This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203962, “Upscaling of Realistic Discrete Fracture Simulations Using Machine Learning,” by Nikolai Andrianov, SPE, Geological Survey of Denmark and Greenland, prepared for the 2021 SPE Reservoir Simulation Conference, Galveston, Texas, 4–6 October. The paper has not been peer reviewed. Upscaling of discrete fracture networks to continuum models such as the dual-porosity/dual-permeability (DP/DP) model is an industry-standard approach in modeling fractured reservoirs. In the complete paper, the author parametrizes the fine-scale fracture geometries and assesses the accuracy of several convolutional neural networks (CNNs) to learn the mapping between this parametrization and DP/DP model closures. The accuracy of the DP/DP results with the predicted model closures was assessed by a comparison with the corresponding fine-scale discrete fracture matrix (DFM) simulation of a two-phase flow in a realistic fracture geometry. The DP/DP results matched the DFM reference solution well. The DP/DP model also was significantly faster than DFM simulation. Introduction The goal of this study was to evaluate the effect of different CNN architectures on prediction accuracy for the DP/DP model closures and on the accuracy of DP/DP simulations in comparison with fine-scale DFM simulations. As a starting point, two CNN configurations were considered that have achieved breakthrough performance in image-classification tasks. The author adopted these architectures to the problem of learning the mapping between pixelated fracture geometries and the DP/DP model closures and indicated several key features in the CNN structure that are crucial for achieving high prediction accuracy. Mapping of fracture geometries requires significant effort, which limits the possibilities for creating large training data sets with realistic fracture geometries. The author, therefore, used the synthetic random linear fractures’ data set to train the CNNs and the fracture geometry from the Lägerdorf outcrop for testing purposes. It was demonstrated that an optimal CNN configuration yielded the DP/DP model closures such that the corresponding DP/DP results matched well the two-phase DFM simulations on a subset of the Lägerdorf data. The run times for the DP/DP model were a fraction of the time needed to accomplish the DFM simulations. Problem formulation is presented in a series of equations in the complete paper.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31298, “Novel Active Slug Control in Angola: Development and Field Results,” by Lisa Ann Brenskelle, SPE, Martin Bermudez Morles, and Lauren Annette Flores, Chevron, prepared for the 2021 Offshore Technology Conference, Houston, 16–19 August. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. Hydrodynamic slugging was anticipated during the design of a new facility in Angola. A simulation study demonstrated that a control scheme from the literature could be applied effectively to control the slugging. That solution was rejected, however, because of the use of a pseudovariable as the principal control point. A novel control scheme, therefore, was developed and tested in simulation for both hydrodynamic slugging and severe riser-induced slugging. Upon commissioning, slugging at the facility was found to be more severe than anticipated during design, but the novel active slug-control scheme was effective in controlling incoming slugs. Slugging-Control Approaches Various control schemes have been implemented to control slugging in hydrocarbon-processing systems, including subsea systems. The accepted control approaches to the various types of slugging differ because causes of slugging differ, although the effects on processing facilities are similar. For hydrodynamic slugging, the use of a pseudoflow controller, which uses a calculated value of flow, is the accepted conventional approach. The pseudoflow is calculated from the equation for volumetric liquid flow through a valve, which results in a value that is not physically meaningful for multiphase fluids. For terrain slugging, the accepted approach is the use of pressure control, wherein the pressure is upstream of the slug-forming area. For riser slugging, this is at the base of the riser. For both hydrodynamic and terrain slugging, the accepted control schemes usually modulate the control valve located upstream of the vessel first receiving produced fluids, normally depicted as a separator, although this vessel also could take other forms. Use of this valve in relation to slugging is common, whether used manually or in a control scheme. Maximum production occurs with the valve fully open, but this cannot control or prevent slugging. Known field-demonstrated control schemes include pseudoflow control, pressure control upstream of the slug-forming area, pressure control upstream of the slug-forming area cascaded to (i.e., determining the setpoint for) the pseudoflow control, and composite variable control. Each of these control schemes has practical disadvantages affecting usability in the field. The principal disadvantage of pseudoflow slug control is that setpoint determination is difficult because the pseudoflow is not an actual physical flow rate. Trial and error would be required to determine the pseudoflow setpoint each time it would need to be adjusted, which would be a frequent occurrence as operational conditions change. In the case of slug control through pressure control upstream of the slug-forming area, the principal disadvantage is the use of a subsea pressure sensor because the slug-forming area, the low point, frequently is subsea. Not only is subsea instrumentation expensive, but such instrumentation also is difficult to replace should it fail.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202265, “Leap of Faith From Conventional to EM Look-Ahead: A Game-Changing Technology To Improve Well Efficiency,” by Muhamad Yanuar Mahardi, Hendarsyah Hendarsyah, and Kharisma Endarmoyo, PT Pertamina, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. The structure in the Matindok block in Central Sulawesi operated by Pertamina has proven producible gas reserves in the Minahaki formation. One of the main challenges in this area is the low resolution of seismic data, leading to a high depth uncertainty. The complete paper describes a technology developed to meet these challenges with the capability to map and detect lithology changes ahead of the bit in real time. Geological Background A first exploration well, PEP-001, was drilled in 2018. The structure has a Miocene carbonate buildup play, and the target reservoir is the M pinnacle carbonate reef. The PEP-001 well was planned to set the 9⅝-in. casing point above the top of the M formation. Offset wells did not show any clear markers in the thick shale above the M formation that could have been used for log correlation. In