optimize the objective function on a synthetic shale gas reservoir model with the Barnett Shale properties. To verify the accuracy of the obtained optimal solutions, we conduct four trials for each stochastic optimization method with 100 generations and the population size of 20. The results show that the best overall value of the NPV found by PSO are 1.7% and 7.6% higher than those obtained by DE and GA, respectively. Moreover, PSO has the fastest convergence rate (in 50 generations), saves at least 10% of the computational time in comparison to those required by other methods, and results in the same optimal solution in all trials. Finally, considering bilinear flow at the early stages of the production period, nonlinear flow at the late production time, and gravitational effects in the analytical model are still open areas for future research in this field.

Synergy potential for oil and geothermal energy exploitation

A new solution for harvesting energy simultaneously from two different sources of energy by combining geothermal energy production and thermal enhanced heavy oil recovery is introduced. Numerical simulations are employed to evaluate the feasibility of generating energy from geothermal resources, both for thermally enhanced oil recovery from a heavy oil reservoir and for direct heating purposes. A single phase non-isothermal fluid flow modeling for geothermal doublet system and a two-phase non-isothermal fluid flow modelling for water flooding in an oil reservoir are utilised. Sensitivity and feasibility analyses of the synergy potential of thermally-enhanced oil recovery and geothermal energy production are performed. A series of simulations are carried out to examine the effects of reservoir properties on energy consumption and oil recovery for different injection rates and injection temperature. Our results show that total oil production strongly depends on the shape of heat plume which can be affected by porosity, permeability, injection temperature, well spacing and injection rate in the oil reservoir. The favourable oil recovery obtains at high amount of (a) injection rate, (b) injection temperature, (c) porosity and (d) low amount of oil reservoir permeability respectively. Furthermore, our study indicates the wellbore spacing plays an important role in oil recovery and an optimum wellbore spacing can be established. The analyses suggest that the extra amount of oil produced by utilising the geothermal energy could make the geothermal business case independent and may be a viable option to reduce the overall project cost. Furthermore, the results display that the enhance oil productions are able to reduce the required subsidy for a single doublet geothermal project up to 50%.

Optimizing Lateral Well Spacing by Improving Directional-Survey Accuracy

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 181772, “Optimizing Lateral Well Spacing by Improving Directional-Survey Accuracy,” by Shawn DeVerse, Surcon, and Stefan Maus, Magnetic Variation Services, prepared for the 2016 SPE Liquids-Rich Basins Conference—North America, Midland, Texas, USA, 21–22 September. The paper has not been peer reviewed. The effect of inaccurate directional surveying on lateral wellbore spacing is commonly overlooked. The purpose of this paper is to demonstrate how inaccuracy in standard directional-surveying methods affects wellbore position and to recommend practices to improve surveying accuracy for greater confidence in lateral spacing. Introduction Determining optimal wellbore spacing for a given field requires consideration of several factors such as hydraulic-fracture geometry and reservoir quality. These variables are simulated using advanced reservoir models to identify ideal parameters, such as lateral spacing distance, which will lead to the greatest production value. Models are then validated against field spacing tests to confirm results. However, an important consideration that is usually ignored is wellbore positional accuracy. Most reservoir models assume accurate wellbore placement. When reservoir models do account for wellbore positional uncertainty, the approximation is only a fraction of the actual positional error expected from standard wellbore-surveying techniques. This creates a problem when positional errors occur during spacing tests, because the actual lateral spacing distance could vary significantly from the values used to create the reservoir model. If production and reservoir simulations are misinterpreted because of wellbore positional errors, then economic consequences could be significant. Horizontal wells are directionally drilled using measurement-while-drilling (MWD) surveying to characterize the well path. Standard MWD surveying is subject to many error sources that lead to significant positional uncertainty and can result in inaccurate well placement. However, enhanced surveying methods such as use of multistation analysis (MSA) in field referencing can be an effective strategy for reducing a majority of errors. Positional uncertainty can be modeled by 3D ellipsoids of uncertainty at each survey point in the well path, which represent a statistical distribution of where the actual survey might exist. Methods In-Field Geomagnetic Referencing (IFR). IFR is a means of predicting the local magnetic field at a specific geographic location. It can be used to support MWD operations as a reference frame for magnetic measurements. IFR accounts for three of the four contributing factors of the geomagnetic field. These are the main field (generated by the Earth’s core), crustal field (magnetic minerals in the Earth’s crust), and steady external field (generated by charged-particle flow in the Earth’s atmosphere). The remaining contribution to the geomagnetic field is the magnetic disturbance field (generated by electric currents in near-Earth space).

Influence of Intersection Angle at Single-Well Flow Tests in Fracture-Wellbore Systems

Abstract The intersection angle between a hydraulically effective fracture and an active wellbore influences the response observed in single-well tests. An experimental study was launched to investigate the ability of a semi-analytical model proposed to account for this influence. The setup designed for this purpose includes three distinct fracture-wellbore system models with 90°, 20°, and 10° intersection angles, each assembled into a steel box frame to provide a constant fracture aperture during testing. The laboratory program involved testing each of these models for three different fracture apertures under steady, constant-flux, injection, and pumping conditions. The overall experimental setup successfully simulated the conceptual testing environment in which the mathematical model is expected to reproduce. Analysis of the test results confirmed the effectiveness of the conceptual model in refining the predictions of single-well tests. Important applications include the determination of anisotropic rock-mass permeability in a single, arbitrarily oriented wellbore by isolating fractures of different sets and of optimum wellbore orientation and spacing for maximum efficiency of producing wells.