Multistage Completion Research Articles

Optimization of Horizontal Well Location and Completion to Improve Oil Recovery for an Iraqi Field

Exploitation of mature oil fields around the world has forced researchers to develop new ways to optimize reservoir performance from such reservoirs. To achieve that, drilling horizontal wells is an effective method. The effectiveness of this kind of wells is to increase oil withdrawal. The objective of this study is to optimize the location, design, and completion of a new horizontal well as an oil producer to improve oil recovery in a real field located in Iraq. “A” is an oil and gas condensate field located in the Northeast of Iraq. From field production history, it is realized the difficulty to control gas and water production in this kind of complex carbonate reservoir with vertical producer wells. In this study, a horizontal well design with multi-stage completion is studied and proposed to find optimal oil recovery in the southeast region of the selected field. A bulk oil well sector model is used to simulate the fluid flow of a single-porosity/single-permeability model. Then, a sensitivity analysis has been run to optimize; the well trajectory path, different scenarios on well oil and water production potential, and well completion design. The result of the well sector simulation indicates that the well trajectory with an Azimuth of 89 degrees and with a multi-stage completion design has better production performance under water production constraints. Optimum oil production rates of 1000 to 2000 STB/day, as delaying and controlling early gas and water production challenges is achieved.

Enhancing Well Performance and Economic Value via Better Well Completion Design—A Delaware Basin Case Study

Summary Operator H’s wells on University Lands acreage in the Delaware Basin were completed with a perforation cluster spacing of around 45 ft and a fracturing fluid volume of about 25 bbl/ft. However, other operators in this area used half or even smaller perforation cluster spacing and a few times more fluid. As a result, the estimated ultimate recovery (EUR) of non-Operator H wells is about 18% higher than that of Operator H’s wells in the Wolfcamp Formation, indicating that Operator H’s completion design can be greatly improved. Therefore, our objective in this work is to locate a better completion design for Operator H’s wells and increase the economic value of the operator and the landowner. An integrated fracturing→well performance→economics workflow is implemented to optimize the completion design for Operator H’s wells. First, a 3D geological and geomechanical model is built and calibrated with historic multiwell multistage completion and production data. A decline curve analysis (DCA) is also performed to double-check our history-matching (HM) model. Then, we use an unconventional fracturing model to simulate fracture propagation and proppant transport for multiple wells on the same pad under various completion designs. The resultant complex fracture network is converted into unstructured gridblocks for reservoir-performance simulation. Finally, economic analysis is incorporated to evaluate the net present value (NPV)and internal rate of return (IRR) to identify the optimal completion design. Numerical results show that with the same amount of fluid and proppant, halving perforation cluster spacing gives shorter and more nonuniform fractures. Doubling the fluid volume creates 40% more fracture area in our target area and activates more microfractures along the wellbore. Also, a smaller stage spacing significantly improves cluster efficiency and well production. For the Wolfcamp Formation in the Delaware Basin, tighter cluster spacing (10–20 ft) with higher fluid volume (75–90 bbl/ft) plus a smaller stage spacing (~120 ft) greatly improves fracturing efficiency and well performance. Our recommended optimal completion design would increase Operator H’s NPV10 by USD 226 million on its undeveloped Wolfcamp A Formation (WCA). With the latest modeling technologies, we model the complex fracture propagation and associated well performance and efficiently identify a better completion design with economic analysis. Compared to multiple field pilot tests needed, the integrated workflow in this work helps operators significantly reduce the time and financial cost to optimize completion design and can be easily adapted to other unconventional wells given their unique data set.

Single Trip Deployment of Multistage Completion Liners Through the Use of Interventionless Flotation Collars