previously drilled offset wells, correlation was performed convention-ally by examination of cutting samples and on drilling breaks. However, when Well PEP-001 was drilled, no apparent drilling break was observed. By the time cuttings reached the surface, the bit had drilled into 20 m of the M formation. Because the casing covered most of the upper carbonate formation, openhole logging and well-testing data were not acquired to delineate the target formation optimally. The second exploration well, PEP-002, was planned with an objective of setting 9⅝-in. casing approximately 5 m above the top of M to acquire full-interval coverage of coring, openhole wireline logging, and well testing. This information was critical for optimal reservoir delineation to allow for accurate reserves calculation and future development. Conventional correlation methods have proven insufficient for casing point placement. The presence of limestone stringers in offset wells within proximity of the top of M presented an additional challenge. The stringers could have been misinterpreted as the main carbonate body, if interpretation were based solely on cutting samples. Real-Time Electromagnetic (EM) Look-Ahead Technology

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203152, “Generative Well-Pattern Design Applied to a Giant Mature Field Leads to the Identification of Major Drilling Expenditure Reduction Opportunities,” by Maddalen Lepphaille, Total; Arthur Thenon, Modis; and Pierre Bergey, Total, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. A generative well-pattern-design (GWPD) work flow was benchmarked against traditional manual designs to leverage three reservoir-development planning opportunities applicable to a giant mature Middle Eastern carbonate field. People remained central in ensuring efficient problem setup and exploration guidance, but the work flow proved able to identify substantially better patterns than the traditional approach for each of the opportunities at the cost of only a few hundred simulations. GWPD Overview The work flow used to tackle the different problems of this study, which the authors call the GWPD “well-improvement scheme” (WISH), consists of the following steps. Each step is detailed in the complete paper. 1. Definition of design space 2. Constraint of design space 3. Qualification of design space 4. Nondominated sorting (a specific ranking of all of the cells of the con-strained design space according to the value of their quality indicators) 5. Candidate design investigation 6. Investigation of preferred designs 7. Optimization of preferred design GWPD Application Context. The application study was con-ducted at the beginning of the industrialization of WISH, a proprietary software tool dedicated to GWPD. The authors call the work flow GWPD-WISH. In the studied oil field, more than 400 oil producers and water- or gas-injector strings have been drilled from approximately 100 platforms in a series of reservoirs. The study focused upon two specific reservoirs holding most of the field reserves. These reservoirs are developed with peripheral water injection and gas injection into the gas cap. According to the latest development plan, hundreds of wells will be drilled during the next 40 years in order to maintain a production plateau. The context was deemed favorable because a 3D gridded dynamic reservoir model was available, the geology and development history defined a large and complex design problem, and large liquid hydrocarbon reserves were thought to remain. While the software and method used enables considering an ensemble of realizations capturing reservoir uncertainties, only a single history-matched realization of the model was available. Consequently, the study did not deal with reservoir uncertainties.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30408, “Design and Safety Considerations To Perform Coiled Tubing Operations in Large-Diameter, High-Temperature Geothermal Wells,” by Ishaan Singh, SPE, Danny Aryo Wijoseno, SPE, and Kellen Wolf, Schlumberger, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 17–19 August. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. The productive section in a high-pressure, high-temperature (HP/HT) geothermal Field A in the Philippines features shallow and deep reservoirs separated by a low-permeability formation. However, recent years have seen a reduction in production levels. To activate and enhance well production, coiled tubing (CT) nitrogen-lift operations were required. CT simulations were combined with simulations from the geothermal reservoir to overcome modeling limitations. The outcome helped the design of a new cooling-loop system and allowed optimization of the nitrogen-lift technique. As a result, two large-diameter geothermal wells were lifted safely with 2-in. CT. Introduction This study describes design and safety considerations in performing CT operations in high-temperature, large- diameter geothermal wells. The customized high-temperature-grade seal material was chosen to withstand high bottomhole temperatures (BHT) (600°F), and a heat exchanger riser system was designed and tested on the job to handle high-surface-temperature steam (350–400°F), thus mitigating potential well-control incidents. Challenges of Seal Damage Caused by High Surface Temperatures in Live Well Intervention The CT interventions in quenched HP/HT geothermal wells reduce the risk of surface equipment failure. The seal material readily available in the market is rated to 250°F, but, if quenching is not possible, the high-temperature steam (approximately 350–400°F) may flow into the pressure-control equipment, leading to seal damage and CT contingencies. At high temperatures (400°F), these seals are unusable. It becomes essential to use a surface heat exchange riser (HER) system to prevent this issue. Design and Execution of HER Systems in Field A To avoid any well contingency and to keep pressure-control equipment safe, HER systems can be used. Some basic designs for HERs are described in the complete paper. For this study, a customized 4.06-in. HER cooling system (Design 1, shown in Fig. 1) was designed to accommodate 2-in. CT pipe. Design 1 was chosen from an evaluation of three design candidates outlined in the complete paper. The wellhead stack featured seal elements rated to high temperatures (400°F). To prevent high- temperature steam from entering the wellhead stack, the blowout preventer, and other surface- equipment elements, an efficient HER system was designed wherein, while the CT is still in the well performing CT operations, the cold water can be pumped into the CT-stack annulus from the top flow cross through the cooling riser to the bottom flow cross and back to the return tank. The temperature of the cooling loop was continuously monitored to ensure that it was well below 212°F (the boiling point of water).

