Single Horizontal Well Research Articles

Mechanism of inter-well hydraulic fracture interference in the primary horizontal well pattern

Shale reservoirs are characterized by low porosity and low permeability and are difficult to be developed, single horizontal well fracturing has the shortcomings of low modification and insufficient fracture coverage, so multi-well fracturing is often used in the field. Primary horizontal well pattern is one of the main modes for commercialized shale oil and gas extraction, but the interwell interference existing in multi-well fracturing will affect extraction. In this paper, a 3D hydraulic fracturing model was established with the geology‒engineering integration method, and the effects of cluster spacing, fracturing sequence, fracture placement, well spacing, horizontal stress difference and natural fractures (NFs) on hydraulic fracture (HF) propagation and cumulative gas production in multi-well fracturing were investigated. The results are described as follows. Appropriately reducing the cluster spacing to 10 m can effectively reduce interwell fracture hits while obtaining higher initial production; Zipper fracturing has a significant effect on reducing interwell fracture hits. Compared with sequential fracturing, zipper fracturing increases the HF area and cumulative gas production by 4.7% and 4.2% respectively; In order to ensure production while reducing the risk of fracture hits, the well spacing was chosen to be 400m; Compared to symmetric fracture placement, the cumulative production increased by 7.0% and 9.8% for the 1/4 staggered fracture placement and 1/2 staggered fracture placement, respectively; Although more NFs can be communicated and a larger fracture area can be obtained under small stress difference conditions, but the risk of interwell and intercluster fracture hits increases; When the NF inclination is less than 80°, the fracture hits is weakened with increase of NF inclination, when the NF inclination exceeds 80°, the HF tend to pass through the NFs and the fracture hits increases; As the NF density increases, the fracture complexity near the wellbore increases and the fracture hits decreases.

Hydraulic fracturing distributed acoustic sensing monitoring data source mechanism inversion: A Hessian-based method

Distributed acoustic sensing (DAS) microseismic monitoring during hydraulic fracturing provides microseismic data with high spatial samplings for fracturing zones. However, sources located perpendicular to the single horizontal well of the DAS acquisition system have limited source-receiver geometries with extremely poor azimuthal coverage, resulting in high uncertainty in source mechanism inversion. To address this problem, we introduce the Hessian matrix, which governs the blurring effect caused by the source-receiver geometry, into the DAS microseismic source mechanism inversion. Our Hessian-based source mechanism inversion method consists of three main steps: (1) construct the Hessian matrix of the source mechanism based on the source-receiver geometry, (2) obtain an initial source mechanism using a conventional source mechanism inversion method, and (3) update the initial source mechanism using a Hessian-based [Formula: see text]-regularized least-squares algorithm. We assess the robustness of our method using synthetic DAS microseismic data with the consideration of noise, source location error, and different regularization parameters, and we compare the results with those of the conventional method. The results demonstrate that the Hessian-based method has a remarkable ability to mitigate the blurring effect of the Hessian matrix caused by limited DAS source-receiver geometry with poor azimuthal coverage, thereby reducing the uncertainty of the inverted source mechanism even in the presence of real noise and/or source location error. Finally, we use our method to invert the source mechanism of a real DAS microseismic event acquired during hydraulic fracturing. Our Hessian-based method provides low uncertainty in the source mechanism inversion of the real DAS microseismic data.

Establishment and Application of a Pattern for Identifying Sedimentary Microfacies of a Single Horizontal Well: An Example from the Eastern Transition Block in the Daqing Oilfield, Songliao Basin, China

The study of sedimentary microfacies of horizontal wells is important for improving oil recovery using horizontal well technology. Vertical well data alone do not provide accurate enough information to determine the sedimentary microfacies of horizontal wells. Therefore, a comprehensive method combining the data of both horizontal and vertical wells was established to identify sedimentary microfacies of horizontal wells and applied to a single horizontal well in the Daqing oilfield in China’s Songliao Basin. The results identified the study area as a delta sedimentary environment, mainly subdivided into four microfacies types: a distributary channel, the main overbank sand, the overbank sand, and an interdistributary bay. The criteria for identifying each sedimentary microfacies were established. Among them, the criteria for identifying distributary channels include a natural gamma value continuously less than 90 API; a resistivity value continuously greater than 11 Ω·m; a logging curve, which is typically bell-shaped or box-shaped with very high amplitude and amplitude difference; a mainly siltstone lithology; and a total hydrocarbon content (Tg) continuously greater than 3%. The variations in the two types of channel boundaries (narrowing of the channel boundary and reverse extension of the bifurcated channel boundary) were corrected. The research results can provide guidance for the efficient development of favorable reservoirs in oilfields using horizontal well technology.

