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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199707, “A Data-Driven Approach to Screenout Detection for Horizontal Wells,” by Xiaodan Yu, Whitney Trainor-Guitton, and Jennifer Miskimins, SPE, Colorado School of Mines. The paper has not been peer reviewed. Multistage hydraulic fracturing has gained global popularity as more tight geologic formations are developed economically for hydrocarbon resources. However, screenout is a major issue caused by the blockage of proppant inside the fractures. The complete paper presents a screenout-classification system based on Gaussian hidden Markov models (GHMMs) trained on simulated data that predicts screenouts and provides early warning by learning prescreenout patterns in surface-pressure signals. The methodology is a useful tool for early screenout detection and shows the promise of other fracturing time-series data analysis. Materials and Methods In the complete paper, fracturing treatment data are generated using a hydraulic fracturing simulation software. A well-logging profile acquired from a vertical well located in the Denver-Julesburg (DJ) Basin is used to generate the reservoir rock properties in the fracturing simulations.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199023, “Evaluation of Well Performance Using Data From Fiber-Optic Sensors in Wells of a Pilot Polymerflooding Test, Orinoco Basin, Venezuela,” by Andres Ramirez, Edgar Vasquez, and Luis Quevedo, PDVSA, et al. The paper has not been peer reviewed. The complete paper describes a pilot test using polymerflooding in which evaluating the performance of injector wells was a main priority. The authors chose to complete the wells using a distributed temperature sensor. The paper describes how a better understanding of the connection between the well and the reservoir can improve reservoir simulation models, the decision-making process, and well-performance evaluation. The authors also stress the importance of determining the possibility of unswept areas in the reservoir, which could result in low volumetric sweep efficiency and, consequently, low recovery factor. Introduction The field is in the Orinoco Belt, mainly unconsolidated Miocene sandstone, and has produced heavy oil since 1999. At the time of writing, more than 711 producing wells have been drilled since the beginning of the exploitation of the field. After reaching a production plateau of 200,000 B/D, enhanced-oil-recovery technologies have been considered. One of these is polymerflooding. A pilot test was conducted in an area of the field in which conditions did not indicate application of any thermal recovery technique. The reservoir pressure at project startup was 315 psia, with a reservoir temperature of 115.5°F. Average porosity was 0.32, reservoir absolute permeability was estimated to be between 25 and 15 darcies, and reservoir thickness was 25 ft. Oil mobility was very low because of high viscosity. The pilot test began in 2016. Polymer at a concentration of 900 ppm was injected in a deltaic sedimentary environment composed of distributary channel fills and mouth bars. Polymer was injected through three injector wells. The objective of the test is to provide rapid answers to questions about injection performance, polymer stability, and the effect of heterogeneities. The results will determine if the technology represents a feasible opportunity for future development of the field. The objectives of the control plan in this phase include the following: - Establish how much of the horizontal section contributes to the well injectivity - Estimate an injection profile distribution - Determine if important changes occur during injection
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.92)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 207698, “Twenty Years of Horizontal Multistage Completions: A Summary of Industry Evolution in Unconventional and Conventional Plays,” by Alberto Casero, SPE, BP. The paper has not been peer reviewed. The innovative idea behind the shale gas revolution was the combination of horizontal well drilling and hydraulic fracturing, which allowed for an increase in the surface area available for hydrocarbon flow and overcame the slow, shallow hydrocarbon release from the source rock. To achieve the high number of hydraulic fractures needed for economical production, different execution techniques evolved in what became known as horizontal multistage fracturing (HMSF) completions. The complete paper covers the most-common types of HMSF completion systems and includes a section about the use of these completions in conventional plays. This synopsis focuses on HMSF use in unconventionals. Well Architecture as a Function of Location and Reservoir Properties As hydraulic fracturing and horizontal wells became popular, many preconceptions associated with hydraulic fracturing had to be reimagined. The concept of stimulated reservoir volume (SRV) was introduced; contacting as much rock as possible was the new priority of hydraulic fracturing, while more-conventional fracturing concepts such as fracture conductivity and planar fractures became secondary or irrelevant. Fracture-production interference and fracture complexity became an aim rather than representing a risk. Very high fracture count and reduced well spacing became a necessity, and, inevitably, a mass-production approach had to be applied rather than an individual fit-for-purpose design for each well or fracture. These changes brought a substantial shift in primary well-construction costs, with completion costs in many cases surpassing the drilling cost by a factor of 40–50%. Multistage fracturing with complex and developed fracture networks or SRV, which is at the basis of unconventional developments, requires a robust infrastructure and resource availability to allow easily moving large amounts of proppant (typically natural sands) and water. This can be challenging for remote locations. When permeability decreases, cased and perforated completions with hydraulic fracturing or acid stimulations become the norm. When permeability decreases even further, multistage fractures and horizontal wells are applied; finally, in ultratight gas and shale gas, horizontal multistage fracturing represents the only option.