Summary In difficult wellbores, the traditional method for deploying liners was to run drillpipe. The case studies discussed in this paper detail an alternative method to deploy liners in a single trip on the tieback string so the operator can reduce the overall costs of deployment. Previously, this was not often practical because the tieback string weight could not overcome the wellbore friction in horizontal applications. In each case, a flotation collar is required to ensure there is enough hookload for the deployment of the liner system. The flotation collars used are an interventionless design using a tempered glass barrier that shatters at a predetermined applied pressure. The glass debris is between 5 and 10 mm in diameter and can be easily circulated through the well without damaging downhole components. This is done commonly on a cemented liner and cemented monobore installations, but more rarely with openhole multistage completions. The authors of this paper have overseen thousands of cemented applications of this technology in Western Canada, the US onshore, Latin America, and the Middle East. For openhole multistage completions, the initial installation typically requires a ball drop activation tool at the bottom of the well to set the hydraulically activated equipment above. The effects of circulating the glass debris through one specific style of activation tool were investigated. Activation tools typically have a limited flow area and could prematurely close if the glass debris accumulates. Premature closing of the tool would leave drilling fluids in contact with the reservoir, potentially harming production. The testing was successfully completed, and the activation tool showed no signs of loading. This resulted in a full-scale trial in the field, where a 52-stage, openhole multistage fracturing liner was deployed using this technology. Through close collaboration with the operator, an acceptable procedure was established to safely circulate the glass debris and further limit the risk of prematurely closing the activation tool. This paper discusses the openhole and cemented multistage fracturing completion deployment challenges, laboratory testing, and field qualification trials for the single trip deployed system. It also highlights operational procedures and best practices when deploying the system in this fashion.

One Stage Forward or Two Stages Back: What Are We Treating? Identification of Internal Casing Erosion during Hydraulic Fracturing—A Montney Case Study Using Ultrasonic and Fiber-Optic Diagnostics

SummaryPlug-and-perforation (plug-and-perf) multistage hydraulic fracturing completions in unconventional reservoirs rely on complete hydraulic isolation from the previous stage to ensure effective treatment of the active stage. Failure to isolate stages can be a result of partially set plugs, plugs set in wellbore debris or deformed casing, unqualified pressure/temperature rating of plugs, and so on. This paper presents a case study with field examples in which unexpected casing erosion occurred at the setting depths of the dissolvable fracturing (frac) plugs during hydraulic fracturing and subsequently resulted in loss of interstage isolation.A 12-well, four-layer, cube pilot was designed with permanent fiber-optic cable to collect distributed acoustic sensing (DAS), distributed temperature sensing (DTS), and distributed strain sensing (DSS) data as well as downhole pressure gauges for development insight and future completion optimization. The cable was mapped, and oriented perforation techniques placed entry holes opposite the fiber along the wellbore, and no loss of communication was observed during perforating operations. However, fiber-optic signal was lost during hydraulic fracturing operations on one or more stages in all four instrumented horizontal wells. Real-time DAS/DTS analysis indicated the fiber breaks were consistently occurring below the lowermost perforation cluster in the stage, at or very near the frac plug setting depth. Step-down tests were also performed and showed significantly enlarged effective treating area. Based on this observation, post-frac downhole imaging tools were deployed to investigate potential casing and perforation erosion.Downhole imaging data clearly showed the casing was severely eroded at several locations. Additional interrogation of the damage with respect to plug design components indicated that damage always occurred near the plug sealing element. By integrating the analysis of DAS/DTS, step-down tests, and ultrasonic imaging, it was determined that the frac plug bypass was creating a loss of casing integrity at the plug set location. Casing integrity loss resulted in multiple fiber-optic cable breaks and lowered the ability to evenly distribute slurry into treatment clusters. Fiber-optic data analysis showed that 50% of the larger outer diameter (OD) dissolvable frac plugs had bypass compared to 100% bypass for the smaller OD high-expansion, dissolvable plugs.To establish key patterns and identify critical variables that influence stimulation effectiveness, it is important to obtain several different diagnostic data sets and perform an integrated evaluation using all available information. This study also reinforces the need for operators and manufacturers to work together to design and qualify frac plugs against realistic downhole conditions, particularly in areas with potential casing deformation issues. Industry innovation is required to enable fracturing operations to continue through deformed casing. This includes advancing equipment, tools, and techniques for plug-and-perf and other multistage completion methods.

One-Trip Multizone Sand-Control-Completion System in the Gulf of Mexico Lower Tertiary