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203226, “First Multistage Fracturing of Horizontal Well Drilled in a Conventional Tight Carbonate Reservoir in an Onshore Field in the UAE: Challenges and Lessons Learned,” by Muhammad Aftab, SPE, Noor Talib, and Maad Subaihi, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. The reservoir upon which this case study is focused is a tight, low-permeability carbonate reservoir with thin layers. The objective of the field case was to increase and sustain productivity of a pilot well consisting of an openhole completion. The complete paper summarizes the design processes, selection criteria, challenges, and lessons learned during design and execution phases. The study may provide a potential approach for selecting the proper hydraulic fracturing method and technique in similar cases. Introduction Reservoir X is divided into six layers. Layers X-3 through X-6 have reasonable porosity development; valid pressure points exist in X-3 and X-6. Pumpout was performed while collecting samples from X-3 and X-6, followed by short buildups. Production-logging-tool measurement was performed and found two major oil-producing layers across X-3 (60% of total production) and X-6 (40% of total production). The remaining intervals of the perforation were almost inactive. Petrophyscial and testing results of vertical Well A resulted in a decision to drill a horizontal oil producer (Well B) through Layer X-3. Well B was steered with a 2,220-ft horizontal length, out of which 1,930 ft was inside X-3 and 290 ft were above X-3 be-cause of a fault throw of 16 ft true vertical depth. The well was steered with a horizontal length of 2,080 ft in X-6. Well B was completed with a 3½-in. completion and horizontal section as an openhole. Matrix stimulation using coiled tubing was performed with 15% hydrochloric acid in Well B. The well ceased to flow after 2 weeks of declining production. Rapid pressure depletion was observed in Well B. Localized depletion around the wellbore was anticipated because of poor matrix/matrix connectivity. After comprehensive studies and risk assessments, the decision was made to recomplete Well B with a cemented fracturing string to perform hydraulic fracturing with the plug-and-perf technique. This technique will allow flexibility of stage count and stage spacing and a multi-cluster design to maximize the stimulated reservoir volume (SRV) along the upper, middle, and lower layers. In addition, the operator and service provider collaborated to enhance this design through a zero-overflush technique with diverting agents. The complete paper provides a detailed discussion of the core measurement and 1D mechanical Earth model used in the hydraulic fracturing design. Hydraulic Fracturing Design The main challenge in fracturing Well B was to ensure that the fracture generated is contained within the reservoir. Well B is completed in two layers (X-3 and X-6). The bottom part of the well is in X-6 and close to another underlying reservoir (Fig. 1).

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 198970, “Casing Rotating Cement Heads: A Custom-Fit Solution To Improve Zonal Isolation Results In Colombia—A Field-Proven Case,” by Jose Vela, SPE, Henry Arias, and Edwin Sanchez, Ecopetrol, prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, held virtually 27–31 July. The paper has not been peer reviewed. In the current challenging drilling environment, effective annular zonal isolation is required for long-term integrity. Among proven cementing practices, casing rotation has been widely applied to liners but not as commonly to full casing strings. The complete paper describes the use of custom-fit rotating cement heads (RCH) to improve cementing results. Cementing Practices in Colombia The following methods of cementing, described in detail in the complete paper, are applied currently in Colombia: - Preflushes and spacers - Slurry design - Casing standoff - Borehole conditioning - Mud circulation and conditioning - Casing movement during the cement job - Monitor job parameters compared with design - Pressure testing and surface-equipment installation Most of these best cementing practices have been followed on a daily basis for all production and intermediate casing. Rotation practice has been widely applied to liners but not for casing strings. This observation led to the introduction of RCH, a technology that arose as the most- appropriate link to connect the top drive or rig prime mover with the casing so that rotation for a full string of casing could be achieved. RCH Use and Implementation Before the implementation of RCH, cement evaluation logs did not show the expected response. Evidence of fluid channeling and fluid contamination was very common, and fair casing to cement bonds was a concern, particularly in washed-out sections and very long cement columns. RCH provides a technical solution for the need to rotate the casing strings while maintaining best practices common to all cement jobs. Rotation has shown to be mandatory for intermediate and production casing to obtain a better log response by enhancing displacement fluid efficiency and mud removal. Well-design and cement objectives vary according to regional sedimentary basins around the country. In the Llanos Basin, the intermediate casing shoe integrity and the isolation of the T1 sand unit are primary objectives; the most-common wellbore problems are the presence of very washed-out sections in front of the E3 and E4 shale formations. The T1 sand unit is located between them and is prone to water or gas influx. Next, the production section is drilled with a lighter mud so that a high negative differential pressure is induced around the casing shoe once the shoe track is drilled. If shoe integrity is not suitable, an influx can be promoted when drilling the productive zone.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199149, “Rate-Transient-Analysis-Assisted History Matching With a Combined Hydraulic Fracturing and Reservoir Simulator,” by Garrett Fowler, SPE, and Mark McClure, SPE, ResFrac, and Jeff Allen, Recoil Resources, prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, originally scheduled to be held in Bogota, Colombia, 17–19 March. The paper has not been peer reviewed. This paper presents a step-by-step work flow to facilitate history matching numerical simulation models of hydraulically fractured shale wells. Sensitivity analysis simulations are performed with a coupled hydraulic fracturing, geomechanics, and reservoir simulator. The results are used to develop what the authors term “motifs” that inform the history-matching process. Using intuition from these simulations, history matching can be expedited by changing matrix permeability, fracture conductivity, matrix-pressure-dependent permeability, boundary effects, and relative permeability. Introduction This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199149, “Rate-Transient-Analysis-Assisted History Matching With a Combined Hydraulic Fracturing and Reservoir Simulator,” by Garrett Fowler, SPE, and Mark McClure, SPE, ResFrac, and Jeff Allen, Recoil Resources, prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, originally scheduled to be held in Bogota, Colombia, 17-19 March. The paper has not been peer reviewed. This paper presents a step-by-step work flow to facilitate history matching numerical simulation models of hydraulically fractured shale wells. Sensitivity analysis simulations are performed with a coupled hydraulic fracturing, geomechanics, and reservoir simulator. The results are used to develop what the authors term “motifs” that inform the history-matching process. Using intuition from these simulations, history matching can be expedited by changing matrix permeability, fracture conductivity, matrix-pressure-dependent permeability, boundary effects, and relative permeability. Introduction The concept of rate transient analysis (RTA) involves the use of rate and pressure trends of producing wells to estimate properties