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202896, “Optimizing Production From Marginal and Challenging Prospects To Unlock Field Potential: Success Cases in the Jasmine Field, Gulf of Thailand,” by Mukminin Yusuf, SPE, Pattarapong Prasongtham, SPE, and Theeranun Limniyakul, SPE, Mubadala Petroleum, et al. The paper has not been peer reviewed. The development of marginal volumes in the Jasmine field is part of the operator’s strategy to extend the field’s life, involving the exploitation of increasingly challenging prospects. The complete paper highlights two case studies to illustrate how the operator has developed marginal prospects to unlock the Jasmine field’s remaining potential successfully. The use of autonomous inflow control devices (AICD) has played a significant role in optimizing production in reservoirs with small oil rims and thick gas caps. Jasmine Field The designation “Jasmine field” is commonly used to refer to both the Jasmine field and the neighboring Ban Yen field, which are essentially one integrated field from an operational perspective. The fields are in the Gulf of Thailand, approximately 300 km southeast of Bangkok in depths of 190 to 200 ft (Fig. 1).
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201450, “Reducing the Volume of Water Needed For Hydraulic Fracturing by Using Natural-Gas-Foamed Stimulation Fluid,” by Raj Malpani, SPE, Chris Daeffler, and Sandeep Verma, SPE, Schlumberger, 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. Using natural-gas (NG) -foam fracturing fluids reduces the enormous water requirements for stimulation by as much as 60 to 80% and poses benefits for productivity in water-sensitive formations. The study outlined in the complete paper aims to characterize hydraulic-fracture geometry and quantify the expected production when using an NG-foam fracturing fluid. Using validated models, the authors provide a comparative analysis to determine the advantages of using NG foams relative to conventionally used slickwater, linear gel, and crosslinked fluid. NG-Foam Fluids Although foamed fluids were first used in the 1960s, the use of nitrogen (N2) and carbon dioxide (CO2) foams has not been widely practiced because of cost, complexity, and unproven production benefits. The use of NG-foam fracturing fluid is not widespread either, but this study attempts to identify specific regions and reservoirs where the use of these fluids may lead to economic and long-term production benefits. The authors write that using NG foams is likely to provide long-term sustainable benefits in areas where water procurement and disposal costs are high, where natural gas may be available from a central processing facility through pipelines, and where the reservoir is relatively shallow and contains clay-bearing minerals. This work is inspired by a program sponsored by the US Department of Energy to investigate NG as an alternative to N2 and CO2 in foamed fracturing fluids. Initially, the project focused on identifying a thermodynamic path-way to use NG obtained from producing wells and processing plants. The study later extended into laboratory-scale experiments to measure NG-foam-fluid rheology, which was found to be comparable to foams based on N2 and CO2. The first step in the work flow is to build a static geological model to capture the reservoir description. The subsequent step is to use the rock characterization to simulate the induced hydraulic fractures. The hydraulic-fracture simulator also predicts the proppant distribution and its conductivity and treating pressure. The simulated treating pressure is matched with observed pressure during stimulation treatment to calibrate the hydraulic-fracture model. The hydraulic fractures are then gridded in the static geological model to generate the reservoir model for flow modeling. This is a critical step in the process because the static model is linked to the dynamic simulator without losing the details of the hydraulic fractures. The reservoir simulator is used to match the historical production performance to calibrate the reservoir model and forecast future production profiles. This hydraulic-fracture modeling, followed by the flow-modeling process, is repeated for various pumping schedules and recipes to perform a sensitivity analysis, which is detailed in the complete paper.