Tubing-conveyed Perforating Research Articles

Sensor Array Enables Accurate Profiling of Produced Fluids During Drillstem Tests

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29749, “Determining Produced-Fluid Properties for Accurate Production Profiling During a Drillstem Test Using Thermal-Imaging Technology,” by David Lavery and David Fyfe, Metrol, and Abu Rashid Hasan, SPE, Texas A&M University, prepared for the 2019 Offshore Technology Conference Brasil, Rio de Janeiro, 29–31 October. Copyright 2019 Offshore Technology Conference. Reproduced by permission. This paper describes the use of a downhole temperature-sensor array during a commingled drillstem test (DST) to determine the density of produced fluids accurately. In a typical DST that uses only downhole pressure gauges, any fluid contacts between the pressure gauges would be missed and the produced-fluid density calculated would be erroneous. The complete paper demonstrates the importance of taking fluid properties into account when determining the zonal flow-rate contributions using the mass-enthalpy method. Introduction Downhole temperature-sensor-array data provide accurate fluid contact depths during buildup periods of the DST that typically cannot be observed in pressure gradients. Determination of these fluid contacts permits the calculation of individual produced-fluid densities. In a case study described in the complete paper, the deepest perforated zone produced a fluid with a higher density than that seen in shallower perforated intervals. The higher density of the produced brine caused the wellbore fluids to slug during the flow periods with a measurable response in pressure and temperature data. If this difference in the fluid properties is not taken into account, zonal-allocation flow rate will be in error because it relies on density and specific heat capacity. Qualitative assessment of the temperature-array data identified producing zones and clearly highlighted different fluid interfaces in detail that would remain hidden if the pressure gauges were relied upon solely. High-Resolution Temperature Measurement During DST Operations The deployment of the downhole temperature-sensor array during DSTs provides an in-depth look into reservoir characteristics that go beyond traditional downhole pressure-gauge measurements. The temperature sensors, contained within steel tubing and clamped to the outside of the tubing-conveyed perforating guns, cover the three perforated intervals in this case study. Two temperature sensor arrays were run, each with a sensor spacing of 0.6 m and offset with an effective sensor spacing of 0.3 m. Throughout the DST, the readings from the temperature sensor arrays were recorded on downhole memory devices at 1-minute intervals. The temperature measurement covered the entire perforated interval. High-resolution pressure gauges are placed above and below the perforated interval and above and below the tester valve. Using an acoustic communication system, real-time temperature and pressure data were available during the DST so that observations across the entire test could be made. Zonal Allocation of Produced Reservoir Fluids From Mass-Enthalpy Balance The mass-enthalpy method of calculating zonal contributions relies on intervals higher in the wellbore producing at a lower temperature than deeper producing intervals. The higher- temperature contributions from the deepest producing intervals will flow up the wellbore while losing some heat to the colder wellbore. The rate of cooling is dependent on the flow velocity. The shallower producing intervals contribute at a lower temperature than the mixture and will cool down the mixture. This method is detailed in the complete paper.