Effect of Matrix Permeability on a Horizontal Shale Gas Well Performance using a Fully Coupled Fluid Flow with Geomechanics Model

Recently, hydrocarbon production from unconventional oil and gas resources has emerged. The most common unconventional oil and gas resources are found in shale formations. These shale formations are well-known for being stress-sensitive. Usually, traditional tools are used to model and study production from such formations. However, conventional modeling techniques denote rock deformation using constant rock compressibility. Such an approach is useful for studying conventional hydrocarbon resources where formation stress sensitivity is insignificant. However, when it comes to modeling stress-sensitive formations such as shale formations, it is important to include the rock deformation and its effects on the overall fluid flow in porous media. To consider the rock deformation in the fluid flow model, the coupling of fluid flow with the geomechanics model has to be used. This study utilizes a fully coupled fluid flow with a geomechanics model. In addition, shale formations are also known to have an ultra-low matrix permeability, and production usually results from hydraulic fractures that act as flow conduits. Consequently, the effect of matrix permeability on hydrocarbon production is rarely studied. This study focuses on the effect of matrix permeability on the production performance of a single horizontal well in Barnett Shale. It also focuses on the effect of matrix permeability on production performance when the geomechanics effects are coupled with the fluid flow model and decoupled. The results show that the higher the matrix permeability, the better the production performance of the well. The results also show that the higher the matrix permeability, the higher the estimated cumulative production difference between the two models (when the geomechanics effects are coupled and decoupled).

Research on circulating heat recovery law of single horizontal well for hot dry rock geothermal resources

Hot dry rock is essential to geothermal resources because of its advantages of clean green, good stability, large reserves, and high utilization coefficient. However, there are few large-scale and commercial mining schemes due to increased development costs, induced earthquakes, and low recovery during fracturing. Based on the above background, the concept of hot dry rock development for circulating heat recovery in the single horizontal well is put forward, injection and recovery of circulating working fluid are realized by single horizontal well, interchange of hollow pipe in well with liquid flow passage in wall annulus is realized by the fast connection of flow passage transformation, and flow direction control of thermal fluid is recognized by its unique bottom hole structure, to achieve the goal of cleanliness, low energy consumption, and high-efficiency heat recovery, to achieve the purpose of avoiding a series of problems caused by reservoir fracturing. A mathematical model has been created to calculate heat recovery efficiency in a single horizontal well. This model analyzes the impact of critical parameters in mining hot dry rock geothermal resources from single horizontal wells. The results show that the flow rate of circulating working fluid, the wellbore’s horizontal section length, and the formation’s thermal conductivity greatly influence thermal recovery. For instance, a domestic hot dry rock project can recover heat up to 3.08 MW through cyclic mining with a single horizontal well over 30 years.

Numerical analysis of unstable propagation of three-dimensional parallel hydraulic fractures induced by interferences of adjacent perforation clusters and thermal diffusion

PurposeThe purpose of this study is to investigate the unstable propagation of parallel hydraulic fractures induced by interferences of adjacent perforation clusters and thermal diffusion. Fracture propagation in the process of multistage fracturing of a rock mass is deflected owing to various factors. Hydrofracturing of rock masses in deep tight reservoirs involves thermal diffusion, fluid flow and deformation of rock between the rock matrix and fluid in pores and fractures.Design/methodology/approachTo study the unstable propagation behaviours of three-dimensional (3D) parallel hydraulic fractures induced by the interferences of adjacent perforation clusters and thermal diffusion, a 3D engineering-scale numerical model is established under different fracturing scenarios (sequential, simultaneous and alternate fracturing) and different perforation cluster spacings while considering the thermal-hydro-mechanical coupling effect. Stress disturbance region caused by fracture propagation in a deep tight rock mass is superimposed and overlaid with multiple fractures, resulting in a stress shadow effect and fracture deflection.FindingsThe results show that the size of the stress shadow areas and the interaction between fractures increase with decreasing multiple perforation cluster spacing in horizontal wells. Alternate fracturing can produce more fracture areas and improve the fracturing effect compared with those of sequential and simultaneous fracturing. The larger the temperature gradient between the fracturing fluid and rock matrix, the stronger the thermal diffusion effect, and the effect of thermal diffusion on the fracture propagation is significant.Originality/valueThis study focuses on the behaviours of the unstable dynamic propagation of 3D parallel hydraulic fractures induced by the interferences of adjacent perforation clusters and thermal diffusion. Further, the temperature field affects the fracture deflection requires could be investigated from the mechanisms; this paper is to study the unstable propagation of fractures in single horizontal well, which can provide a basis for fracture propagation and stress field disturbance in multiple horizontal wells.