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.54)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201132, “The Future of Plunger Lift Control Using Artificial Intelligence,” by Ferdinand Hingerl and Brian Arnst, SPE, Ambyint, and David Cosby, SPE, Shale Tec, et al., prepared for the 2020 SPE Virtual Artificial Lift Conference and Exhibition - Americas, 10-12 November. The paper has not been peer reviewed. Dozens of plunger lift control algorithms have been developed to account for different well conditions and optimization protocols. However, challenges exist that prevent optimization at scale. To address these challenges, a plunger lift optimization software was developed. One aspect of this software is enabling set-point optimization at scale. This paper will present the methodology to do so, detailing three separate areas working in unison to offer significant value to plunger lift well operators. Introduction Even in vertical wells, plunger lift presents significant challenges to optimization. Despite their mechanical simplicity, plunger lifted wells produce large amounts of data, and the combinations of possible set points to optimize the well are many. Additionally, plunger lift wells can present a variety of different types of anomalies and problems that require a robust understanding of the underlying physics and mathematics. Such problems then are amplified when applied to horizontal well applications. The underlying physics and mathematics applied throughout the years for vertical wells do not produce accurate results for horizontal wells. Additionally, the anomalies produced in horizontal wells are more complex. Finally, typical production engineers and well optimizers now regularly look after more than 150—and often more than 500—wells, creating additional resource constraints to optimizing a field of plunger lift wells. The presented plunger lift optimization software was implemented by creating a secure connection between the operator’s supervisory control and data acquisition (SCADA) network and the cloud. As new data are generated by the SCADA network, they are automatically transmitted to the cloud and processed. Plunger Lift Control Algorithm Overview These algorithms are the software code that determines when the well opens and when the well closes. Even though the algorithms only control well open/close, the plunger moves through four stages of plunger operation to complete one cycle: plunger fall time, casing pressure build time, plunger rise, and after flow (or production). Optimizing each individual stage is critical to ideal well production. Plunger fall time is the time required for the plunger to descend from the lubricator to the bottomhole assembly (BHA). Currently, operators use the manufacturer’s anticipated fall time, trial and error, previous knowledge, acoustical plunger tracking, and plunger fall applications to set the appropriate fall time in the controller. A “fudge factor” is often applied to help ensure that the fall timer does not expire before the plunger reaches the BHA. Plunger fall time is affected by many changing variables: plunger condition, tubing condition, liquid height, and gas and liquid density. These variables make it difficult for a fall timer set once to represent accurately the correct time required for the plunger to reach the BHA on every cycle.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191406, “Using In-Situ Mechanical Rock Properties To Target Landing Zones and Improve Completions in the Permian Basin,” by E.L. Scott, A.M. Hildick, and C. Glaser, Fracture ID, and E. Petre, Hunt Oil, prepared for the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18 October. The paper has not been peer reviewed. Optimizing horizontal well placement is not limited to identifying the most-favorable reservoir, but also involves identifying the ideal target window within that reservoir. Gathering drill-bit geomechanics data provides a lower-cost and lower-risk method to acquire mechanical rock properties in long horizontal wellbores. By integrating data sets with mechanical rock properties recorded while drilling, operators can have significantly higher confidence in choosing a target landing zone and improving completions. The complete paper presents two detailed case studies from the Permian Basin. Introduction In this paper, the authors combine the characterization of petrophysical and geomechanical properties into what they call a petromechanical work flow. Typically, petrophysical and geomechanical properties are characterized using data acquired by wireline logs. In vertical wells, wireline logs represent, traditionally, the least-intrusive manner of acquiring high-resolution data. With additional cost and rig time, cores of the formation rock can be exhumed to analyze its properties on surface. In horizontal wells, both wireline logs and conventional cores are costly and operationally challenging. Because of the economic and operational burden, operators typically avoid collecting geomechanical data in horizontal wells. Besides these traditional measurements, the novel technique of using drill-bit geomechanics can enable measurement of geomechanical properties while drilling. Compared with wireline logs and core analysis, this technique is less costly and has a lower risk in long horizontal wells. Drill-Bit Geomechanics Drill-bit geomechanics provides mechanical properties through continuous, high-resolution measurements of drilling-induced vibrations. Triaxial accelerometers, which sample at 1 kHz, record the vibrations while positioned directly behind the drill bit. Earthquake seismology models allow a transformation of the high-frequency, triaxial, drilling-induced vibrations into mechanical rock•properties. The drill-bit geomechanics method determines mechanical properties by using stress-strain relationships and isotropic stiffness coefficients. Additionally, the method describes anisotropy by solving for transversely isotropic (TI) interpretations of the rock matrix. Typically, a vertically transverse isotropic (VTI) matrix contains high shale content or other laminar bedding, while a horizontally transverse isotropic (HTI) matrix contains vertical bedding or fractures. In this paper, the authors define VTI anisotropy as bedding and HTI anisotropy as fracture intensity.