such as permeability and fracture surface area. While very useful, RTA is an analytical technique and has commensurate limitations. In the complete paper, different RTA motifs are generated using a simulator. Insights from these motif simulations are used to modify simulation parameters to expediate and inform the history- matching process. The simulation history-matching work flow presented includes the following steps: 1 - Set up a simulation model with geologic properties, wellbore and completion designs, and fracturing and production schedules 2 - Run an initial model 3 - Tune the fracture geometries (height and length) to heuristic data: microseismic, frac-hit data, distributed acoustic sensing, or other diagnostics 4 - Match instantaneous shut-in pressure (ISIP) and wellhead pressure (WHP) during injection 5 - Make RTA plots of the real and simulated production data 6 - Use the motifs presented in the paper to identify possible production mechanisms in the real data 7 - Adjust history-matching parameters in the simulation model based on the intuition gained from RTA of the real data 8 -Iterate Steps 5 through 7 to obtain a match in RTA trends 9 - Modify relative permeabilities as necessary to obtain correct oil, water, and gas proportions In this study, the authors used a commercial simulator that fully integrates hydraulic fracturing, wellbore, and reservoir simulation into a single modeling code. Matching Fracturing Data The complete paper focuses on matching production data, assisted by RTA, not specifically on the matching of fracturing data such as injection pressure and fracture geometry (Steps 3 and 4). Nevertheless, for completeness, these steps are very briefly summarized in this section. Effective fracture toughness is the most-important factor in determining fracture length. Field diagnostics suggest considerable variability in effective fracture toughness and fracture length. Typical half-lengths are between 500 and 2,000 ft. Laboratory-derived values of fracture toughness yield longer fractures (propagation of 2,000 ft or more from the wellbore). Significantly larger values of fracture toughness are needed to explain the shorter fracture length and higher net pressure values that are often observed. The authors use a scale- dependent fracture-toughness parameter to increase toughness as the fracture grows. This allows the simulator to match injection pressure data while simultaneously limiting fracture length. This scale-dependent toughness scaling parameter is the most-important parameter in determining fracture size.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 201662, “A Well-Flux Surveillance and Ramp-Up Method for Openhole Standalone Screen Completion,” by Mehmet Karaaslan and George K. Wong, University of Houston, and Kevin L. Soter, SPE, Shell, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5-7 October. The paper has not been peer reviewed. Production and surveillance engineers need practical models to help maximize production while avoiding ramping up the well to an extent that the completion is damaged, causing well impairment or failure. The complete paper presents a well-flux surveillance method to monitor and ramp up production for openhole standalone screen (OH-SAS) completions that optimizes production by considering risks of production impairment and screen-erosion failure. Challenges of Increased Production vs. Well Failure The problem of increased production vs. the risk of well impairment or failure is a pressing problem for sand-control wells in deepwater, where projects tend to have a small number of high-rate wells. In such environments, any well impairments or failures greatly affect the project economics. Following unloading, well surveillance faces the critical step of ramping up to-ward the well’s designed peak rate for the first time when the actual well performance is uncertain. To reduce risk of well impairment or failure, surveillance information and models are needed to help make adjustments during the ramp-up process. Different models are available, from simple to complex and from small to large amounts of input data and computational efforts. Simple nonsurveillance models use field-derived operating limits of completion pressure drop and flow velocity or flux. They are non-surveillance models in the sense that no direct linkage of surveillance results to update flux calculations exists. Simple surveillance models use pressure transient analysis (PTA) results and completion information to evaluate changing well performance and adjust the ramp-up and long-term surveillance operations. The complex surveillance model evaluates well performance and adjusts well operations using probabilistic completion failure risks and coupled reservoir and completion simulations. These models mainly focus on cased-hole gravel pack and frac-pack applications. For openhole completions with sand control, the literature offers limited ramp-up surveillance references. The objective of the well-flux model described in the complete paper is to ramp up the well safely and optimize production using PTA results as surveillance inputs to calculate completion fluxes for well impairment or failure assessment. The method follows an approach presented in the literature.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 199268, “Upscaling Laboratory Formation Damage Laboratory Test Data,” by Michael Byrne, SPE, Lesmana Djayapertapa, and Ken Watson, SPE, Lloyd’s Register, et al., prepared for the 2020 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, 19-21 February. The paper has not been peer reviewed. Through several case histories, the complete paper demonstrates applications of computational fluid dynamics (CFD) modeling to upscaling of laboratory-measured formation damage and reveals implications for well and completion design. The value of laboratory testing is quantified and interesting challenges to conventional wisdom are highlighted. Introduction Laboratory formation damage testing is often used to help select optimal drilling and completion fluids. Test procedures such as sand retention and return permeability represent an attempt to simulate near-wellbore conditions during well construction and production. To determine what degree of permeability impairment is allowable, further interpretation that cannot be provided using classical nodal analysis or reservoir simulation methods is required. The complete paper describes the evolution of, and potential for, more-comprehensive upscaling and outlines the importance of consideration of full well geometry when designing and interpreting coreflood tests for formation damage. CFD simulations provide a means to upscale suitable laboratory test data to predict effect on well performance. Methods CFD simulations use a relatively simple, steady-state, static damage model that takes endpoint data from laboratory core tests and translates the data into parameters that are used for input into well geometry. Although this method has its merits and is a considerable advance on previous, more-simplistic upscaling attempts, it does not necessarily present the full picture of damage evolution in the near-wellbore. A transient model of damage with data again derived from laboratory coreflood data could reveal more about well cleanup and progressive damage removal. Steady-State Modeling. No API recommended practice for return permeability testing exists. Laboratories have their own procedures that comply broadly with recommended procedures developed some time ago. Operators and consultants, too, have their own procedures, which they often ask laboratories to follow. Although no recommended practice exists, evaluation of drilling and completion fluids usually involves measurement of a base permeability and remeasurement of a return permeability—or several—after application of the test fluid or fluids. In many cases, the laboratory removes the external mud cake or trims a slice of the end of the plug to measure return permeability without mud cake (Fig. 1).