Application of Dual Horizontal Well Systems in the Shenhu Area of the South China Sea: Analysis of Productivity Improvement

The horizontal well technology was successfully applied in the Chinese second natural gas hydrate (NGH) field test in the Shenhu area of the South China Sea in 2020. However, the results show that the threshold for commercial exploitation has not been broken, judging from daily gas production and cumulative gas production. Consequently, the paper presents the effects of dual horizontal well systems for exploitation in this area. The NGH reservoir model in the Shenhu area was established with CMG software. The influence of various layout options and various spacing of dual horizontal well systems on the production capacity was investigated. Further, we simulated the production effect of dual horizontal well systems joint auxiliary measures, such as well wall heating, heat injection, etc. The results show that the production capacity of dual horizontal well systems increased by about 1.27~2.67 times compared with that of a single horizontal well. The daily gas production will drop significantly, no matter which method was used, when exploitation lasts for about 200 d. Meanwhile, well wall heating and heat injection have limited effects on promoting production capacity. In conclusion, attention was drawn to the fact that the synergistic effect could be fully exerted to accelerate NGH dissociation when dual horizontal well systems are applied. The NGH reservoirs in the Shenhu area may be more suitable for short-term exploitation. The research results of this paper can provide a reference for the exploitation of the Shenhu area.

Study of Multibranch Wells for Productivity Increase in Hydrate Reservoirs Based on a 3D Heterogeneous Geological Model: A Case in the Shenhu Area, South China Sea

Summary So far, a total of 11 hydrate trial production projects have been carried out all over the world, all of which used a single vertical well or horizontal well to carry out hydrate production by the depressurization method or depressurization combined with other methods. These traditional production methods have some limitations: The single vertical well has a small contact area with the reservoir, and the transmission range of the temperature and pressure is limited; therefore, the productivity is low. The horizontal well can improve hydrate productivity from magnitude order; however, there is a long distance from the standard of commercial production of marine hydrate. Therefore, it is an inevitable trend to find a highly efficient and advanced drilling technology for heterogeneous hydrate reservoirs. The multibranch wells based on horizontal wells can not only increase the contact area between the hydrate reservoir and well by branch structure to improve the conductivity of the reservoir temperature and pressure but also improve the hydrate productivity by laying the branch at high hydrate saturation for areas with extremely uneven distribution. Therefore, for this paper, we chose the Shenhu area as the research area to establish an approximate realistic 3D heterogeneous geological model contained with hydrate, then we laid the multibranch wells based on horizontal wells in high hydrate saturation area and optimized the branch direction, location, and spacing, and the production increasing effect was assessed. Finally, an optimal multibranch well scheme was obtained under the conditions of this paper setting, which is as follows: The vertical multibranch well was set at the root end of the horizontal main well with a branch spacing of 10 m, and the productivity after optimization was 31.64% higher than that before optimization.

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

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

Genesis of Low CBM Production in Mid-Deep Reservoirs and Methods to Increase Regional Production: A Case Study in the Zhengzhuang Minefield, Qinshui Basin, China.

