Horizontal Completions Research Articles

The possibilities of field geophysical surveys for the diagnosis of horizontal wells with different types of completion

Background. Over the past decades, the design of production directional and horizontal wells has changed significantly. Currently, wells have a more complex trajectory, and their development control requires new approaches. Field geophysical surveys are an integral element of system control at any stage of the development of oil and gas fields. Objective. To systematize the experience of conducting field geophysical surveys in horizontal wells with different types of shanks. Materials and methods. Field geophysical surveys, which are included in both the standard and extended complexes, are designed to evaluate directly working sections of the studied geological objects, determine the inflow profile or intake capacity of production wells and establish the composition of the inflow with the allocation of the main phases. Results. The work shows the experience of conducting field geophysical surveys, and their informative possibilities depending on the type of horizontal completion of the well. The most informative research methods and technologies for studying an object with various layout variations are considered. The analysis of the influence of the complexities of the operation of low-permeability reservoirs and the choice of the optimal set of methods are carried out; recommendations on the optimal completion for horizontal wells are given. Conclusions. The obtained results will ensure the most cost-effective operation and the obtainment of more informative field geophysical survey results, which will allow to timely adjust well operation and conduct geological and technological measures.

Multi-scale reservoir response characteristics of coalbed methane development through stress relief via horizontal well cavity completion in tectonically deformed coals

China’s coalbed methane (CBM) resources hold significant potential. However, the widespread presence of soft and low-permeability tectonically deformed coal (TDC) presents a challenge to the efficient development of CBM. The development of CBM through stress relief via horizontal well cavity completion (HWCC) offers a promising innovative solution to this problem. To elucidate the multi-scale reservoir response characteristics of CBM development through stress relief via HWCC in TDCs, this article comprehensively employs particle discrete element and finite element numerical simulation methods, and carries out the numerical simulation studies of cyclic seepage at the specimen scale, HWCC at the coal seam scale, and CBM development at the coal seam group scale. The main findings are summarized as follows. Unlike the stress-compression specimens, which exhibited overall failure, the differential distribution of pressure gradients within the specimens during the gas seepage experiments resulted in the development of microcracks concentrated at the bottom of the specimens. With the escalation of coal body structural damage, the permeability stress compression coefficient during the elastic deformation stage shows an increasing trend. Upon entering the plastic deformation stage, the specimen’s permeability shifts from a decreasing to an increasing trend. Increasing the lower limit pressure ratio, upper limit pressure ratio, and cycle rate of gas injection pressure could accelerate the failure efficiency of the specimens. Increasing the lower limit pressure ratio has a more pronounced effect on the TDC specimens, while increasing the upper limit pressure ratio has a more significant impact on the primary undeformed and cataclastic coal specimens. In TDCs, the phenomenon of wellbore collapse and cavity expansion becomes more pronounced. The cavity volume tends to increase with the increase in the initial well diameter, in-situ stress, and alternating bottom-hole pressure differences. The HWCC could enhances reservoir permeability and production in both the cavity completed and adjacent coal seams. For two horizontal wells with cavity completions in the same layer, excessively close well spacing is unfavorable for fostering inter-well interference and reservoir pressure drop. When the HWCC is applied to thin coal seams, the enhancement of permeability and production is limited. Reasonable optimization of drainage rates could effectively mitigate the reservoir permeability velocity-sensitive damage. The research findings extend related theories and provide a robust reference for subsequent practical engineering applications.