Perforation and Flowback Highlights From the Gorgon Field, Offshore Australia

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 182420, “Perforation and Rig Flowback Highlights for the Gorgon Field Development Wells,” by A.K. Morrison, SPE, and J.P. Beinke, SPE, Chevron Australia, prepared for the 2016 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 25–27 October. The paper has not been peer reviewed. The Gorgon liquefied-natural-gas project (Fig. 1) is one of the world’s largest natural gas projects and the biggest single resource development in Australia’s history. In 2014, eight Gorgon wells were perforated successfully, intercepting between three and seven commingled zones and gross intervals of up to 500 m per well. This paper contrasts the detailed perforating and flowback plan with the results of the operation where a number of planned, and some unplanned, contingencies were faced. Perforation Basis of Design The main element of the Gorgon- project well design that affected perforating was that reservoir sections would be completed with a cemented 70-in. liner in 8¾-in. open hole, with the top perforation approximately 250 m below the liner top. Each well was to be completed in multiple formation zones, with the average gross perforation interval per well (top to bottom shot measured distance) expected to be more than 400 m and an average net perforation interval (sum of perforated zones) of close to 150 m. Four perforating alternatives were evaluated with respect to their relative operational and subsurface risks: Tubing-conveyed perforating (TCP) shoot and drop—guns deployed into the liner on a gun hanger before upper completion is run and then fired and dropped after perforation TCP shoot and pull—a separate drillpipe-conveyed perforation trip before completion with use of a sized kill pill after perforation to mitigate losses before the upper completion is run Coiled-tubing conveyed Wireline conveyed After analysis, the TCP shoot-and- drop option was eliminated because of the additional time and well-control risk of drilling the required rathole to accommodate dropped guns. Shoot and pull was not considered a viable option because of a lack of a temperature-rated, post-perforation kill pill. Coiled tubing was rated feasible but with inherently greater operational risks when performed from a mobile offshore drilling unit. The process concluded that the wireline-conveyed method was the best solution despite requiring several perforating runs per well. Operational issues associated with this technique were identified, and plans were developed for these to be managed safely. The gun length per trip was expected to be approximately 30 m, necessitating at least five wireline trips to perforate each well, with each run expected to take between one and two rig shifts. In the event of failure (e.g., unsuccessful cable development), the selected contingency method for deployment was coiled tubing, which was considered a proven alternative.

Acoustic Wireless Telemetry Reduces Uncertainty in Deepwater Drillstem Tests

Technology Update The drillstem test (DST) is one of the oldest methods used to test a formation’s capability to produce hydrocarbons. An early patent filed on drillstem testing in 1926 describes it as a method for “testing the productivity of formations encountered in drilling oil and other deep wells.” While frontiers such as deepwater drilling were far in the future, the industry was already seeking methods and equipment that were more efficient and economical than those in use then. Technology has continued to advance from mechanical openhole testing to modern annulus pressure controlled cased hole drillstem testing. An impressive array of annulus pressure-operated downhole test tools is available and provides operators with versatility and flexibility in drillstem testing. Downhole tool technology has advanced to extreme limits, with tools capable of handling bottomhole conditions of 35,000 psi and 500°F. Meanwhile, drilling technology has also progressed, with wells drilled to greater depths and in deeper water. Operating conditions pose new challenges to cost efficiency and annular pressure limitations. The inherent complexity of deepwater DST operations implies that a significant number of downhole test tools require some form of annular pressure manipulation. Tubing string tester valves, primary and backup circulating valves, bottomhole sampler triggers, and primary and backup firing heads for tubing-conveyed perforating are some examples. In deep water, the maximum allowable casing pressure has become the limiting factor in an increasing number of instances, and this reduces flexibility in designing the downhole test string. Advances in acoustic wireless telemetry have led to a novel and reliable alternative approach to operating downhole test tools in drillstem testing and providing real-time feedback of tool status, bottomhole pressure and temperature, and bottomhole fluid sample conditions. Wireless Telemetry Although wireless telemetry for downhole applications in the oil industry has been used since the 1940s, it did not gain much traction until the 1990s. Different wireless technologies have been studied and tested. Mud pulse telemetry found little use in drillstem testing because of low bandwidth and operational limitations. Electromagnetic telemetry saw some early use but also had limited data transmission capabilities, and the method does not work in subsurface salt layers.