With the increase of the burial depth of the no. 3 coal seam in the Zhengzhuang minefield of Qinshui Basin, the production of surface coal bed methane (CBM) vertical wells was low. By means of theoretical analysis and numerical calculation, the causes of low production of CBM vertical wells were studied from the aspects of reservoir physical properties, development technology, stress conditions, and desorption characteristics. It was found that the high in situ stress conditions and stress state changes were the main controlling factors of the low production in the field. On this basis, the mechanism of increasing production and reservoir stimulation was explored. An L-type horizontal well was constructed alternately among the existing vertical wells on the surface to initiate a method to increase the regional production of fish-bone-shaped well groups. This method has the advantages of a large fracture extension range and a wide pressure relief area. It could also effectively connect the pre-existing fracture extension area of surface vertical wells, realizing the overall stimulation of the low-yield area and increasing the regional production. Through the optimization of the favorable stimulation area in the minefield, 8 L-type horizontal wells that adopted this method were constructed in the area with high gas content (greater than 18 m3/t), a thick coal seam (thicker than 5 m), and relatively rich groundwater in the north of the minefield. The average production of a single L-type horizontal well reached 6000 m3/d, which was about 30 times that of the surrounding vertical wells. The length of the horizontal section and the original gas content of the coal seam had a significant influence on the production of the L-type horizontal wells. This method for increasing the regional production of fish-bone-shaped well groups was an effective and feasible low-yield well stimulation technology, which provided a reference for increasing the production and efficiently developing CBM under the high-stress conditions in mid-deep high-rank coal seams.

Decision Support Tool Shows Multilaterals Can Maximize Reserves Value

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211570, “Maximizing Reserves Value Using Multilateral Wells: A Decision Support Tool and Key Applications,” by Eglier Yanez, SPE, Luigi Saputelli, SPE, and Fahad Alhosani, SPE, ADNOC. The paper has not been peer reviewed. _ In the complete paper, the authors review advances in selected completions to provide insight into adoption of multilateral technology (MLT), including lessons learned and recommendations. Six demonstrative applications were reviewed to validate technical assumptions for selecting particular MLT concepts. The authors write that MLT completions can reduce between 10 and 30% of drilling and completion (D&C) cost requirements while enhancing field-development net present value (NPV) in the range of 1–21%, with the potential of promoting fields that were otherwise uneconomic. This synopsis is devoted to the authors’ proposed technoeconomic assessment of MLT. Part 1: Economic Assessment of Dual and Trilateral Wells A simplified performance assessment was conducted to determine the economic effect of adding multilateral wells into a particular development plan. In this case, the following four well configurations or well types were considered: - Two single-lateral horizontal wells - One dual-lateral well with independent access to each lateral - Three single-lateral horizontal wells - One trilateral well completed with single controlled, commingled completion This analysis aims to produce insights from the following two comparison cases: - Comparison 1: Two single horizontal wells vs. one dual-lateral well - Comparison 2: Three single horizontal wells vs. one trilateral well The well design assumed for the cases can be found in the appendix of the complete paper. The production and reserves drained are maintained the same for each of the laterals; thus, those are considered controlled variables. To understand the effect of adding laterals to a motherbore, three cases have been selected for each of the previously mentioned well configurations by varying drilling depths for each typical cost environment to specify the areas with more potential for multilateral application and, conversely, the areas where single wells might appear to be more convenient. The analysis is broken down into onshore and offshore-shallow-water environments, where the main difference is the drilling cost per foot. The three cases are as follows: - Short-footage well: Motherbore depth of 5,000 ft and lateral length of 4,000 ft - Medium-footage well: Motherbore depth of 7,000 ft and lateral length of 8,000 ft - Long-footage well: Motherbore depth of 9,000 ft and lateral length of 12,000 ft The well costs considered for the study can be seen in Tables B-1 and B-2 of the appendix. In this simplified example, the capital costs included are limited to well-construction costs. Every lateral has a post-stimulation initial rate of 800 STB/D, which is expected to accumulate approximately 1.5 million STB on a 20-year horizon (Fig. 1). One should assume that, in this case, the equivalent rate of the dual-lateral well is exactly double of the one horizontal well and that of a three-lateral well is triple of one horizontal well.

Numerical Simulation of a Class I Gas Hydrate Reservoir Depressurized by a Fishbone Well