Feasibility Study on the Applicability of Intelligent Well Completion

The relevance of assessing the applicability of intelligent wells using autonomous inflow control devices lies in the active development of the relevant sector of the oil and gas industry and the limited understanding of the economic efficiency of intelligent wells. The use of autonomous inflow control devices allows for a change in the composition of flow to the well, thus contributing to delaying the breakthrough of undesirable formation fluids, but at the same time, such an effect affects the dynamics of formation fluid production, which undoubtedly has a huge impact on the economic effect of the project. The analysis of scientific publications on the topic of “intelligent well completion” as a downhole production monitoring and remote production control system has shown that the vast majority of researchers pay attention to the evaluation of technological efficiency, ignoring the economic aspects of the proposed solutions. This study considered the dependence of the economic effect on the geological reservoir and technological well characteristics for variant 1—intelligent horizontal well (HW) completion using autonomous inflow control devices and variant 2—conventional horizontal well completion using the open hole. Calculations of production levels and dynamics in the two variants were performed on a created sector hydrodynamic model of a horizontal well operating in the depletion mode. The analysis of the obtained results allowed us to determine the applicability criteria of the proposed configuration of formation and well characteristics at the object of study, as well as to establish general dependencies of the net discounted income of an intelligent well. As a result of this study, it was determined that the economic efficiency of intelligent well completion with the use of autonomous inflow control devices relative to conventional well completion increases with decreasing permeability and drawdown pressure on the reservoir and reaches maximum values at the object of study at the thickness of the oil-saturated part of the reservoir about 5–6 m and the location of the wellbore in it at 35–40% of the thickness of the oil-saturated part below the gas–oil contact (GOC). This article covers the research gap in evaluating the economic efficiency of intelligent HW completion using AICD relative to conventional HW completion in oil rims.

Fracture propagation law of temporary plugging and diversion fracturing in shale reservoirs under completion experiments of horizontal well with multi-cluster sand jetting perforation

This study conducted temporary plugging and diversion fracturing (TPDF) experiments using a true triaxial fracturing simulation system within a laboratory setting that replicated a lab-based horizontal well completion with multi-cluster sand jetting perforation. The effects of temporary plugging agent (TPA) particle size, TPA concentration, single-cluster perforation number and cluster number on plugging pressure, multi-fracture diversion pattern and distribution of TPAs were investigated. A combination of TPAs with small particle sizes within the fracture and large particle sizes within the segment is conducive to increasing the plugging pressure and promoting the diversion of multi-fractures. The addition of fibers can quickly achieve ultra-high pressure, but it may lead to longitudinal fractures extending along the wellbore. The temporary plugging peak pressure increases with an increase in the concentration of the TPA, reaching a peak at a certain concentration, and further increases do not significantly improve the temporary plugging peak pressure. The breaking pressure and temporary plugging peak pressure show a decreasing trend with an increase in single-cluster perforation number. A lower number of single-cluster perforations is beneficial for increasing the breaking pressure and temporary plugging peak pressure, and it has a more significant control on the propagation of multi-cluster fractures. A lower number of clusters is not conducive to increasing the total number and complexity of artificial fractures, while a higher number of clusters makes it difficult to achieve effective plugging. The TPAs within the fracture is mainly concentrated in the complex fracture areas, especially at the intersections of fractures. Meanwhile, the TPAs within the segment are primarily distributed near the perforation cluster apertures which initiated complex fractures.

Study on Predicting Liquid Production Profile in Horizontal Wells Considering the Mechanism of Annular Flow Resistance and Water Control

The coated particle ICD water control technology has been widely used in horizontal well completion in offshore oil fields in recent years, but there is a lack of research on the simulation and prediction methods for liquid production profiles. By analyzing the dynamic inflow process of fluid, starting from the laws of momentum conservation and mass conservation, a coupled mathematical model of horizontal well reservoir wellbore pressure drop considering the mechanism of annular flow resistance was established, and solved through programming. Based on the actual well data of a certain block in an offshore oilfield, a horizontal well reservoir production model was established. The calculation results of the example show that the annular flow resistance and water control technology can effectively control the balanced liquid production of horizontal wells, thereby increasing the anhydrous oil recovery period and improving the oil recovery rate of the oilfield; The coupling model simulation and prediction method can fully reflect the mutual influence between the oil reservoir, wellbore annulus, ICD, and horizontal wellbore; The effective diameter of the ICD valve affects the changes in oil production and water content. The placement of the ICD well section has a significant effect on water control, and the compactness of the filled particles has a certain impact on pressure and water content changes.