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27183, “Current State of the One-Trip Multizone Sand-Control-Completion System and the Conundrum Faced in the Gulf of Mexico Lower Tertiary,” by Bruce Techentien, Tommy Grigsby, and Thomas Frosell, Halliburton, prepared for the 2016 Offshore Technology Conference, Houston, 2–5 May. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission. This paper provides perspective on the current state of multizone completion technology and issues encountered in the industry with developing a system that offers increased capabilities to meet the increasing challenges presented by the Lower Tertiary in the Gulf of Mexico (GOM). The multizone technology has proved to be an enabler for cost-efficient completions in the shallow-well environment and in the high-cost ultradeepwater environment requiring high-rate fracture-stimulation treatments. Lower Tertiary GOM The Lower Tertiary play is south and west of the Miocene area in the GOM and is, consequently, in deeper water. The Lower Tertiary is located approximately 175 miles offshore and is estimated at 80 miles wide and up to 300 miles long. Water depths are from 5,000 to 10,000 ft. Production targets are at depths of 10,000 to 30,000 ft subsea. The Tertiary trend is from 66 million to 38 million years old. Within the Lower Tertiary, the Lower Wilcox portion presents sheet to amalgamated-sheet sands considered to be part of a regional basin floor fan system. The Late Paleocene to Early Eocene (Wilcox equivalent) reservoirs are considered to be laterally extensive sheet sands that were deposited in deep water. These reservoirs are distributed across an area largely covered by the allochthonous Sigsbee salt canopy. It is this canopy that causes additional problems beyond merely the water depth and the well depth required to reach the reservoirs. These exploration plays depend on understanding the updip fluvial/deltaic stratigraphic architecture and the potential for partitioning of reservoir-quality sandstones across the depositional shelf into the slope and basin floor environments. The Lower Tertiary is estimated to contain up to 15 billion bbl of oil. Current State of Multizone Technology The Generation IV multizone system has been deployed successfully in the Lower Tertiary by multiple operators. To the authors’ knowledge, the multistage completion system and enhanced single-trip multizone fracturing systems had been installed in 10 wells as of the summer of 2015, with additional well installations planned. These systems are rated to 10,000 psi, and the enhanced single-trip multizone tool system offering an open-hole variant was installed in one five-zone completion.

Qualitative modeling of multi-stage fractured horizontal well productivity in shale gas reservoir

As an important unconventional gas resource, shale gas has become an important part of gas production in recent years with the advantage of horizontal well drilling and large-scale multi-stage hydraulic fracturing completion technologies. The shale gas reservoir numerical simulation advances were reviewed and a multi-stage fractured horizontal well numerical simulation was performed to qualitatively modeling the well productivity in over-pressured shale gas reservoir based on actual shale properties and well completion parameters. A single horizontal well model was established on the basis of dual-porosity model and logarithmically spaced grid refinement. A comprehensive comparison and analysis of the initial average gas production, daily gas production, cumulative gas production, adsorbed gas and free gas cumulative production were provided to investigate the influence of matrix permeability, SRV permeability, hydraulic fracture conductivity and half length, SRV size, bottomhole pressure on the well performance. The research shows that for the high matrix permeability (Km > 10−7 mD) and low SRV permeability (KSRV < 0.01 mD), the SRV permeability has a significant impact on the initial average gas production. For the high matrix permeability (Km > 10−7 mD) and medium SRV permeability (0.01 mD < KSRV < 0.5 mD), the initial average gas production is controlled by both the matrix and SRV permeability. For the high matrix permeability (Km > 10−7 mD) and high SRV permeability (KSRV > 0.5 mD), the initial average gas production is mainly controlled by the matrix permeability. When the matrix permeability is lower than 10−9 mD, the cumulative gas production is too low to be of economic interest. For the matrix permeability (10−9 mD < Km < 10−5 mD), the matrix permeability and SRV permeability are all important factors that influence the cumulative gas production. For the matrix permeability (Km > 10−5 mD), the matrix permeability has much more impact on cumulative gas production than that of SRV permeability. The daily gas production and cumulative gas production are independent of hydraulic fracture conductivity and half length. The initial gas production of multi-stage fractured horizontal well is also independent of SRV sizes. The SRV size mainly controls the gas production decline characteristic. With the increase of the SRV size, the daily gas production declines slowly. The SRV size determines the cumulative gas production directly. With the increase of the SRV size, the cumulative gas production increases linearly. The bottomhole pressure has a significant impact on cumulative gas production. With the decrease of the bottomhole pressure, the cumulative gas production of 20 years increases linearly.

