High Rate Gas Wells Research Articles

Reservoir Drilling and Openhole Gravel Packing with High-Density Cesium Formate Fluids in a High-Pressure, Marginal Mud Window Environment at Martin Linge

Summary High-density cesium/potassium (Cs/K) formate fluids were successfully utilized from reservoir drilling to upper completion installation in five productive Martin Linge high-rate gas wells. Four wells were completed with openhole gravel pack (OHGP) and one with standalone sand screens. The gravel packing operation marks what is considered to be the highest density carrier fluid OHGP successfully completed worldwide, with a specific gravity (SG) of 2.06. A complex operation under pressure and temperature conditions (745–780 bar and 135–140°C) that almost qualify as high pressure/high temperature (HP/HT), including managed pressure drilling (MPD), overbalanced screen running, and openhole gravel packing, was simplified by using the same base brine throughout the operation. Cs/K formate reservoir drilling fluid (RDF) and screen-running fluid were designed with biopolymeric additives and minimal calcium carbonate bridging particles. Clear Cs/K formate brine was chosen as gravel pack (GP) carrier fluid. The use of Cs/K formate fluids for all stages of the operation reduced the complexity of transitioning between the operational stages. In addition, the reservoir was only exposed to one filtrate without application of damaging weighting solids. The drilling fluid contributed to successful MPD and delivered wells with very good hole quality in the reservoir, which consisted of interbedded sandstone, coal stringers, and shale. The shale-stabilizing properties of concentrated formate brine–based fluids provided acceptable conditions for extended openhole time and allowed additional logging runs, including pore pressure measurements, under near-HP/HT conditions, before running the screens. One bottom-up cleanout was conducted before the screen-running fluid was circulated in and the screens installed. The spurt and seepage losses were low throughout the drilling and screen-running phases. No breaker treatment was required in any of the wells. All wells have proved to have good initial productivity and high well productivity index. The successful OHGP operations performed with the high fluid densities required in Equinor’s Martin Linge field have set a new standard for well completions in challenging high-pressure environments.

Sanding evaluation and real-time sand management decisions in high-rate gas wells, Ichthys Field, Browse Basin Australia

This paper demonstrates the workflow of an integrated petrophysical, geomechanical sanding assessment and cement bond log evaluation to define a simple cut-off for reliable sand production assessments and well completion decisions. This workflow provides valuable insights for timely and fit-for-purpose sand management strategies particularly at early field life where the commonly used sanding prediction methodologies cannot be calibrated with field data because of the lack of sanding observations. The successful application of this methodology is shown in the Ichthys gas field, Browse Basin, with high rate and long high-angle producers with subsea wellheads and a long pipeline to an onshore plant. Advanced geomechanical analysis combing analytical and numerical sanding methodologies are used to define a single property cut-off for well-life sand-free production. The availability of such a simple cut-off has assisted the well construction engineers to follow a quick, cost-effective, simplified but thorough approach for sand production assessment and completion selection as opposed to being empirical, or too time consuming. The field first came on stream in July 2018. The workflow has been used in development wells and its validity and sand control decisions are confirmed, as to date all wells are producing sand-free. A similar workflow is being developed for the secondary target at some 400–500 m deeper for the subsequent phases of field development.

Downhole Sand Control Applied for High-Rate Gas Completions in Deepwater Malaysia