Monitoring, Modeling Techniques Help Optimize Eagle Ford Completions

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212367, “Sealed Wellbore Pressure Monitoring and Calibrated Fracture Modeling: The Next Step in Unconventional Completions Optimization,” by Karen Olson, SPE, Joshua Merritt, and Rair Barraez, SPE, Well Data Labs, et al. The paper has not been peer reviewed. _ Sealed wellbore pressure monitoring (SWPM) has been used across North and South America, with more than 16,000 stages monitored. A recent development is the added capability of a fracture model that can automatically history-match the volume to first response (VFR) determined from SWPM. The complete paper’s focus is a case study of the Department of Energy Eagle Ford refracturing project, where a range of completion designs were trialed while monitoring offset SWPM and fiber-optic strain. Introduction of the Hydraulic Fracture Test Site 1 (HFTS1), Phase 3 Background. The HFTS1 Phase 3 was conducted at the Zgabay unit in northwest DeWitt County, Texas. This unit was initially developed with horizontal multistage completions and has been producing since 2013. The 10 original wells in the unit, and the four new drilled wells, are landed in the approximately 100-ft-thick Lower Eagle Ford Shale. Of the four new drills, Well 14H is a dedicated observation well instrumented with various diagnostics, including a permanent fiber-optic cable. Well 12H, another new drill, was monitored using a wireline-deployable fiber. Both of these wells featured downhole gauges, while Wells 11H and 13H featured surface gauges. The focus of the refracturing strain diagnostics— SWPM and fiber—was to characterize new fracture growth and interaction with pre-existing fractures during the liner refracturing of parent Wells 5H and 3H. Completion Designs. Multiple stage and cluster architectures were tested on the Zgabay Wells 3H and 5H. Four single-cluster stages were performed per well. Both a high (2,000-psi target) and low (500-psi target) perforation friction design was tested on seven-, 12-, and 22-cluster stages. Well 3H maintained a slightly tighter cluster spacing (10–15 ft) compared with the 12–20 ft spacing of Well 5H. The main method of measuring the effect of different designs is strain monitoring using SWPM and fiber optics. Technology Background SWPM. SWPM uses an uncompleted wellbore to monitor fracture intersections from offset-well stimulations. The monitor well collecting the SWPM data cannot be connected to a formation through perforations or other types of access points. The wellbore should be filled with low-compressibility fluid, with pressure added to the monitor well. Fractures intersecting the sealed wellbore cause local deformation, which results in a small volume reduction in the closed system and generates a discernable and distinct pressure response. The total slurry injected into the stage of the active well when the first fracture arrival is identified using SWPM is the VFR. VFRs are used as a proxy for cluster efficiency and to calculate fracture-growth rates. The field execution of SWPM does not require any tools to enter the wellbore. Multiple sealed wellbores can be used as monitor wells for a single treatment well.

Sensitivity analysis on tailpipe design for mitigating terrain slug in horizontal wells

Terrain slugs are a common challenge faced in horizontal well completions, leading to significant operational difficulties and reduced well performance. The lateral wellbore can cause hydrodynamic slug problems, even severe terrain slug issues. With undulations along the lateral, gas pockets can build up within the peaks and valleys of the wellbore. These gas pockets can restrict liquid flow until bottom hole pressure builds up enough energy to push the liquid slug to the surface. The terrain slug flow not only frequently results in foaming or emulsions at the surface but also causes downhole equipment failures, especially for Electrical Submersible Pumps (ESPs). Even with the downhole separator and gas handling pump stages, the ESP system is challenged by the elongated gas pocket that results in gas locks and electrical failures. To mitigate these issues, the use of Tailpipes (TP) in combination with ESP has become a popular solution. This study aims to explore the impact of tailpipe design on the performance of ESP systems in horizontal wells. With the help of oilfield operating companies, 5 representative wells are selected from 24 horizontal ESP wells that are facing or will potentially face the slugging issue.A total of 284 simulations are conducted using the transient simulator (OLGA, 2019) to comprehensively investigate the tailpipe design methodology for well conditions that are comparable to this study, i.e., flow rate from 500 to 2000 bpd, GLR from 500 to 2000 scf/bbl, 5 ½” and 7” casing, 9000–12000 ft well depth. Different TP diameters and lengths are simulated to evaluate the TP effectiveness at different flow rates, Gas-Liquid Ratios (GLRs), and well conditions. The results of this study can provide valuable insights and recommendations to the ESP tailpipe design for a wide range of horizontal wells applications, and help to improve their overall performance and reliability.

Geosteering, application of synthetic logging to horizontal wellbore sections

This article provides an analysis of the process and optimization of horizontal wellbore tracking using geosteering control. Recently, the issue of high-quality and efficient drilling of wells through the reservoir and determining the position of the wellbore in the formations has been raised. In this regard, complex data analysis is used based on a 3D geological model and special software for well geosteering. In preparation for drilling a well, it is necessary to prepare voluminous, comprehensive information on previously drilled wells in a particular field and upload the results of seismic surveys. The article also describes an analysis of activities at various stages of drilling support, starting with geophysical reference and opening the target formation with the transport section. When drilling a horizontal section of a well, geosteering software is used while drilling wells, equipped with various tools, one of which is the 2D synthetic logging method. The method is based on the superposition of logging curves of a previously drilled reference vertical well and a directional well with a horizontal end currently being drilled. The two-dimensional synthetic logging method is the main and most optimal way to optimize the placement of wells with horizontal completion when drilling terrigenous reservoirs in Western Siberia.