The results of the second trial production of the gas hydrate reservoir in the Shenhu area of the South China Sea show that the production of a gas hydrate reservoir by horizontal wells can greatly increase the daily gas production, but the current trial production is still far below the minimum production required for commercial development. Compared with a single horizontal well, a fishbone well has a larger reservoir contact area and is expected to achieve higher productivity in the depressurization development of gas hydrate reservoirs. However, there is still a lack of systematic research on the application of fishbone wells in Class I gas hydrate reservoirs. In this paper, a grid system for gas hydrate reservoirs containing fishbone wells is first established using the PEBI unstructured grid, and fine-grained simulation of reservoirs near the bottom of the wells is achieved by adaptive grid encryption while ensuring computational efficiency. On this basis, Tough + Hydrate software is adopted to simulate the productivity and physical field change of a fishbone well with different branching numbers. The results show that: the higher the number of branches in a fishbone well, the faster the free water production rate, reservoir depressurization, and free gas production rate in the initial stage of depressurization development, and the faster depressurization can effectively promote hydrate dissociation. Compared with a single horizontal well, the cumulative gas production of a six branch fishbone well can increase by 59.3%. Therefore, using multi-branch fishbone depressurization to develop Class I gas hydrate reservoirs can effectively improve productivity and the depressurization effect, but the hydrate dissociation will absorb a lot of heat and lead to a rapid decrease in reservoir temperature and hydrate dissociation rate. At the end of the simulation, the hydrate dissociation rate of all schemes was lower than 50%. In the later stage of depressurization development, the combined development method of heat injection and depressurization is expected to further provide sufficient thermal energy for hydrate dissociation and promote the dissociation of the hydrate.

Numerical simulation on the evolution of physical and mechanical characteristics of natural gas hydrate reservoir during depressurization production

Changes in the physical and mechanical characteristics of the natural gas hydrate reservoir during depressurization production can affect safe and efficient production. In order to reveal the evolution law of reservoir physical and mechanical characteristics, based on the establishment of thermo-hydro-mechanical-chemical (THMC) multi-field coupling theoretical model, taking SH2 drilling platform in Shenhu sea area of the South China Sea as an example, COMSOL multiphysics is used to simulate the processes of depressurization production with a single horizontal well. The results show that, after the bottom hole pressure began to decrease, the gas and water production rates immediately increased from zero to their respective peaks, and then decreased rapidly. The decomposition of hydrate is an endothermic process. The changes of temperature and pressure conditions have a significant impact on the decomposition of hydrate. Effective stress and Mises stress appear to be concentrated in the area of complete hydrate decomposition. Mises stress rises sharply at the location of the leading edge of decomposition, which needs to be alert to the risk of landslide. In the process of depressurization production, the top of the reservoir gradually appears settlement behavior. The upper area of the horizontal well has a large amount of subsidence, and reservoir modification can be implemented during production to improve the mechanical stability of the reservoir. The results are an important guide to achieve stable and continuous gas production.

Enhancement of gas production from low-permeability hydrate by radially branched horizontal well: Shenhu Area, South China Sea

A high gas production rate is critical for commercial exploitation of hydrate. Most marine hydrates deposit in the silty or clay sediments with low permeability, and gas production rate is low. Herein, a novel deployment of well, radial three-branch horizontal well was numerically investigated to enhance the gas production. A 3D geological model was established based on field trial in the Shenhu Area of the South China Sea. The simulation showed similar gas and water production for single and multi-branch horizontal wells with same length of 250 m. The depth in which well deployed dramatically affects the gas and water production, and which increases with the length of multi-branch well. Meanwhile the ratio of free gas originally distributed in three-phase and gas layers also increases with the length, which is 50% for 1200 m well. The interference around the intersection of branches enhances temperature recovery and the dissociation of underlying hydrates. The standard energy return on investment analysis shows that the economic potential increases linearly with the length of multi-branch well and obviously depends on the content of initial free gas. However, the production balances investment confines only to tens or hundreds of days for all model scenarios.

Predicting horizontal well flow rates under the geological conditions of Western Siberia fields

Research relevance. The determination of the expected well flow rate is a key problem in designing the development of oil fields with horizontal wells. In industrial practice, actual and real flow rates of horizontal wells usually differ significantly. Research objective. The algorithms for horizontal well potential flow rates determination have been studied extensively. However, the issues of choosing a methodology for determining the flow rate in relation to particular geological conditions remain unresolved. It is necessary to compare the actual and design rates of horizontal wells and identify the most representative methods for flow rates determination for the geological conditions of Western Siberia fields. Methods of research. A single horizontal well draining a semi-infinite reservoir is considered in the absence of hydrodynamically isolated and poorly drained zones within the radius of the well external boundary. The Giger, Joshi, Janar, and Renard–Dupuy methods were used to determine the expected flow rates of horizontal wells only under the following conditions: a homogeneous reservoir and a near-rectilinear horizontal section of the well in the reservoir interval. As an example, the calculation of the expected flow rate of a horizontal well with the following initial data is given: the horizontal section length is 700 m, the net oil thickness is 7.8 m; the permeability coefficient is 127 · 10–15 m2 , oil viscosity is 1.24 MPa ∙ s, the drawdown is 3 MPa, the external boundary radius is 1000 m, and the volume factor is 1.08. Results. Quite significant discrepancies between the actual and design data are recorded for wells with arbitrary numbers 4, 7, 8, 10, 15, 18 and 20. All the methods used for calculations provided comparable results. For all other wells, the calculation results have a high convergence with field data. Conclusions. The Giger, Joshi, Janar, and Renard–Dupuy methods may be recommended for horizontal wells expected flow rates determination only under the following conditions: a homogeneous reservoir and a near-rectilinear horizontal section of the well in the reservoir interval.