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199690, “Diagnostic Fracture Injection Test Analysis and Interpretation in Layered Rocks,” by Shuang Zheng, SPE, Ripudaman Manchanda, SPE, and HanYi Wang, The University of Texas at Austin, et al., prepared for the 2020 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, 4-6 February. The paper has not been peer reviewed. Formation-property estimations based on diagnostic fracture injection tests (DFITs) typically are based on analysis of pressure data assuming the closure of simple planar fractures in homogeneous reservoirs. These interpretations are incorrect when dealing with complex reservoir environments such as layered reservoirs with different properties and stresses. The complete paper investigates the effect of such complex environments on DFIT interpretation and presents a systematic method to analyze the data. Model Description A fully integrated hydraulic fracturing and reservoir simulator is used in this paper to simulate a DFIT. This simulator has been developed for designing and evaluating pad-scale fracturing treatments. It was then extended from a single-phase flow model to a multiphase black-oil-flow model and from a single-well fracturing simulator to an integrated fracturing and reservoir simulator. An energy-balance model was incorporated into the simulator to consider temperature changes. The fully implicit geomechanical hydraulic fracturing simulator was also extended to an integrated equation-of-state-based compositional fracturing and reservoir simulator in recent work. This simulator, which has been used in the literature and is discussed in detail in the complete paper, couples the reservoir fracture/wellbore system and has the capability to simulate the life cycle of wells: hydraulic fracturing, shut-in, flowback, primary production, and improved oil recovery. Base Case In the base case, a small amount of fluid is injected into the wellbore and the well is shut in for 10 days to mimic a DFIT job. The simulation domain is 400×400 m 2 in the horizontal plane and 200 m in the height direction. The perforation clusters are placed in the middle of the domain. The bottomhole pressure vs. time is computed and plotted in this simulation. The simulation involves propagation of a single vertical fracture from a horizontal wellbore drilled in a formation with layered stress heterogeneity. The fracture maintains the largest width in the middle low-stress region, and the two low-stress regions below and above the middle low-stress region also have a large width compared with the fracture-tip regions and the high-stress regions. During fracture closure, fracture width decreases; however, the fracture width in the low-stress region is always higher than in the high-stress region. Results and Discussion The authors applied the numerical DFIT model to study the effect of different layer properties on DFIT signature and its interpretation. The simulation results indicate that most of the layer proper-ties have a major effect on DFIT signature and interpretation.

In recent years, Aker BP has explored and developed a number of digital improvements to optimize production. The underlying business drivers are meant to improve efficiency, increase production and reserves, decrease costs, and reduce the carbon footprint from operations. The example described in this article has innovative elements of digitalization and automation of workflows which provide a new approach for better handling of slugging in subsea developments with long tiebacks. The new solution has a potential for optimizing production and limiting the amount of flaring. Flow Instabilities in the Vilje Field The Aker BP-operated Vilje field in the Norwegian Continental Shelf has occasionally experienced production-flow instabilities in the production pipelines and risers due to slugging. The company worked with Turbulent Flux to develop a software solution, the FLUX Stability Adviser, to continuously and precisely monitor production in real time. Field Description and Outline of Problem The Vilje field is a subsea development with three horizontal producers tied back to the Alvheim floating production, storage, and offloading (FPSO) facility through a production line longer than 20 km. The inlet separator at Alvheim is shared with other third-party developments. After an initial period of dry-oil production at the field, which started production in 2008, the oil rate has gradually decreased as a result of increased water cuts (WC) over time. Gas lift has been used to sustain production. The occasional slugging at the inlet separator had been controlled by increasing the backpressure to the production line and/or shutting in one of the producers. However, this practice affects production potential and may lead to production losses or deferral. Explanation of the Solution The two companies developed a Stability Adviser application to advise operators of the settings to optimize production in real time while lowering the risks related to slugging at any point in time. The developed solution runs on a cloud infrastructure with an interactive web-user interface. The main user interface contains a 3D heat map which is based on output from a series of pre-run transient simulations and a statistical analysis of the associated slugging severity. The model quality of the pre-run simulations was benchmarked with field data, and a similarity index was introduced to evaluate the degree of matching. Transient multiphase flow simulations represent the state of the art in the prediction and analysis of slugging behavior in multiphase transport pipelines (both terrain-induced and hydrodynamic slugging). These simulators capture and follow slugs as they are forming along the pipeline. That said, these simulations are time consuming, which limits their usefulness in a real-time operational context.