Drilling technology of long horizontal section of shale oil

As an important supplementary energy resource, shale oil has attracted worldwide attention due to its huge reserves and rich comprehensive utilization levels. The world is rich in oil shale resources. According to statistics, if the oil shale of 33 countries and regions in the world is converted into shale oil, it will be about 400 billion tons. With the continuous maturity of horizontal well drilling and completion technology in shale oil gas reservoirs and the application of other advanced technologies in horizontal well drilling, mature shale oil gas drilling and completion matching technologies have gradually formed at home and abroad after years of research and drilling practice. In terms of measurement technology, China has been able to produce single-point, multi-point, wired, wireless inclinometers and MWD measuring instruments while drilling and has mastered their usage methods. In terms of control technology, various specifications and types of fixed-angle and ground-adjustable curved shell screw drilling tools have been produced in China. Large deformation analysis and trajectory prediction methods for lower drilling tool assemblies have been completed. Various lower drilling tool assemblies and their usage processes required for wellbore trajectory control have been improved and mastered. In the construction of inclined and horizontal sections, attention should be paid to the response law of drilling tool combinations to drilling pressure in different formations, especially the response law of composite drilling. Reasonable drilling tool combinations should be selected for the control of wellbore trajectory in stable and horizontal sections, especially in the long stable and horizontal sections.

HORIZONTAL WELL COMPLETION SYSTEMS WITH MULTI-STAGE HYDRAULIC FRACTURING FOR LOW-PERMEABILITY, POORLY DRAINED, HETEROGENEOUS AND DISMEMBERED RESERVOIRS

Currently, the most effective method of intensifying the inflow of hydrocarbons and increasing oil recovery in productive formations in wells, in particular with a horizontal well, remains the technology of hydraulic fracturing (HF). In many regions, according to some domestic and foreign researchers, this is the only technology for developing fields with hard-to-recover hydrocarbon reserves confined to lowpermeability, poorly drained, heterogeneous and dissected reservoirs, which can significantly increase hydrocarbon production and make wells economically viable.Multi-stage hydraulic fracturing (MSHF) has established itself as one of the main methods of reservoir stimulation in the Russian Federation. The main goal of this method is to create highly conductive fractures in an oil and gas saturated reservoir throughout the horizontal section of the wellbore. To do this, an alternate series of hydraulic fracturing is performed, the result of which is the maximum production rate of hydrocarbons.Over time, oil and gas companies in the Russian Federation are becoming more demanding on the technical and technological parameters of MSHF in terms of the number of stages, the length of the horizontal section of the well, the possibility of re-fracturing and management of intervals/ports after its commissioning, and much more.The authors of the article propose to consider and analyze modern horizontal well completion systems with multi-stage hydraulic fracturing for low-permeability, low-drainage, heterogeneous and dissected reservoirs in order to form their rating.