Numerical analysis on gas production from heterogeneous hydrate system in Shenhu area by depressurizing: Effects of hydrate-free interlayers

Natural gas hydrates (NGHs) buried in the Shenhu area are characterized by fine-grained sediments with interbedded hydrate-free layers. However, few is known about the influence of hydrate-free interlayers (HFIs) on gas production, which may control efficient and safe gas recovery from NGH reservoirs in long-term production. In this study, a field-data-based heterogeneous reservoir model is established to evaluate gas production behavior of Shenhu NGH reservoir with HFIs during depressurization. We compare the gas production from the hydrate reservoir with different HFIs characteristics. In a vertical well configuration, NGHs adjacent to HFIs dissociate preferentially over time, thereby significantly increasing average methane production and gas-to-water ratio. Notably, highly permeable HFIs (especially those near the permeable underburden), which can be regarded as high-permeability channels, increase pressure diffusion and then fluid flow, heat transfer and long-term gas production efficiency. The interlayers provide a better pathway for gas migration and secondary hydrates form inhomogeneously in the dissociation front. In contrast, low-permeability HFIs can negatively affect gas production and decrease average gas production amount by nearly 32.4% at most. The HFIs with low permeability are unfavorable for fluid migration and convective heat transfer from the burdens. Under the same initial conditions, the alternative of single horizontal well promotes the gas extraction volume limitedly. This study suggests that the vertical well configuration may provide more promising gas production efficiency than that of the horizontal one for the heterogeneous NGH reservoirs with HFIs in vertical direction. Our finding can provide a useful guide for gas production strategy in NGH reservoirs with HFIs.

Numerical Trend Analysis for Factors Affecting EOR Performance and CO2 Storage in Tight Oil Reservoirs

Improved oil recovery from tight oil reservoirs to fulfill the fossil fuel requirements and the CO2 storage to meet the net carbon zero objectives are the two motivations of this work. CO2 is a major anthropogenic greenhouse gas and its emission to our plants’ atmosphere is hazardous, particularly causing global warming. Therefore, its injection in the sub-surface oil-bearing formations not only improves the oil recovery but also reduces the carbon footprint from the planet. In this study, a mechanistic numerical simulation model is built using typical U.S. tight oil reservoir rock and fluid properties. The reservoir model is equipped with a hydraulically fractured single horizontal well that is subjected to multiple sensitivities using the huff-n-puff technique. Detailed CO2 trapping and diffusivity mechanisms at the nanopore scale are discussed that numerically define the CO2 solubility in formation oil and it’s trapping phenomenon into the nanopore spaces. The results show that CO2 injection works predominantly to achieve significant incremental oil recovery. Also, the reservoir with lighter in-situ fluid composition and higher reservoir pressure further enhances the oil recovery due to improved diffusivity and the solubility of CO2 into the reservoir fluid. It is also found that the increased number of huff-n-puff cycles and the incremental CO2 injection volume in each cycle not only enhance the oil recovery performance but likewise help to trap a larger volume of CO2 into a reservoir. A few diagnostic contour plots are also presented in this study to demonstrate the simultaneous effect of multiple hydraulic fracture parameters and the CO2 injection volume for the directional EOR and CO2 trapping performance. The findings of this study can help for a better understanding of designing EOR operations in tight oil reservoirs to achieve both goals concurrently.