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31413, “Applying Downhole Sand Control for High-Rate Gas Completions in Deepwater Malaysia,” by Elvy Jose Samuel, SPE, Mohd Faizal Yusoff, and Phil Bee, PTTEP, et al. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. _ Designing and delivering a successful completion in a subsea high-rate gas deepwater environment is a great challenge in upstream field development. The complete paper covers the sand-control design and execution techniques applied to four high-rate gas wells in the operator’s Block H development in the deepwater region of Sabah offshore Malaysia in 2020 and 2021. Field Background PTTEP’s Block H gas development is a multifield phased subsea development designed to deliver gas to Petronas’ floating liquefied natural gas (FLNG) project known as PFLNG2. The Block H field is in the South China Sea in water depths between 1150 and 1400 m. The first phase (Phase 1A) of the project was executed in four wells between the Rotan (three wells) and Buluh (one well) fields in the midsection of the Block H development. The reservoirs completed in Phase 1A were deepwater slope turbidite sands deposited during the Late Miocene and contain high net-to-gross reservoirs. Based on evidence from sonic logs and rock-mechanics testing performed on rotary side-wall cores and fullbore cores, all targeted reservoirs required robust sand control. Openhole gravel packing (OHGP) was chosen as the recommended sand-control technique for the high-rate gas application, and the four wells were drilled nearly vertically, with high water standoff height as a mitigation against early water coning. The drilling and completion operations were completed in a batch completion strategy in which all top holes were drilled to the top of the targeted reservoir, followed by the batch completion of all wells’ lower completion phase, then the batch upper completion and well cleanups. The wells were placed on production in Q1 2021 to PFLNG2, achieving the targeted rates per well of 80 MMscf/D solids-free.

Concurrent 10. Presentation for: Collaborating to bring new technology on developments

Presented on Wednesday 18 May: Session 10 Project delivery certainty is a key a success factor for positive business outcomes. Taking on world first applications across multiple delivery streams comes with risk that requires significant risk reduction to meeting business requirements. The Julimar Development completed this successfully across both drilling and completions, and subsea. Reliable multizone completions with robust sand control have traditionally been a challenge in high-rate gas wells. Cased hole stacked gravel packs can leave high mechanical skin, require multiple trips and are complex operations. While Open Hole Gravel Packs (OHGPs) have provided reliable sand control in such wells, multizone applications have been limited due to the tradeoff between effective gravel placement and zonal isolation. Recent developments in technology have enabled reliable gravel placement and complete zonal isolation. The collaboration between Woodside and Subsea 7 has delivered an ‘industry first’ on the Julimar Project, with the completion of an 18″ Corrosion-Resistant Alloy (CRA) gas transmission flowline installed via reel-lay – the largest diameter insulated CRA pipeline ever reeled. For background, most projects have traditionally used the ‘S-Lay’ method for installing pipe in Australia – the reel-lay method is less common. A key benefit of the reel-lay method is it removes thousands of welds from the offshore installation vessel critical path, transferring them onshore into a safer, quality-controlled environment earlier in the schedule. Pipe joints are welded into ‘stalks’ which are then spooled onto purpose-built reel-lay vessels. Woodside and Subsea 7 were able to jointly demonstrate the safety, quality, technical and cost advantages of this innovative but field-proven reeled pipe-lay technology. The 18″ CRA flowline is a tangible example of the performance that can be delivered through early collaborative engagement and strategic investment in technology and is a step change in Australia and the industry. This joint presentation discusses contracting, design, execution and evaluation of technologies on the Julimar Development. It includes the method followed for reel-lay technology selection, engineering development, post project evaluation and the health and safety benefits. The presentation provides both the Operator and Contractor perspectives on the challenges of implementing new technology in developments in Australia. To access the presentation click the link on the right. To read the full paper click here and also here.

Multiple world first technology applications on Julimar Development Phase 2 – multizone openhole gravel packing with enhanced shunted screens and zonal isolation in high rate gas wells and 18″ reel lay for corrosion resistant alloy (CRA) flowlines