Guest Editorial: The Engineer of the Future

Recently, at the SPE Annual Technical Conference and Exhibition, I was asked a question about the ‘engineer of the future.’ As we take a pause to turn the page to next year, I believe now is a prescient time to contemplate what’s next for petroleum engineering. Throughout my career, I’ve been able to witness great change in our industry as the shale revolution took hold making horizontal drilling and hydraulic fracturing commonplace, diagnostic and modeling tools improved in access and cost, and data became more timely and readily available. This led to a tremendous period of US energy supply growth and decades-long productivity improvements. Looking forward, I believe there are three trends that engineers should consider: 1) applying “new” tools to solve “old” problems, 2) connecting the dots via hybrid engineering, and 3) organizing, directing, and inserting data predictions into their workflow. These are not only my views but also the views of Devon’s talented engineers. Old problems will meet new solutions. The past decade has been dominated by unconventional horizontal development that was first pioneered in the Barnett Shale for natural gas and shortly thereafter transitioned into oil-focused development in the Bakken and Eagle Ford. Today, the Permian Basin continues to grow in total supply as the stacked pay is developed. Engineers should take stock of the tool set we have acquired during this era with a mindset to deploy these methodologies to tier II unconventional extensions, previously developed or bypassed conventional formations, offshore and international opportunities, enhanced recovery projects such as EOR and refracturing, and new energy opportunities like geothermal. To make these future opportunities competitive and meet the global demand for energy, we will likely need a combination of price, technology, and cost improvements. Engineers are critical to the latter two. To better illustrate these points let’s utilize examples. Drilling rig specification improvements have been coupled with material science and design improvements in bottomhole assemblies. The outcome is improved topdrives and mud pressure systems to power more durable and efficient downhole motors and bits, thus reducing failures, enhancing the efficiency of a rig’s daily footage, and enabling longer laterals. If we pivot to the completion space, our diagnostics for frac geometry have gone from limited and costly to a menu of options that provide fit-for-purpose diagnostics and costs. Devon deployed its first permanent fiber diagnostics in unconventional shale in 2012. Today, the same system is readily available but for a much lower cost. However, more frequently Devon has supplemented this tool with dip-in fiber and a proprietary methodology called sealed wellbore pressure monitoring to gather more frequent data points for frac geometry and design. As our team conducted, in cooperation with the US Department of Energy (DOE), a novel Eagle Ford project capturing horizontal core and completion diagnostics, we recognized that our designs have tremendously improved in efficiency but still have potential to capture more of the resource via initial and secondary fracturing efforts.

MINIMIZING BHA FRACTURES AND INCREASING DRILLING SPEED IN OIL AND GAS WELLS

The paper discusses horizontal completion drilling technology that uses telesystem diagnostic parameters to monitor the condition of the bottom hole BHA in order to increase wellbore penetration speed and reduce critical vibration and shock loads on BHA elements. The technology is based on solving the dependencies of penetration speed on the parameters of the rotary drilling mode and BHA vibrations using artificial neural networks and, in particular, the «random forest» method. During the development of the technology, a justification was given for the failure of the methods of classical mathematics due to the difficulty or impossibility of formalizing part of the influencing factors, as well as the discreteness of the values obtained from the face. An array of events of the drilled well was used for the study, the data of the GTE, the bottomhole telemetry complex and the on-board recorder of the drilling machine are tied to each other in depth and time. Events were sampled to obtain the correct data array for further investigation with similar parameters of drilling modes, the correct operation of the solved dependencies was tested for a part of the same array, and statistically significant results were obtained. A universal model has been built, with the help of which, based on previously received events, it is possible to obtain the necessary parameters of the rotary drilling mode to reduce the risks of BHA failure and increase the drilling speed. The model is selflearning and improves its quality by replenishing the base of reference events with new events. Thus, even if the wellbore trajectory or geological conditions change during drilling, the model remains applicable.

Mathematical Modeling of Prediction of Horizontal Wells with Gravel Pack Combined with ICD in Bottom-Water Reservoirs

During the development of horizontal wells in bottom-water reservoirs, the strong heterogeneity of reservoir permeability leads to premature bottom-water breakthroughs at locations with high permeability in the horizontal wellbore, and the water content rises rapidly, which seriously affects production. To cope with this problem, a new technology has emerged in recent years that utilizes gravel filling to block the flow in the annulus between the horizontal well and the borehole and utilizes the Inflow Control Device (ICD) completion tool to carry out segmental water control in horizontal wells. Unlike conventional horizontal well ICD completions that use packers for segmentation, gravel packs combined with ICD completions break the original segmentation routine and increase the complexity of the production dynamic simulation. In this paper, the flow in different spatial dimensions, such as reservoirs, gravel-packed layers, ICD completion sections, and horizontal wellbores, is modeled separately. Furthermore, the annular pressures at different locations are used as the solution variable for the coupled solution, which realizes the prediction of oil production, water production, and the water content of gravel packs combined with ICD completion of horizontal wells. The model is used to calculate the effects of different crude oil viscosities, different reservoir permeabilities, different permeabilities of gravel-packed layers, and different development stages on the water control effects of gravel packs combined with ICD completions and conventional ICD completions under field conditions.