Investigation on the asymmetric inter-fracture asynchronous huff-n-puff technology for the horizontal well group in the tight oil reservoir

Water huff-n-puff is one of the effective energy supplement methods for the development of tight oil reservoirs by horizontal wells. However, the oil production performance of water huff-n-puff severely decreases after several cycles. Available researches indicate that the inter-fracture asynchronous injection-production technology for the horizontal well is an efficient method for improving the oil production performance of water huff-n-puff. However, considering the object of the inter-fracture asynchronous huffn- puff is the single horizontal well, the study for a horizontal well group is less. Therefore, the asymmetric inter-fracture asynchronous huff-n-puff technology for the horizontal well group was investigated in this paper. The oil productions of the horizontal well group for different huff-n-puff modes were compared and analyzed first. After that, the oil recovery mechanisms of the asymmetric inter-fracture asynchronous huff-n-puff technology for the horizontal well group were revealed. Finally, the influence of operating parameters on the oil production of the horizontal well group for the asymmetric inter-fracture asynchronous huff-n-puff technology for the horizontal well group was studied by the numerical simulation method. The results show that compared with the water huff-n-puff, the accumulative oil productions for the asymmetric inter-fracture asynchronous huff-n-puff technology for the horizontal well group increased by 5134.8m3, and the increased amplitude is 36.86%. The imbibition, the inter-fracture displacement, and the inter-well displacement are the main oil recovery mechanisms of the asymmetric inter-fracture asynchronous huff-n-puff technology for the horizontal well group. The accumulative oil production of the horizontal well group for the asymmetric inter-fracture asynchronous huff-n-puff increases first, and then declines, finally tend to be stable with the increase of injection rate. Both the injection volume and the soaking time show a positive correlation with the accumulative oil production. The accumulative oil production of the horizontal well group decreases with the increase of production rate due to the aggravation of water channeling in the production stage. This work could provide certain theoretical guidance for the effective development of similar reservoirs by the horizontal well group.

Petrophysical/geophysical approaches to identify ISIP variability in the Eagle Ford shale

Understanding geomechanical properties is essential for an optimal completion strategy that ensures commercial productivity in shale reservoirs with ultra-low permeability. This study provides details to identify the variability of Instantaneous Shut-In Pressure (ISIP) in multidisciplinary approaches using petrophysical and geophysical data. ISIP is one of the input data required for well completion design. Operators commonly ignore the variability of ISIP and use uniform geomechanical assumptions due to cost and time constraints. In the case study, the variability of ISIP was observed up to 30 % in a single horizontal well, which could lower the efficiency of hydraulic fracturing with uniform geomechanical assumptions along a horizontal well trajectory. We propose practical approaches to identify the variability of ISIP from a case study in the Eagle Ford shale. MWD (Measurement While Drilling) Gamma Ray log, which is commonly acquired for a geosteering purpose, was utilized to prove its correlation with actual ISIP data gained at frac-stages in horizontal production wells. Correlation between ISIP and microseismic data was analyzed to identify the integrated relationship among the variability of Gamma Ray, ISIP, and hydraulically-induced fracture. In addition, practical approaches using a series of seismic inversion and attribute data were proposed to help identify geological variabilities affecting ISIP. This study was designed to provide operators hands-on approaches to capturing the variability of ISIP under limited data accessibility. We suggest multifunctional ways using the basic datasets commonly available at field sites. It can be applied to mitigate risks concerning well planning, drilling, and completion design in where operators face frequent challenges from geomechanical heterogeneity in global shale plays.

Combined stochastic and discrete simulation to optimise the economics of mixed single-horizontal and multilateral well offshore oil developments

Multilateral wells promise cost savings to oil and fields as they have the potential to reduce overall drilling distances and minimize the number of slots required for the surface facility managing the well. However, drilling a multilateral well does not always increase the flow rate when compared to two single-horizontal wells due to competition in production inside the mother-bore. Here, a holistic approach is proposed to find the optimum balance between single and multilateral wells in an offshore oil development. In so doing, the integrated approach finds the highest Net Present Value (NPV) configuration of the field considering drilling, subsurface, production and financial analysis. The model employs stochastic perturbation and Markov Chain Monte-Carlo methods to solve the global maximising-NPV problem. In addition, a combination of Mixed-Integer Linear Programming (MILP), an improved Dijkstra algorithm and a Levenberg-Marquardt optimiser is proposed to solve the rate allocation problem. With the outcome from this analysis, the model suggests the optimum development including number of multilateral and single horizontal wells that would result in the highest NPV. The results demonstrate the potential for modelling to find the optimal use of petroleum facilities and to assist with planning and decision making.