Project delivery certainty is a key success factor for positive business outcomes. Taking on world first applications across multiple delivery streams comes with risk that requires significant risk reduction to meet business requirements. The Julimar Development completed this successfully across both drilling and completions, and subsea. Reliable multizone completions with robust sand control have traditionally been a challenge in high-rate gas wells. Cased hole stacked gravel packs can leave high mechanical skin, require multiple trips and are complex operations. While OpenHole Gravel Packs (OHGPs) have provided reliable sand control in such wells, multizone applications have been limited due to the trade-off between effective gravel placement and zonal isolation. Recent developments in technology have enabled reliable gravel placement and complete zonal isolation. The largest flow line installation by reel lay for corrosion resistant alloy (CRA) flowlines was previously 16″. Increasing this size to 18″ required an in-depth understanding of key risks for the contractor to deliver on the size increase, and for Operator to engineer in risk mitigation. Key areas to understand included vessel capability, new build spool base, engineering methods to support delivery and the Operators role in change management when additional risks are identified, or issues occur. This paper discusses contracting, design, execution and evaluation of technologies on the Julimar Development. It includes methodology followed for both technology selections, engineering development, qualification tests, post project evaluation, lessons learned along with health and safety benefits.

Collaborating to bring new technology on developments

Project delivery certainty is a key a success factor for positive business outcomes. Taking on world first applications across multiple delivery streams comes with risk that requires significant risk reduction to meeting business requirements. The Julimar Development completed this successfully across both drilling and completions, and subsea. Reliable multizone completions with robust sand control have traditionally been a challenge in high-rate gas wells. Cased hole stacked gravel packs can leave high mechanical skin, require multiple trips and are complex operations. While Open Hole Gravel Packs (OHGPs) have provided reliable sand control in such wells, multizone applications have been limited due to the tradeoff between effective gravel placement and zonal isolation. Recent developments in technology have enabled reliable gravel placement and complete zonal isolation. The collaboration between Woodside and Subsea 7 has delivered an ‘industry first’ on the Julimar Project, with the completion of an 18″ Corrosion-Resistant Alloy (CRA) gas transmission flowline installed via reel-lay – the largest diameter insulated CRA pipeline ever reeled. For background, most projects have traditionally used the ‘S-Lay’ method for installing pipe in Australia – the reel-lay method is less common. A key benefit of the reel-lay method is it removes thousands of welds from the offshore installation vessel critical path, transferring them onshore into a safer, quality-controlled environment earlier in the schedule. Pipe joints are welded into ‘stalks’ which are then spooled onto purpose-built reel-lay vessels. Woodside and Subsea 7 were able to jointly demonstrate the safety, quality, technical and cost advantages of this innovative but field-proven reeled pipe-lay technology. The 18″ CRA flowline is a tangible example of the performance that can be delivered through early collaborative engagement and strategic investment in technology and is a step change in Australia and the industry. This joint presentation discusses contracting, design, execution and evaluation of technologies on the Julimar Development. It includes the method followed for reel-lay technology selection, engineering development, post project evaluation and the health and safety benefits. The presentation provides both the Operator and Contractor perspectives on the challenges of implementing new technology in developments in Australia.

Distributed Fiber-Optic Sensing Enhances Flow Diagnostics in Gas Condensate Well

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 205435, “Flow Diagnostics in High-Rate Gas Condensate Well Using Distributed Fiber-Optic Sensing and Its Validation With Conventional Production Log,” by Fuad Aziz Atakishiyev, SPE, BP, and Alessandro Delfino and Cagri Cerrahoglu, Lytt, et al. The paper has not been peer reviewed. The authors describe a machine-learning (ML) approach for processing distributed-fiber-optic-sensing (DFOS) data that enables dynamic flow-profile monitoring using a fiber-optic electric-line cable deployed in a gas condensate well and compare the method with a conventional approach. DFOS technology has the potential to provide more-efficient and dynamic flow profiles compared with traditional methods, particularly in high-rate gas wells where production logs (PL) are recorded at reduced rates to avoid tool lifting. Technology and Field Introduction DFOS surface acquisition systems launch short pulses of light into an optical fiber, then receive its backscatter and convert it into physical measurements: temperature in the case of distributed temperature sensing (DTS) and acoustic intensity in the case of distributed acoustic sensing (DAS). These systems essentially turn a fiber-optic cable into a long array of thermometers (DTS) or multifrequency microphones (DAS). The DFOS systems record the backscatter signal continuously and measure at multiple points along the fiber. The major advantage of DFOS acquisition is the ability to record data throughout time at a very high sampling frequency. Unlike traditional PL tools, insights provided by DFOS offer a real-time view of changes in production without intervention. A successful trial was performed in a high-rate gas-producing well to test the quantitative inflow profiling algorithm on DFOS data. As part of the work, conventional PL data were acquired in high-rate gas production Well A01. An electric-line cable with built-in multimode and single-mode fiber-optic line was used to acquire conventional PL data. DAS and DTS data were acquired simultaneously for approximately 30 minutes while the well produced at a gas rate of approximately 70 MMscf/D. No sand-control completions were planned for Well A01 or for other wells in the field; therefore, in addition to the identification of a quantitative inflow profile, another main objective of the study was to identify intervals with sand production.