Updating the processes of long-term monitoring of production wells

The development of West Siberian oil and gas fields in conditions of total horizontal completion of wells showed that technologically our industry was not sufficiently ready for this challenge. To quickly build high-tech horizontal wells, to carry out multistage hydraulic fracturing in them and at the same time effectively manage the operation of high-tech horizontal wells, to ensure the required degree of reserves development, unfortunately, is not the same thing...Despite the fact that the actual coverage of well-testing, production logging and alternative long-term distributed monitoring based on stationary information and measurement systems in Russia in recent years has been extremely insignificant, a cumulative analysis of the data obtained in the industry on the leading vertically integrated oil companies speaks about the following negative trends identified by diagnostic methods: the existing domestic technologies do not allow to regulate and manage the inflow and intake profiles in horizontal wells, horizontal wells with multistage hydraulic fracturing, multibarrel wells, thereby initially ensuring uniform production of recoverable oil and gas reserves in the drainage zones of wells with horizontal completion; the undesirable breakthroughs into the borehole of a horizontal well of water and gas detected by means of borehole diagnostics were eventually not isolated by field services, as a result of which the wells were decommissioned prematurely, without ensuring the achievement of the project accumulated indicators of hydrocarbon production; according to measurements in the horizontal wells, incomplete confirmability of multistage hydraulic fracturing designs was found (both in estimates of crack lengths and in terms of determining the places and forms of their initiation in holes); finally, the profiles of the inflow and the composition of the inflow studied in dynamics, as a rule, changed quite quickly in time from the moment the wells were launched for the selection of products, which usually led to unpredictable production losses (flow deterioration was usually recorded from the toe and the central parts of the boreholes of horizontal wells); the most typical reason for the decrease in productivity in horizontal wells and horizontal wells with multistage hydraulic fracturing should be recognized as the clogging of boreholes with sand and proppant, as well as the lack of the ability of producers to promptly clean the boreholes without creating repression on the formation; all these problems are certainly aggravated for objects of the category of hard-to-recover initial-recoverable reserves of hydrocarbon raw materials. The fixation and justification of the above conclusions were largely obtained due to the gradual transition of oil and gas producing and service companies from traditional one-time complex measurements by production logging and well testing to permanent long-term stationary monitoring of well testing and production logging parameters in production wells using various types of point-distributed and distributed modular means of stationary information and measurement systems. This progressive high-tech direction of borehole research can potentially be significantly developed and spread in the industry in the near future (which will objectively contribute to the achievement of higher oil and gas recovery coefficients), provided that the state bodies supervising the development of hydrocarbon raw materials (Rosnedra, Ministry of Energy of the Russian Federation) will involve measures to motivate a deeper and more detailed study of the state of development of residual recoverable reserves at the developed fields.

Geomechanical Rock Properties from Surface Drilling Telemetry

Summary We present a novel approach for real-time estimation of the mechanical properties of rock with drilling data. We demonstrate that surface drilling telemetry (also known as mud logging) can be used as an input for a trained machine learning (ML) algorithm to predict the properties of the rock being drilled at the moment. The study involves data from several real wells with horizontal completions. We use mud logging and logging while drilling (LWD) data from one part of the wells to train various ML models. The models are compared by various metrics using the five fold cross-validation technique. We also show the importance of proper feature selection for maximizing models’ performance in operation mode.

Numerical Simulation of Superheated Steam Flow and Heat Transfer in a Balanced Steam Injection Flow Control Device

Dual-string steam injection pipe is widely used in the production of superheated steam injection in heavy oil horizontal wells. Due to the nonuniform steam injection volume at the heel end and the existence of an interlayer and other factors in the reservoir, the distribution of steam cavity is not uniform, so it is necessary to control the flow of the steam injection well. Based on the basic principles of fluid mechanics and heat transfer, a three-phase nozzle outflow control device model is established in this paper. The steam flow and heat transfer law in the flow control device is numerically simulated, and the outflow dynamic law of horizontal well OCD completion in heavy oil reservoir is obtained. On this basis, the influence of OCD aperture parameters, steam injection pressure, and steam injection velocity on OCD throttling effect is studied. The results show that OCD has a good control effect on balancing pressure drop and improving steam injection uniformity. When the throttle aperture occupies 1/3 of the pipe diameter, the throttle effect is the best and the heat loss is low. Increasing the steam injection pressure can rapidly enhance the pressure reduction rate of the throttle hole. The throttling effect of increasing steam injection volume is not obvious, and the energy loss becomes higher. The study of this paper provides a reference for parameter optimization and prediction of steam distribution in the flow control device of horizontal wells.