Rupture Disk Valve Improves Plug-and-Perf Applications

Technology Update Plug-and-perf completions have proved to be the most flexible multistage well completion schemes. The main reason is that each stage can be perforated and treated optimally because options can be exercised right up to the moment the perforating gun is fired. This allows the engineer to apply knowledge from each previous stage to the stage under treatment. For example, using real-time microseismic fracture mapping techniques provides a view of where previous fractures have propagated, which enables adjustments to be made to perforating depth and pumping schedules for subsequent stages. Some people have argued that the plug-and-perf technique is too time consuming and that it is too slow at the start because of the need to run the first stage perforating guns in with coiled tubing, stick pipe, or a downhole tractor, thus adding an unnecessary expense. A new technique introduced by Schlumberger adds significant operating efficiency and lowers the cost of cemented, multistage fracturing by eliminating the initial perforating run. The technique uses the KickStart pressure-activated rupture disk valve to enable the first stage treatment to be combined with casing operations. In addition to reducing downtime, the technique has been shown to lower fracture initiation pressure, thereby eliminating the risk of closed perforation tunnels caused by shale swelling, and to increase the likelihood of fracturing the stage to completion. The extensive study of geomechanics has shown that rock formations fracture at their weakest point and that the weakest point aligns with the plane of maximum horizontal stress whenever the overburden (vertical) stress exceeds lateral stresses, which occurs most of the time. The pressure-activated rupture disk valve has a unique helical port design that exposes the formation outside the casing to fracture pressure, thereby ensuring that the fracture will align with the maximum horizontal stress plane and propagate at the weakest point in the formation. A major benefit of this alignment is the reduction of tortuosity at the fracture initiation point, which significantly reduces the probability of a premature screenout of the initial fracture treatment at the toe of the completion.

Multiple Transverse Fracturing in Open Hole Enables Development of a Low-Permeability Reservoir

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 119140, "Multiple Transverse Fracturing in Open Hole Allows Development of a Low-Permeability Reser voir in the Foukanda Field, Offshore Congo," by Alberto Casero, SPE, Loris Tealdi, SPE, Roberto Luis Ceccarelli, SPE, Antonio Ciuca, SPE, Giamberardino Pace, SPE, Eni; Brad Malone, SPE, Schlumberger; and Jim Athans, SPE, Packers Plus Energy Services, prepared for the 2009 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 19–21 January. The paper has not been peer reviewed. During the past decade, multiple transverse fracturing in horizontal wells has been applied successfully in onshore low-permeability reservoirs. The reasons for the success of this technique are related to the effectiveness of hydraulic fracturing for production enhancement and to the relatively low cost of pumping services onshore. Offshore, high direct and indirect costs and the risks associated with operations have limited the use of this technology. This study documents the successful effort of taking these techniques offshore. Transverse fracturing with multistage completion—with properly engineered design of the well trajectory—can provide economic success of field development of low-permeability reservoirs. Introduction The Foukanda marine field is 20 km north of the Kitina platform and 52 km west of the city of Pointe Noire, Congo. Average water depth is 100 m. The field was discovered in 1998, with initial production in June 2001. That year, one well was drilled in the D reservoir, but it had very poor reservoir characteristics, and this level was abandoned. The well was recompleted in the shallower B4 reservoir. The low-permeability D reservoir (less than 10 md) was abandoned. Successful fracture treatments in the Kitina field in May 2007 proved the possibility of obtaining economical rates from a marginal reservoir. It was decided to test the multistage hydraulic-fracturing technology on the previously abandoned D reservoir in the Foukanda field. Synergy from early cooperation among drilling, reservoir, and production-enhancement engineers proved key for the operation. An optimum process path was followed: reservoir assessment, selecting optimum fracture(s) configuration, providing input for the drilling plan, selecting the proper completion to allow optimum fracture(s) placement, and, finally, plan execution. The original plan on Foukanda was to drill a new vertical or deviated well with one or two fractures. Fracturing engineers suggested changing this plan and drilling a horizontal well and completing it with multiple transverse fractures. The deviated well was discarded because of complex fracture-growing issues, which, in the best case, could have transverse fractures that are not properly spaced, resulting in fracture/production interference. The advantage of having transverse fractures in a horizontal well is the possibility of proper spacing and deciding the optimum number of fractures that are required.

低浸透性火山岩貯留層への挑戦 大深度火山岩貯留層生産性向上技術開発について

The first multi-stage completion in a deep, hot, and low permeability volcanic rock of the Minami-Nagaoka Field, Niigata Prefecture, Japan, was successfully completed using six propped fracture treatment stages in 2001. This concept was introduced through the joint research program, “Productivity Improvement in a Deep Volcanic Rock Reservoir”, between Japan National Oil Corporation and Teikoku Oil Co., Ltd. started in 1997. The history and current status of Minami-Nagaoka Field is briefly reviewed and the outline of this project including the background of project initiation is discussed.