Productivity index enhancement by wettability alteration in two-phase compressible flows

Water blocking due to the capillary end effect near the wellbore vicinity creates significant formation damage and decreases well productivity for oil and gas. The alteration of the rock wettability by a chemical well treatment is an effective way to reduce water blockage and enhance oil and gas production. Presently, several surfactants and nanofluids are used in the industry for contact angle alteration. After the treatment, the porous medium in the well vicinity (or along the core) has stepwise contact angle. The previous paper (Naik et al., 2015) develops analytical models for incompressible steady-state two-phase linear and axi-symmetric flows, accounting for the piecewise constant contact angle and contact-angle-dependent capillary pressure and relative permeability. The current paper adds the effect of compressibility, which is particularly important for high rate gas wells and wells in unconventional and tight-sand reservoirs. The obtained semi-analytical model has been validated by comparison with a set of laboratory coreflood tests. The modelling reveals a complex interplay between the competing effects of compressibility, viscous and capillary forces, yielding non-monotonic dependencies of well productivity on the wettability and the optimal contact angle. The model closely matches the productivity index data for two production wells from a field case before and after wettability treatment using surfactant.

Prediction of Non-Darcy Coefficients for Inertial Flows Through the Castlegate Sandstone Using Image-Based Modeling

Near wellbore flow in high rate gas wells shows the deviation from Darcy’s law that is typical for high Reynolds number flows, and prediction requires an accurate estimate of the non-Darcy coefficient (β factor). This numerical investigation addresses the issues of predicting non-Darcy coefficients for a realistic porous media. A CT-image of real porous medium (Castlegate Sandstone) was obtained at a resolution of 7.57 μm. The segmented image provides a voxel map of pore-grain space that is used as the computational domain for the lattice Boltzmann method (LBM) based flow simulations. Results are obtained for pressure-driven flow in the above-mentioned porous media in all directions at increasing Reynolds number to capture the transition from the Darcy regime as well as quantitatively predict the macroscopic parameters such as absolute permeability and β factor (Forchheimer coefficient). Comparison of numerical results against experimental data and other existing correlations is also presented. It is inferred that for a well-resolved realistic porous media images, LBM can be a useful computational tool for predicting macroscopic porous media properties such as permeability and β factor.