- North America > United States > Texas (0.82)
- North America > United States > New Mexico (0.82)
- Asia > Middle East > Oman > Muscat Governorate > Muscat (0.25)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.55)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Earthquake Seismology (0.54)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Well Drilling > Wellbore Design (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190860, “Evaluating the Impact of Lateral Landing, Wellbore Trajectory, and Hydraulic Fractures To Determine Unconventional Reservoir Productivity,” by Piyush Pankaj, Priyavrat Shukla, SPE, Ge Yuan, and Xu Zhang, Schlumberger, prepared for the 2018 SPE Europec featured at the 80th EAGE Annual Conference and Exhibition, Copenhagen, Denmark, 11–14 June. The paper has not been peer reviewed. Inconsistent production performance from wells completed in similar pay zones has been observed when shale formations are exploited through horizontal wells. This paper demonstrates the need to couple the wellbore model to the reservoir-simulation and hydraulic-fracturing model in shale formations to optimize well landing, trajectory profile, and long-term productivity. The authors aim to demonstrate and deconvolute the well-trajectory plan with an integrated parametric study that helps to improve well productivity. Methodology To plan a well profile, two critical pieces of information are required: Lateral landing depth, and well trajectory originating from the landing depth. To reach the targeted landing depth, the well trajectory undergoes a certain buildup of curvature deviating from the vertical section and, eventually, when the landing depth is reached, the designed trajectory profile is maintained and continued for the horizontal wellbore. The authors evaluated well trajectory and well productivity on the basis of the effect of the following parameters to guide well-trajectory planning: Hydraulic-fracturing fluid Natural fracture network Wellbore trajectory, undulations, toe up, toe down, or combinations Production operations such as proppant flowback, fracturing choke management, and well shutdown Geological Review of the Model A 3D earth model in the Permian Basin for the Wolfcamp shale was used to develop a work flow for determining well landing and well trajectory. The Wolfcamp shale covers most of the Midland Basin and ranges in thickness from 200 ft in the north of the basin to 2,600 ft in the south. The entire play is dominated by a fine-grained, naturally fractured source rock. The depths range from 5,500 to 11,000 ft. The Wolfcamp is slightly overpressured, with the pressure gradient varying between 0.55 and 0.70 psi/ft. In the past few years, the Wolfcamp has become one of the most profitable and exploited unconventional plays in the US. Almost all of the operators are collecting a significant share of their well inventory, which yields over 1,000 BOPD routinely in initial-production rate. The production declines within a short period (6 to 9 months). The recovery factors remain in the single digits for most operators. The Wolfcamp, Spraberry, and Bone Spring formations are the most prolific in the basin. Defining Landing Depth The proposed solution considers applying an end-to-end cycle of a streamlined work flow that starts with sampling engineered landing location points in the geomodel defined by the user on the basis of reservoir-quality (RQ) cutoffs. The first step is building the geological model around the sweet spot. This geological model contains petrophysical and mechanical properties of the rock along the depth of the targeted interval.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- Europe > Denmark > Capital Region > Copenhagen (0.25)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191783, “Drilling Extended Laterals in the Marcellus Shale,” by Joshua Doak, SPE, Matthew Kravits, SPE, Michael Spartz, SPE, and Pat Quinn, Range Resources-Appalachia, prepared for the 2018 SPE/AAPG Eastern Regional Meeting, Pittsburgh, Pennsylvania, USA, 7–11 October. The paper has not been peer reviewed. A drilling team has focused on increasing lateral lengths in the Marcellus Shale. The team determined which operational practices would need to be revised in order to drill and case laterals in excess of 18,000 ft. During a 12-month period of revised processes and upgrades, the team drilled 34 horizontal wells, each exceeding 12,000 ft in lateral length, which represented the first Marcellus lateral to exceed that length. Introduction At the time of writing, the team had drilled more than 1,050 Marcellus wells in the state of Pennsylvania. In the first decade of development (2006–2016), it drilled hundreds of Marcellus horizontal wells with laterals ranging from 1,500 to 11,000 ft. The average lateral length over that period was 3,950 ft. In late 2016, focus was placed on developing the core acreage of the Marcellus field with extended laterals. This change in planning resulted in dozens of wells being scheduled that would feature lateral lengths exceeding 