Autonomous ICDs Optimize Production in Singue Field, Ecuador

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210417, “Autonomous ICD Introduction in Singue Field, Ecuador: Completion Methodology and Production Evaluation,” by Alejandro Chacon, SPE, Georgina Corona, and Juan Pico, Halliburton, et al. The paper has not been peer reviewed. _ Autonomous-inflow-control-device (AICD) technology, design methodology, and production-performance evaluation for AICD completions were applied for the first time in multiple horizontal wells of the Singue oilfield development in Ecuador. The analysis described in the complete paper covered the complete cycle, from reservoir modeling, completion design, post-drilling match, calibration, and production-performance analysis. Background and Field Information Singue is a field in a tropical rainforest in the Sucumbios province of Ecuador. The first well in the Singue field was drilled in February 1991. Lower U was the target reservoir in this first well. The well was drilled on the basis of seismic 2D data acquired from 1979 to 1989. Field cumulative oil production between 1991 and 1997 was 447,000 bbl. The field then was shut in until 2012, when Gente Oil Company was assigned as the operator of Block 53. Despite heavy field-development investment, a cumulative oil production of 8 million bbl was generated until 2018. Alternate completion techniques were considered to increase oil production by drilling horizontal wells. Water breakthrough was the challenge in these wells. The field has strong support from a water aquifer. An additional challenge in this area was the environmental sensitivity of the Amazon region to produced-water disposal. A horizontal completion with inflow-control technology to restrict water was considered as a mitigation measure. The first horizontal well, AH1, was drilled in 2019; it included swell packers and AICDs to balance the oil and control and restrict water at breakthrough. The second well, BH2, was drilled in 2020; the third and fourth wells were drilled in 2021 with similar completion technology. These wells were drilled in the Lower U reservoir, which has an average oil API gravity of 22.8. This reservoir is considered a consolidated sandstone with no sand production. Fluidic-Diode AICD Technology AICDs have a similar performance to traditional ICDs during the initial oil-production phase of the well before the onset of unwanted fluids (water/gas). During oil production, AICDs induce a low-pressure differential that allows balancing the flow across the completion. Therefore, they also provide the benefit of delaying the onset of water or gas. However, this technology offers additional benefits. In contrast to ICDs, AICDs induce a higher restriction for water or gas by creating a greater pressure differential across the devices for these fluids, which reduces the flow rate when compared with traditional ICDs.

Response in coal reservoirs and in-situ stress control during horizontal well coal cavern completion and stress release

Widely developed tectonically-deformed coal (TDC) blocks the recovery of coalbed methane (CBM). Horizontal well cavern completion and stress release (HWCCSR) is expected to extract TDC in-situ CBM efficiently. Systematic investigations on reservoir response during stress release are essential for evaluating stress-relief performances and guiding engineering practices. However, the dynamic-controllable cavern enlargement and the influence of high stress and intense tectonic stress were mainly ignored in previous work. Additionally, the mechanism of permeability variation remained unclear under complex stress surroundings. In this work, the geological-engineering numerical model of coal cavern completion was constructed, and the equivalent method was adopted to investigate the dynamic HWCCSR. The stress, plastic deformation, and permeability responses were analyzed, and the impact of in-situ stress on reservoir response was discussed. The mechanism and model of permeability changes under complex stress were revealed.The results showed that the equivalent method could imitate the dynamic-controllable enlarging of the cavern properly with easy operation and good convergence. The reservoir responded significantly during the HWCCSR. With increasing cavern diameter (Dc), the plastic deformation zone (PDZ) increased, permeability could be expanded to 1–105 times the initial value, and the effective permeability increase zone (EPIZ) was linear with Dc. Laboratory and field data confirmed the rationality of simulation results. High vertical principal stress and significant lateral stress coefficient were conducive to generating more complex PDZ and larger EPIZ and enhancing more considerable permeability in TDC reservoirs due to more energy and a strong damage-deformation trend. Four models of permeability variation and possible division of permeability distribution were proposed according to the integrated control of elastic-plastic deformation, stress difference, and volume stress. Stress difference was the direct reason for coal plastic deformed-failure. Plastic deformed-failure coupled with volume stress-relief could significantly increase permeability. Plastic deformed-failure and volume stress concentration might cause a permeability decrease. Coal elastic deformation with volume stress concentration might induce a similar outcome. Additionally, elastic deformation coupled with volume stress-relief might enhance permeability and expand the EPIZ under tectonic stress conditions. In conclusion, larger caverns had better stress-relief performance, expected to attain a high recovery of coalbed methane. The HWCCSR was suitable for recovering TDC in-situ CBM in areas with intense tectonic stress and large burial depths. This work confirmed the feasibility of efficient recovery of TDC in-situ CBM through HWCCSR. It provided basics for evaluating reservoir responses to stress-relief and selecting layers.