Techbits: Australian Workshop Reviews State of High-Rate Gas Wells

Techbits Perth, Australia played host earlier this year to an SPE Applied Technology Workshop (ATW) aimed at examining the state of the art in developing and producing high-rate gas wells. Titled “High-Rate Gas Wells,” the ATW brought together 71 participants from 33 different organizations and 14 countries to uncover what the industry has learned, both in terms of best practices and pitfalls, while operating the growing number of these wells around the world. For the purpose of this workshop, a high-rate gas well was defined as being capable of producing more than 200 MMscf/D of gas. The workshop organizers, led by Cochairs Daniel Teng of Woodside Energy and Raymond Tibbles of Schlumberger, pointed out that many wells around the world, including in Australia, Trinidad, Brazil, Qatar, and the North Sea increasingly fit that criterion. Case studies and practical applications were presented on reservoir drainage and management; carbonate, sandface, and upper completions; subsea and surface facilities; well integrity and reliability; and intervention strategies. There was also a poster session that gave delegates the opportunity to have in-depth discussions in a relaxed environment. Highlights of the sessions are presented below. Reservoir Drainage The first technical session, chaired by Azhar Al Kindi of Shell Upstream International and Carl Stockmeyer of Baker Hughes, focused on building an understanding of reservoir drainage for high-rate gas wells that links to well design and the infrastructure required for field development. An important challenge highlighted in this session is successfully balancing the drainage scheme and well architecture with the capacity allowance for individual wells. Presenters and audience members also discussed the complexities of some of these reservoirs and the importance of constantly re-evaluating available information, as well as how multiple sensors could be used in long intervals to evaluate production across a lateral. Inflow-control device technology was also discussed, with particular emphasis on how applicable the current technology is to high-rate gas wells. Reservoir Management Al Kindi and Kamel Bennaceur of Schlumberger cochaired this session on the critical aspects of managing reservoirs that are being drained by high-rate gas wells. Most of the focus was paid to the necessary tools required for effective reservoir management, and the need for good surveillance data was stressed to facilitate robust management, performance simulation, and forecasting. The session opened with a discussion on dynamic simulation to ensure deliverability from the entire completion/surface system. A discussion on the limitations of production logging followed, and the session closed with a review of how distributed temperature sensors can be used as a reservoir-monitoring tool.

Integrated Approach To Optimize Material Selection for High-Rate Gas Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 12503, "Integrated Approach To Optimize Material Selection for North Field High-Rate Gas Wells," by W.A. Sorem, RasGas Company; E.J. Wright and J.L. Pacheco, ExxonMobil De vel opment Company; and D.A. Norman, ExxonMobil Upstream Research Company, originally prepared for the 2008 In ter national Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed. The RasGas Company North field wells typically have a true vertical depth of 9,000 ft with a sail angle up to 70º. The combination of 7-in. mono-bore and 9 5/8-in. big-bore wells is designed to handle hydrogen sulfide (H2S) and carbon dioxide (CO2) corrosion, hydrochloric acid (HCl) stimulation, and environmental cracking. The wells must accommodate high flow rates and through-tubing intervention. The full-length paper describes the technical development of an optimized operational envelope for L-80 carbon-steel tubulars for these high-rate gas wells in Qatar. Introduction The North field is offshore to the northeast of Qatar in the Arabian Gulf. It is the world's largest nonassociated-gas field, with reported reserves of more than 900 Tcf. The sour, abnormally pressured natural gas is contained in the massive Khuff carbonate formation. RasGas currently has 11 offshore platforms in the North field. Two different types of production wells have been used on these platforms. The first type is a 7-in.-monobore well with 7-in. tubing and liner made of L-80 carbon steel. The second well type is referred to as the 9 5/8-in. optimized big-bore (OBB) well comprising 9 5/8×7 5/8-in. tapered production tubing made of L-80 carbon steel and a 7-in. liner made of Alloy 28 corrosion-resistant alloy (CRA). More than 60 9 5/8-in. OBB wells have been drilled and completed to date. The wells are more than of 9,000 ft deep with deviations from vertical of as much as 70°. Well deliverability for the 9 5/8-in. OBB wells is greater than for the 7-in. monobore wells, and on the basis of reservoir modeling, it was determined that the target project production could be achieved with 25% fewer wells. At equivalent production rates, the 9 5/8-in. OBB wells have less wellbore pressure loss, resulting in an extension of the plateau life without surface compression. All of these wells must be designed to handle H2S and CO2 corrosion, HCl stimulation, and environmental cracking. All of the acid used to stimulate these wells contains corrosion inhibitors to mitigate corrosion in the tubing and liners during acid stimulation. The tubular materials are designed to withstand the corrosive production environment on their own without chemical inhibition. Early in the design phase of the 9 5/8-in. OBB wells, the use of CRAs was considered for both the tubing and the 7 in. liner. However, it was determined that CRA materials could not be fabricated (on a commercial scale) to 9 5/8-in. diameter in usable lengths because of tubular-mill manufacturing limitations, so carbon steel would have to be used to enable the 9 5/8-in. OBB production advantages.