Flow-induced vibration (FIV) from high-velocity multiphase flow is a common source of vibration concern in process piping, potentially leading to fatigue failures and hydrocarbon leaks. A combination of computational fluid dynamics (CFD) and finite element (FE) modeling offers a potentially powerful tool for assessing and diagnosing multi-phase FIV problems in hydrocarbon-production piping systems. Global energy consultancy Xodus Group performed FIV studies on an Equinor-operated topside production system, carrying multiphase flow at high-pressure (approximately 69 bara) conditions, where significant vibration was measured. The study assessed different vibration-simulation methodologies, combining FE analysis with forcing functions based on both correlations and CFD simulations. The aim was to gain a better understanding of the accuracy and limitations of calculation methods typically used to assess fatigue. Calculating Multiphase FIV in Operational Pipework While CFD FIV modeling methods have been well validated against low-pressure water-airflow under laboratory conditions (Emmerson et al. 2016a and 2016b), little has been published to show how well these techniques perform for operational hydrocarbon-production systems. As these systems usually operate at higher pressures with complex, live hydrocarbon fluids and water, the process conditions are often not well defined. They typically incorporate sev-eral features that could complicate the vibration-generation mechanisms such as long upstream pipelines, chokes, and convoluted combinations of pipe bends with complex support arrangements. As part of the development of a new Energy Institute guidance document for subsea pipework, the project with Equinor was instigated following a joint industry project (JIP) established by Xodus, in collaboration with TNO and funded by six major operators, to improve techniques for estimating forcing functions in liquid-gas flows. Vibration measurements were taken at various locations on a section of piping carrying multiphase flow at high-pressure conditions (approximately 69 bara) (Fig. 1). The forces were applied in harmonic, transient, and fluid structural interaction (FSI) simulations (directly coupled FE and CFD). The topside piping arrangement consists of 16-in. schedule-100 piping, with a tee at the top of a riser section followed by six 90° and four 45° 1.5 R/D elbows and is reasonably well supported (as shown in Fig. 1). The measurements provided the vibration velocity of the piping structure, and frequency spectra analysis was performed for comparison with the structural-response simulations. The main locations of interest are V4 and V5 as the measured vibration was the highest here. The peak vibration velocity at V4 is 4.7 mm/s and this occurs at 5.1 Hz in the EW-Y direction (Fig. 2), while at V5 the peak is 6.4 mm/s at 5.2 Hz.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29875, “Combined Data Analytics and Physics-Based Simulation for Optimal Bit, Motor, and Bottomhole Assembly Combination,” by Samba Ba, SPE, Dmitry Belov, SPE, and Daniel Nobre, SPE, Schlumberger, et al., prepared for the 2019 Offshore Technology Conference Brasil, Rio de Janeiro, 29-31 October. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Today, drill bits and mud motor issues can account for more than half of the reasons for pulling out of hole before total depth (TD) on directional drilling wells. The complete paper presents a methodology designed for optimally matching drill bits, mud motors, and bottomhole-assembly (BHA) components for reduced failure risks and improved drilling performance. Work Flow The overall work flow includes detailed modeling of each sophisticated component and an algorithm to combine them efficiently at the system level without losing their specific nature. Drilling-Bit Simulation. The drill-bit model is created in 4D - 3D space modeling plus the transient behavior with time. In 4D finite-element modeling, both polycrystalline-diamond-compact (PDC) and reverse-circulation bits can be modeled. The detailed cutting structure model may include specifying the number of cutters and how to place them in a 3D cutter space. The bit cutter and rock interaction must be modeled correctly to simulate the real scenario. This interaction is characterized by laboratory testing for almost all types of rocks interacting with the cutters. Motor Simulation. The mud motor consists of multiple subassemblies. The power section assembly is where the transformation of hydraulic power into mechanical power occurs; this consists of a rotor/stator pair. The rotor is the moving part and the stationary stator is a metal tube with rubber bonded inside. The authors developed a motor- optimization modeling work flow for evaluating the mud motor’s performance and durability for any defined drilling conditions. This model includes performance, fatigue, and hysteresis heating simulation capabilities. Within the framework of the developed work flow, the authors use three types of simulation (mechanical, thermal, and fatigue), with mutual correlations between the results. Drillstring Simulation. A proper drill-string simulation is critical for the successful evaluation of drilling performance and equipment reliability. In this study, the drillstring and BHA analysis consists of a comprehensive full-scale finite-element model that also includes a proper transient analysis of the drilling process in a 4D analysis. This finite- element model uses 3D beam elements with six degrees of freedom for each finite-element node. The described complex finite-element model incorporates all components from drill bit to surface. This model considers factors affecting the dynamic performance of the drillstring and can predict the transient response in the time domain. Detailed working mechanisms and geometries of downhole drive tools were implemented in the model to study the dynamic characteristics and directional performance of these tools.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper IADC/SPE 199587, “Modeling Cuttings Transport and Annular Packoff Using Local Fluid Velocities With the Effects of Drillstring Rotation and Eccentricity,” by Oney Erge, SPE, and Eric van Oort, SPE, The University of Texas at Austin, prepared for the 2020 IADC/SPE International Drilling Conference and Exhibition, Galveston, Texas, 3-5 March. The paper has not been peer reviewed. This paper discusses a new, comprehensive cuttings-transport model designed to enable safe and improved hole-cleaning operations. Local velocity profiles are calculated for a given fluid and compared against the local critical velocity for cuttings transport. Then, the location and the magnitude of annulus blockage are numerically assessed. After an annulus becomes partially blocked with cuttings deposited in a cuttings bed, continuity and momentum equations are solved for the blocked annulus to estimate the new local velocities. The annulus is divided into small sections, and the pressure profile is calculated with the progression of time. The results from this study agree with large-scale flow-loop experiments and field observations, showing that axial flow alone is not enough for effective hole cleaning in high-deviation and horizontal wells. The results also provide a way to predict packoff events during which the string can become stuck, the equivalent circulating density can spike, and lost circulation can occur.