12,000 ft. As a result, the average lateral length increased to 9,450 ft over a span of 200 additional wells drilled starting in 2017. Throughout the initial years of drilling Marcellus horizontal wells, tools and practices were used that efficiently drilled laterals under 4,000 ft in length. Routine operations included use of rigs with 5,000-psi circulating systems, directional tools with bent housing motors, saltwater-based polymer drilling fluids, and standard drilling procedures. In re-evaluating processes, the team focused on cost per lateral foot (Fig. 1). Increased performance coupled with maintenance of consistent overall drilling costs helped lower the cost per lateral foot. Comprehensive studies followed by field tests were implemented in preparation for the extended laterals. Rig Selection While focusing on what are now deemed as shorter laterals, the team had experienced success drilling with super single rigs because of their versatility and efficient design. The second iteration of a rig fleet to meet the challenges of developing the Marcellus Shale came in the form of high-performance rigs with new enhanced horizontal-drilling capabilities. The team used this style of rig to meet lateral-length challenges successfully from 2010 until late 2016, drilling 805 Marcellus horizontal wells in that time period. In the spring of 2016, the first 14,000-ft lateral was placed on the drilling schedule for the end of that same year. The rig fleet would need to be upgraded in order to meet the upcoming required changes in lateral length. Size of the rig and equipment became another critical consideration for the rig fleet, because, by then, returning to sites with actively producing wells had become routine, so the upgraded rigs selected would have to fit onto these sites.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (9 more...)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191695-18RPTC, “Complex Approach to Fault Description While Geosteering for Maximization of Reservoir Contact in Horizontal Wells in West Siberia Oil Fields,” by Vladislav V. Krutko, Tatyana A. Yurkina, SPE, and Dmitriy Y. Kushnir, Baker Hughes, a GE Company, and Valery B. Karpov, RITEK, prepared for the 2018 SPE Russian Petroleum Technology Conference, Moscow, 15–17 October. The paper has not been peer reviewed. This paper presents an interdisciplinary approach to the description of tectonic dislocations made on the basis of interpretation of seismic data, petrophysical analysis of well-logging data in horizontal wells, and inversion of a multifrequency propagation tool. A consistent approach to fault identification and description is presented on the basis of seismic surveys and logging-while-drilling (LWD) data in horizontal wells in a western Siberian oil field. Seismic Methods of Tectonic-Fault Interpretation Estimation of seismic methods of fault detection was performed on materials acquired from one of the fields in the Frolov oil-and-gas district. The observed territory of the oil field is characterized by complex geological structure—namely low effective reservoir thickness, thin layering of sandstones and silts, low porosity, low-permeability reservoir zones, and tectonic block structure. When drilling in reservoirs of low thickness, knowing the precise position of the horizontal wellbore relative to the structure is critical. The basis of drilling planning is a structural map of the reservoir top. After field jobs were complete and the results of the wide-aperture 3D seismic survey of the considerable refinement of the top structure of the reservoir were obtained, the morphology of all earlier identified structural forms was completed. A faulted and blocked principal model of the reservoir was created that formed the basis for a well-pad positioning scheme, as well as for usage in horizontal-well drilling. Horizontal Well 2301G was planned in the northwest region of the field. For reservoir-model construction, a structural map prepared from seismic-survey interpretation was used. An outcrop of the structural map with Well 2301G in place is presented in Fig. 1. A rare well network in the drilling area led to high uncertainty regarding structure parameters and risk of penetrating a fault. As an offset, Well 75B3 was used (Fig. 1). In this offset well, the horizon AC3 represented a thin layering of silt, shaly sandstone, and tight rocks. The thickness of the AC3 horizon was 13.2 m. During the drilling of the transport section, the wellbore of Well 2301G penetrated the top of the AC3 horizon at 1912.12-m true vertical depth, which coincided with the structural surface prognosis made on the basis of seismic data. The blocked model of the AC33 horizon is complex; the vision of the structure of the target reservoir can change significantly while drilling and penetrating the reservoir. According to seismic data, the possibility exists of crossing three faults along the planned horizontal section of Well 2301G.
- Geology > Structural Geology > Tectonics (0.76)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)