Fluidic Oscillation With Acid Stimulation Improves Gas-Well Productivity

This article, written by Technology Editor Dennis Denney, contains highlights of paper IPTC 11452, "Fluidic- Oscillation Technique in Conjunction With Acid Stimulation Improves Gas- Well Productivity," by Ahmed Hegazy, Belayim Petroleum Company, and Bruce Conrad, Arshad Waheed, and Osama Sanad, Halliburton, prepared for the 2007 International Petroleum Technology Conference, Dubai, 4–6 December. The paper has not been peer reviewed. Copyright 2007 International Petroleum Technology Conference. Reproduced by permission. Low productivity of gas wells in the offshore Mediterranean Sea operations of Egypt often is caused by near-wellbore formation damage. The stimulation technique will vary depending on the type of damage; however, prevalent techniques are hydraulic fracturing and matrix acid stimulation. A new technique called "fluidic oscillation" was proposed, which would be especially applicable in cases having uncertainties regarding rock mineralogy. Fluidic oscillation is a mechanical, nonfluid-invasive stimulation technique (i.e., it is not essential to inject the treatment fluid into the reservoir to break down damage, although its use in that manner is not precluded). This technique was successful in stimulating gas wells in Egypt. Introduction The main challenge after completing two high-rate gas wells was less-than-expected production. These wells are approximately 37 miles off the Mediterranean Sea coast in the PetroTemsah field, northwest of Port Said in Egypt. This field produces gas and condensate with a condensate/gas ratio (CGR) of 60 bbl/MMscf. The producing formation is the Sidi Salem formation of Serrvallian age (Miocene), with an average porosity of 22%, average water saturation of 30%, and an average permeability of 100 md. This formation consists of four main reservoir layers (Lobe-0, -1, -2, and -3) and is at a depth of approximately 14,000 ft with a bottomhole temperature of 230°F. The bottomhole pressure ranges from 7,400 to 8,000 psi. A complete mineralogical breakdown of the rock by weight is not available, but essentially the rock is clean sandstone (80% quartz with 3 to 4% calcium carbonate and 10 to 15% feldspars and clay). The Sidi Salem formation is unconsolidated, and without adequate sand control, the wells tend to sand up, ceasing all flow from the reservoirs. The sand-control techniques used for the field include openhole gravel packs, expandable sand screens, and cased-hole gravel packs. The first example is an openhole completion with an expandable sand screen set across the zones of interest. The second well has an inside-casing gravel-pack completion.