The oil and gas industry is facing unprecedented and brutal market conditions. While the industry was already in the midst of digitalization, the oil price crash has instilled a fresh impetus on its adoption to cut costs through innovation and new technologies. One such technology is predictive maintenance. When equipment on a rig breaks down, the resulting problem often is not that of replacement but the forced downtime in production or drilling. Therefore, predicting when equipment or a system is going to fail and determining the root cause of failure unlocks significant value. Predictive maintenance has rapidly gained in popularity, spurred by well publicized advances in high-performing computing and Internet of Things (IoT) technologies. Some companies are experiencing the benefits of predictive maintenance firsthand. For example, engineers at Baker Hughes implemented predictive maintenance on the company’s fleet of fracturing trucks. They collected nearly a terabyte of data from pumps on these trucks and then used signal-processing techniques to identify the relevant sensors. Finally, they applied machine-learning techniques to distinguish a healthy pump from an unhealthy one and reduced overall costs by $10 million (MathWorks 2019). This success story and others like it have made pursuing predictive maintenance projects a priority among both oilfield operators and services firms.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 199164, “Applied Learnings in Reservoir Simulation of Unconventional Plays,” by Raphael Altman, SPE, Roberto Tineo, SPE, and Anup Viswanathan, SPE, Schlumberger, et al., prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, Bogota, Colombia, 17-19 March. The paper has not been peer reviewed. Reservoir simulation is valuable in understanding dynamics of unconventional reservoirs. Applications include estimating long-term production behavior, enhancing well-spacing and pad-modeling efficiency, optimizing completion and stimulation of horizontal wells, and understanding production drivers that cause differences in productivity between wells. In the complete paper, the authors revisit fundamental concepts of reservoir simulation in unconventional reservoirs and summarize several examples that form part of an archive of lessons learned. Reservoir Simulation Applications in Unconventionals Reservoir simulation plays an important role in many stages of unconventional reservoir field development. In the initial pilot phase, a calibrated reservoir simulation model can provide an indication of estimated ultimate recovery (EUR), which is advantageous given few wells with short production time. EUR evaluation with incorporated uncertainties is a key variable in asset evaluation and investment decisions. During the ramp and development phases, reservoir simulation aids completion optimization by providing a link between completion parameters, such as cluster spacing and stimulation pumping parameters, and a well’s production. Extending this idea further, the integrated nature of reservoir simulation enables identification of production drivers and understanding of why wells are producing differently. During the mature stages of unconventional reservoir development, well spacing and hydraulic fracture and pressure interference, together with refracturing, require advanced modeling techniques that can include a combination of hydraulic fracture simulation, 3D stress simulations, and advanced reservoir simulation. Reservoir Simulation Modeling in Unconventionals Unconventional reservoirs are heterogeneous across multiple scales and exhibit variations in production performance across wells. The production variation is influenced by a large variation in production drivers that simultaneously affect the production. Examples of these drivers include reservoir properties such as hydrocarbon-filled porosity, moveable hydrocarbons, matrix permeability, relative permeability and pressure/volume/temperature, completion properties such as stress-state and natural fractures, and stimulation (pumping) parameters. Reservoir simulation constitutes one of the best tools to understand the dominant production drivers because of the multidisciplinary data required to build simulation models for unconventional reservoirs. Because of the orders of magnitude of difference in matrix permeability between conventional and unconventional reservoirs, pressure gradients from the sandface to the formation (pressure drawdowns) are larger in unconventional reservoirs and drainage radii are more likely to be smaller. Therefore, in the case of shale reservoirs, single-well models usually suffice except for the case of multiwell pads. Very fine grid cells (on the order of inches to a few feet) are used close to, and immediately surrounding, the perforation clusters, whereas in conventional reservoirs, coarser grid cells are used, especially in full-field models, even with local grid refinements.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195951, “Case Study: Optimizing Eagle Ford Field Development Through a Fully Integrated Work Flow,” by Adrian Morales, SPE, Robert Holman, and Drew Nugent, Chesapeake Energy, et al., prepared for the 2019 SPE Annual Technical Conference and Exhibition, Calgary, 30 September-2 October. The paper has not been peer reviewed. An integrated project can take many forms, depending on available data, from a simple horizontally isotropic model with estimated hydraulic fracture geometries used for simple approximations to a large-scale seismic-to-simulation work flow. The complete paper presents a large-scale work flow designed to take a vast amount of data into consideration. The work flow can be scaled for projects of any size, depending on the data available. Introduction In 2017, Chesapeake Energy launched an investigation to evaluate ways of improving overall recoveries within the lower Eagle Ford. Two theoretical approaches were generated to optimize the company’s development plan: modification to current completion designs to achieve greater near-well fracture complexity and modification of targeting strategies to more-effectively drain the Eagle Ford interval. Methodology To evaluate these approaches, the company acquired multiple data sets to provide an integrated study. An already developing and productive area was selected in southwest Texas to examine completion design and targeting strategies while attaining a data set to allow for complex completion monitoring and reservoir simulations to aid in subsequent development optimization while maintaining at least type-curve production. Microseismic was acquired on three wells with multiple downhole arrays used to visualize how fracture geometries were affected by completion design changes. For quality control, data from ultrasonic image tools, cement-bond logs, and gyros were acquired to increase confidence in microseismic results. Time-lapse 2D lines were acquired pre- and post-hydraulic fracture to measure seismic changes induced by completions. Water- and oil-soluble tracers were run to determine hydraulic fracture extent and drainage footprint. Parent wells were instrumented with surface pressure gauges to characterize hydraulic fracture hits. With permanently installed fiber, a post-hydraulic fracture downhole camera was run to examine cluster efficiency per completion design. Core and quad-combo logs were taken in the area to analyze compositional similarities in oil signatures compared with produced oil and to calibrate petrophysical and geomechanical values. Oil samples were collected and analyzed to derive an equation of state for fluid characterization and reservoir simulation. Natural fracture characterization was performed to determine the pre-existing geological fabric of the rock using lateral electrical borehole images, a field outcrop study, and quad-combo and fracture-identification logs derived from drilling data. Multiple facture calibration tests were collected in the study area at different target intervals to calibrate vertical stress profiles and examine reservoir pressures. Lastly, following 1 year of production, a temporary rod-conveyed fiber-optic production log was run to determine cluster contribution based on completion design. The independent data sets were integrated on a common commercial software platform for geomodel creation, discrete natural fracture characterizations, hydraulic fracture simulations, and reservoir simulations. An integration strategy was developed to bring together the vast amount of data acquired. The work flow is a simplified representation of the data interdependencies and was used throughout the study. Only five data acquisitions are shown to overlap; however, any change in interpretation can lead to revision and iteration of several interdependent segments.