Simulation-based evaluation of the effectiveness of fiber-optic sensing in monitoring and optimizing water circulation in next-generation enhanced geothermal systems

The success of multi-stage hydraulic fracturing technology in unconventional oil and gas reservoir development has attracted much attention from the geothermal community. Some pilot field experiments have been conducted to investigate the multi-stage hydraulic stimulation along horizontal or high-deviated wellbores in geothermal reservoirs (denoted as next-generation enhanced geothermal systems). One common output of such stimulation is that the created hydraulic fractures show various conductive capabilities, which could potentially lead to undesirable flow localization, early thermal breakthrough, and low cold water sweep efficiency. Monitoring the water circulation between horizontal wellbores connected through hydraulic fractures becomes important in avoiding early severe producing temperature reduction in practical operations. In this study, we investigate the effectiveness of distributed temperature sensing (DTS) and distributed strain sensing (DSS) in identifying dominant flow paths in geothermal reservoirs with multi-stage hydraulic stimulation and horizontal well completion designs. A coupled thermo-poro-elastic model for general-purpose geothermal reservoir simulation is developed and solved using a combined finite volume/finite element method, together with a fully implicit sequential coupling scheme. The temperature and strain responses along horizontal production wells are simulated and analyzed during water circulation. Reservoir temperature reduces in the area that is close to the water flow paths, which induces thermal contraction. These thermoelastic characteristics can be monitored by fiber-optic sensing, forming distinct signatures for flow-localization identification. DTS data may be dominantly influenced by the fractures with higher conductivity, ‘masking’ the signals related to fractures in the downstream, but DSS data can provide additional information for accurate identification of high conductive fractures. Successful mitigation strategies, for example plugging the dominant fractures illustrated in this study, could substantially increase the producing fluid temperature. The analyses in this study show that fiber-optic sensing is an effective technology to monitor and optimize water circulation in next-generation enhanced geothermal systems.

Technical advances in well type and drilling & completion for high-efficient development of coalbed methane in China

Compared with the United States, Australia, Canada, and other countries, China's coalbed methane reservoir is featured by low formation pressure, low permeability, low gas saturation, and strong heterogeneity, which not only increases the difficulty of reservoir stimulation but also restricts the single well production and the recovery efficiency of coalbed methane (CBM). In view of this, the research and application of horizontal drilling and completion technology of CBM at home and abroad are reviewed to provide references and theoretical supports for the advancement of the horizontal well engineering technology of CBM in China. This paper introduces a series of horizontal drilling and completion technologies (e.g., the well type design, well structure optimization, well trajectory control, wellbore stability, completion optimization, reservoir protection, etc.). The advanced technologies and their adaptability, including screen pipe completion and stimulation with dual-layer tubular strings, radial horizontal well screen pipe completion and magnetic steering drilling, are dialectically discussed in this paper. In addition, a novel integrated engineering mode for the efficient and green development of deep CBM and coal through the underground “well factory” is proposed. The conclusions are as follows: (1) In view of the geological conditions and surface environment of the coal seam in China, the horizontal drilling and completion technologies of high rank coalbed methane should be further refined, and an integrated development for the coal measure gas is required; (2) More efforts should be made to strengthen the innovative research on horizontal drilling & completion technology for low-medium rank coals and the broken coal, so as to identify the efficient development mode for the complex coalbed methane reservoir; (3) When encountering major technical challenges during the green and efficient development of unconventional coal mines such as deep coal mines, low grade coal mines and thin coal seams in China, it is necessary to explore the development mode via in-situ conversion process based on underground “well factory” to realize the integrated green and efficient development of deep CBM and coal; (4) The high quality transformation with low-carbon and green energy in China will not only ensure national energy security, but also achieve the goal of “carbon peaking and carbon neutrality”.