Well-Completion Effects on the Performance of Horizontal and Multilateral Wells

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 96530, "An Evaluation of Well-Completion Impacts on the Performance of Horizontal and Multilateral Wells," by L.-B. Ouyang, SPE, and B. Huang, SPE, Chevron Energy Technology Co., prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October. Well completion is critical in well design and the performance of the well for its entire life. The major objective for this study was to provide guidance in the design of completion configuration with a series of simulations with different completions in different flow and reservoir environments. Completion options including open hole, slotted liner, inflow-control devices, intelligent-well completions (i.e., downhole instrumentation and control system), perforated/cemented liner, wire-wrapped screen, external casing packers, gravel pack, and frac pack were reviewed. Introduction With many advanced well-completion options deployed in new wells, especially in deep- and ultradeepwater environments, well-completion details often are not taken into account in reservoir simulators. Reservoir simulators should be connected with wellbore hydraulics and tubing-performance prediction software regarding the ability to model complex well hydraulics, including an appreciation of the influence on deliverability of reservoir effects and completion design. This study evaluated the performance under different completion designs for two proposed gas wells and one existing oil well. Several potential factors that could affect well production were evaluated including pressure drawdown, wellbore damage, non-Darcy effect, zonal isolation, wellbore-pressure drop, fluid flow in the annulus, and well position. Simulation Tool A commercially available completion-modeling and well-planning simulation tool was used that models production fluids flowing from the reservoir through well completions into a wellbore. It is used for well-placement and -completion screening and/or design studies of local variations in reservoir properties. It allows scaleup and honors complex reservoir-description information from an Earth model to compute multiphase flow from the reservoir through the well completion, into the wellbore, and up to the wellhead. Through alternative well placement, the well behavior can be estimated for the given reservoir description and well-completion design. The steady-state oil-, water-, and gas-production rates as well as the production profile along the length of the horizontal wellbore can be calculated. Completion Option Different completion designs were proposed for the two gas wells, including openhole gravel pack (OHGP), cased-hole gravel pack (CHGP), standalone screen (SAS), cased-hole frac pack (CHFP), and expandable sand screen (ESS). For a CHGP or CHFP completion, an isolation string could be required. The detailed completion parameters for all the completion options are given in Table 1 in the full-length paper. Skin factor is a measure of the amount of additional pressure draw-down encountered because of mechanical or turbulent effects. The higher the skin factor, the larger the extra pressure drawdown, resulting in reduced well production. Mechanical skin is a factor closely related to well completion and independent of flow rate. The skin caused by turbulent effects (normally called non-Darcy effect, or non-Darcy skin) depends primarily on flow rate. Typically, non-Darcy skin is trivial and can be ignored for liquid wells or low-rate gas wells. However, the non-Darcy skin for high-rate gas wells could be as significant as the mechanical skin.

Sand Management for High-Rate Gas Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 86535, "Sand-Management Solutions for High- Rate Gas Wells, Sawan Field, Pakistan," by C.A. McPhee, SPE, Helix RDS Ltd., and C.K. Enzendorfer, SPE, OMV Pakistan, prepared for the 2004 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 18-20 February.

Design of High-Rate Gas Wells: Issues and Solutions

This article is a synopsis of paper SPE 50081, "High-Rate-Gas-Well Design: Issues and Solutions - Goodwyn Gas Condensate, NWS, Australia," by D. Teng, SPE, G. Nettleship, SPE, S. Hicking, and K. Hindmarsh, Woodside Energy Ltd., originally presented at the 1998 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 12-14 October.

Sand-Control Completion Design, Installation, and Performance in High-Rate Gas Wells

This article is a synopsis of paper SPE 39432, "Sand-Control Completion Design, Installation, and Performance of High-Rate Gas Wells in the Jupiter Field," by R.C. Burton, SPE, and S.A. Boggan, SPE, Conoco Inc., originally presented at the 1998 SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, 18-19 February.