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195524, “Insight Into Hydraulic Fracture Geometries Using Fracture Modeling Honoring Field-Data Measurements and Post-Fracture Production,” by Neil Stegent, SPE, Ron Dusterhoft, SPE, and Hari Menon, SPE, Halliburton, prepared for the 2019 SPE Europec featured at the 81st EAGE Conference and Exhibition, London, 3-6 June. The paper has not been peer reviewed. Using planar fracture models to match treatment pressure and improve understanding of fracture-geometry generation is not a new concept. At some point during the progression from vertical to horizontal wellbores, however, many within the industry forgot about the learnings that still can be gained from current fracture models. The complete paper demonstrates the benefits of honoring data measurements from a multitude of potential sources to help engineers do a better job of including more diagnostics into routine operations to provide additional insight and result in improved models and completion designs. Introduction Many sources of reservoir, drilling, and completion data and measurements are available to well operators. However, in nearly all cases, a balance must be achieved of what can be captured at a reasonable cost and the associated value of the information gained. It is unrealistic to acquire high-density data sets for every well in an entire field because of the prohibitive costs, but understanding what is available and knowing what questions need to be answered can enable a more-cost-efficient means of acquiring the correct information to address specific challenges. Diagnostic Data and Measurements The complete paper contains a summary of some relevant tools and technologies and a short description of the information that can be captured, the importance of this information, and how it can be used; examples are discussed wherein some of these tools are combined to provide useful completion-design information. Gathering Production Information Production-logging tools are useful for characterizing and better understanding reservoir performance and optimizing production. The production logs are typically run after the completion of a well, either in a cased or open hole. The logs are used to determine the allocation of wellbore inflow to different zones and to identify areas of production problems such as crossflows and leaks. In low- and ultralow-permeability reservoirs with horizontal drilling and increases in the number of fracturing stages, understanding the production rate of each fracturing stage is important. Therefore, a post-fracturing evaluation might be necessary for optimization of multistage fracture design. Artificial-lift installations on post-fracture completions can be an obstacle to acquiring good production-log data in unconventional wellbores. Tracer Technologies Multiple tracer technologies are available for fracture diagnostics, and, while all such methods provide useful information, the results can be misleading when the methods are used independently. Conditions within the reservoir are changed significantly during the completion process and again during production. While wells can be in communication during hydraulic fracturing operations, that does not mean that the same wells will be in communication during production, because not all of the created fractures will remain open and conductive when production and reservoir depletion has begun.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195221, “Fracture Diagnostics Using Distributed Temperature Measurements During Stimulation-Fluid Flowback,” by Yilin Mao, SPE, and Mehdi Zeidouni, SPE, Louisiana State University, and Caroline Godefroy, Interpretive Software Products, et al., prepared for the 2019 SPE Oklahoma City Oil and Gas Symposium, Oklahoma City, 9-10 April. The paper has not been peer reviewed. The significant temperature difference between the fractured and nonfractured regions during the stimulation-fluid flowback period can be useful for fracture diagnosis. Recent developments in downhole temperature-monitoring systems open new possibilities to detect these temperature variations to perform production-logging analyses. In the complete paper, the authors derive a novel analytical solution to model the temperature signal associated with the shut-in during flowback and production periods. The output of this work can contribute to production-logging, warmback, and wellbore-storage analyses to achieve successful fracture diagnostic. Introduction Information about individual fractures is critical in determining whether fracturing jobs have been successful or refracturing is required. Exploring new methods to evaluate fracture characteristics has been the focus of recent research activities. Triggered by field implementations and observations, research has been conducted to investigate temperature profiles during the early hydraulic fracturing and late production periods to characterize fractures. Current research on the use of temperature data to evaluate hydraulic fractures and reservoirs focuses on developing forward numerical and semianalytical models to predict temperature profiles during fracturing and production. As a prelude to the production period, stimulation fluid flowback is often performed after hydraulic fracturing operations to remove the remaining fluid and loosen proppant from the wellbore. Because recording the flowback operation may be required already by regulations, the cost of collecting data from the flowback period is minimal. As a result, ongoing research on analyzing data from the flowback period has aimed to diagnose fracture design and efficiency, characterize key reservoir properties from the chemical composition of the flowback fluids, and predict long-term production. Such efforts are based on the critical timing of the flowback period - a transition between what happened during completion and what will happen during production. The potential temperature modeling on the flowback period proposed here shares the same insight. Shortly after hydraulic fracturing stimulation, the temperature in the fractured region is still lower than in the nonfractured region. The objective of this work is to perform fracture diagnostics with the flowback temperature signal. The main objective is identifying inflow temperature from each of the fractures, critical as an input for production-logging-tool (PLT) analysis. Preliminary simulation studies found that the inflow temperature is identical to the surrounding fractured region temperature, which is masked by the heating effect introduced from wellbore fluid flow after the shut-in test (afterflow). Therefore, the authors propose analyzing this heating effect with analytical and numerical models, which are described in the complete paper. Once the heating effect is quantified, the inflow temperature for each fracture can be obtained.