Geometry of Hydraulic Fractures From Modestly Deviated Wellbores

Summary Model studies of the geometry of hydraulic fractures from modestly deviatedwells revealed that the rough surfaces seen previously are formed by thecoalescence of a number of starter fractures. At higher deviation angles, thestarter fractures do not link. The overall effect is a loss of wellproductivity resulting from restricted communication length and reducedeffective aperture. This paper presents some guidelines for paper presents someguidelines for minimizing this adverse effect. Introduction Historically, most hydraulically fractured wells have been vertical. An increasing number of deviated wells now require hydraulic fracturing, in somecases because of environmental awareness and legislation, which can restrictthe number and location of drillsites. and in others because of the developmentof offshore. low-permeability fields. Productivity, from a fractured deviated well is expected to be lower than that from a fractured vertical well. Fornormal reservoir depths. the axis of an ideal vertical well lies in the preferred fracture plane, defined as the plane perpendicular to the directionof the minimum horizontal rock stress and the fracture communicates with the wellbore over the entire perforated interval The axis of a deviated well, perforated interval The axis of a deviated well, however. rarely lies in thepreferred fracture plane. and the wellbore may intersect the fracture only overa limited reservoir interval. The limited cross-sectional area of fluids toenter the wellbore from the fracture leads to high local flow rates and hence additional pressure losses and reduced productivities. particularly inhigh-rate gas productivities. particularly in high-rate gas wells The economicsof South Ravenspurn, a southern North Sea gas field, depended heavily, on effective hydraulic fracturing to achieve high productivity increases. Thefield shape and platform locations were such that all parts of the field couldbe accessed by build-and-hold wells with deviations up to about 30 deg. Suchdeviations were likely to lead to limited-entry problems. An alternative was todrill S-shaped wells to return wells to near vertical through the reservoirinterval. Doing so increases well productivity and reduces the number of wellsrequired, but also increases drilling costs and risks. The closer the wellreturns to the vertical and the higher the step-out, the higher the cost of drilling an S-shaped well. An experimental study was conducted to definemaximum inclinations through the reservoir interval as a function of well direction for test conditions, representative of South Ravenspurn. This paper describes the experiments, discusses the results, and makes recommendations forthe fracturing of deviated wells of moderate step-out. Experiments Tests were conducted on 1/4-in.-diameter model boreholes in 12-in. cubes ofplaster of Paris (hydrostone) containing silica flour to increase strength andto decrease permeability. The cubes were loaded with a permeability. The cubes were loaded with a vertical stress of 1 = 2. 1 00 psi, a maximum horizontal stress Of 2 - 2, 1 00 psi, and a minimum horizontal stress Of 3 = 700 psi. Thefield effective s were about 6.000 psi vertical and 2,000 psi minimum psivertical and 2,000 psi minimum horizontal. The intermediate stress was unknown. The preferred hydraulic fracture plane, by definition, was perpendicular to eAppendix gives full experimental details. The communication length of thefracture with the wellbore, defined here as the length of wellbore in contact with the hydraulic fracture, depends on the well azimuth, measured from thedirection and the well deviation, (Fig. 1). A wellbore lying in the preferredfracture plane has a O degs azimuth. The following tests were carried out on both open and cased bore holes: vertical well -B=0 Deg.; =90 deg. with 10, 20, and 30degs; and 0=30* with a=O, 10, 20, and 30degs. The wellbore pressure wasrecorded at 10 Hz. After testing, each sample was examined in acomputerized-tomography (CT) scanner and then opened to reveal the fracturegeometry, which was subsequently photographed. The communication length of thephotographed. The communication length of the fracture with the wellbore wasmeasured. Results and Discussion Fracture Communication With the Wellbore. Tables 1 and 2 give the results ofthe open- and cased-hole experiments, respectively. The measured communication lengths are significantly longer than the minimum theoretical length, L, for aplanar fracture perpendicular to a3. From geometrical considerations, L-d/(sin ct sin 6), where d is the wellbore diameter. JPT P. 742

Evaluation of Flow Characteristics of Perforations Including Nonlinear Effects With the Finite-Element Method

Summary This study presents results of finite-element modeling of steady-state flow in perforated natural completions. Use of a mesh chosen carefully by grid sensitivity analysis permits evaluation of flow with more precision than that achieved by previous investigators. Also, for the first time, flow characteristics of perforated completions are evaluated with the non-Darcy effect resulting from converging flow around the perforation taken into account. The results indicate (1) confirmation of Locke's results qualitatively but 5 to 10% overprediction by the nomograph, (2) the importance of angular phasing between adjacent perforations, (3) the uncertainty in generally accepted severe permeability impairment in the compacted zone, and (4) a significant reduction in productivity owing to a non-Darcy effect around the perforation for high-rate gas wells.