Acid-Soluble Plugs—Pressure-Tight Solution for a Preperforated Liner

Summary This paper covers the development, laboratory testing, and field testing of acid-soluble-plug (ASP) technology as a viable completion alternative to wireline- or tubing-conveyed perforating. The ASPs are installed in a preperforated reservoir liner and dissolve when soaked in acid, allowing access to the reservoir. This allows the technology to be easily applied in reservoirs in which matrix acid jobs or acid-fracturing techniques are used. The ASP technology was developed to reduce risk and cost associated with wireline- and tubing-conveyed perforating. ASPs were designed, manufactured, and field tested in both 5-in. and 7.625-in. reservoir liner sizes for wells in the Ekofisk field. The combination of laboratory testing and large-scale field testing influenced the design of the ASPs as well as the additives used in the acid systems used to dissolve them. From concept to initial field implementation, the process of ASP-engineering development took more than 2 years. The concept was in the beginning field-tested in deviated injectors, with ASPs installed in the deepest section of the reservoir liner. The field tests proved the ASP concept before depending on the technology in a horizontal producer with an uncemented, tubing-in-liner completion solution. The field tests showed that acid soaking dissolved the ASPs in the downhole environment and allowed efficient acid stimulation of the reservoir. It also reduced the number of wireline runs necessary to complete the well. When field tested in a tubing-in-liner completion application, installation of the ASPs in the reservoir liner eliminated tubing-conveyed-perforating runs. The reservoir liner was uncemented with mechanical openhole packers for zonal isolation. The ASPs provided a pressure-tight reservoir liner to set the packers against and eliminated fluid loss during the running of the inner completion string. Optimization of this technology is an ongoing process. The plug design itself continues to evolve as well as the operational steps to minimize the soaking time necessary to dissolve the plugs and to gain access to the reservoir.

Drilling and Completing Cascade and Chinook Wells: A Case History

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24179, ’Drilling and Completing Cascade and Chinook Wells: A Design and Execution Case History,’ by Flavio Dias De Moraes, Petrobras; Oswaldo Moreira, Petrobras America; Ziad Haddad, FOI Technologies; Scott Ogier and Jonathan Shipley, SPE, Cherokee Offshore Engineering; Mauricio Rebelo, Petrobras; and Fernando Gama, Petrobras America, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. During the design, implementation, and operation of the Cascade and Chinook (C&C) field development project in ultradeep water in the Lower Tertiary play of the Gulf of Mexico (GOM), the technical limits of single-trip multizone (STMZ) frac-pack systems were pushed to depths greater than 27,000 ft using high fracture rates and high-strength proppants; knowledge was gained from ultrahigh-pressure (greater than 20,000 psi) tubing-conveyed perforating systems; and well-design criteria suitable for high-drawdown (more than 12,000 psi) production operations were demonstrated. Introduction The C&C development plan in the GOM is one of the most technologically challenging and complex projects ever implemented by Petrobras. This project uses the first floating production, storage, and offloading vessel in operation in US waters at a water depth of 8,200 ft. The C&C subsea infrastructure considers the use of subsea manifolds, rigid flowlines, pipe-in-pipe pipelines, and freestanding hybrid risers. These two fields are 15 miles apart and share several characteristics such as depth, lithology, and reservoir similarities. The Wilcox 1 (Eocene) and 2 (Paleocene) sands belong to the Lower Tertiary geologic period and are part of the latest exploratory frontier in the GOM. At least 12 discoveries have been made in the Lower Tertiary, holding a potentially recoverable volume of several billion bbl of oil, highlighting the importance of this technology development for the industry. These reservoirs are characterized by a considerable thickness of intercalated sandstones and shales. The reservoirs show low horizontal permeability (less than 100 md) and poor vertical communication between sand layers. Other characteristics include a very high static formation pressure, a maximum temperature of 256°F, and a low gas/oil ratio. The produced oil has carbon dioxide concentration in the gaseous phase of less than 1.5%, and there is no evidence of hydrogen sulfide contamination. Drilling Design The casing design was based on delivering an 8½-in.-internal-diameter casing at total depth (TD) to accommodate the completion design. In this design, each string is run to its approximate design limit to maximize leakoff-test (LOT) values. One of the most important strategies of the C&C wells was the elimination of the 11⅞-in. liner, which prevents achieving adequate circulation rates for a successful primary cement job on the 10⅛-in. production casing.

Evaluation of Established Cleanup Models in Dynamic Underbalanced Perforating

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 159413, ’Evaluation of Established Perforation-Cleanup Models in Dynamic Underbalanced Perforating,’ by Dennis Haggerty, G.G. Craddock, and Clinton C. Quattlebaum, SPE, Halliburton, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed. Dynamic underbalanced (DUB) perforating is a process that creates a negative pressure differential, or underbalance, causing fluid to move toward the wellbore even in an initial overbalanced static condition. A DUB condition can be controlled by understanding and carefully managing the temporal pressure transients by use of multiple methods within the wellbore during and after gun-system detonation. Recently, a series of instrumented perforation experiments demonstrated that existing cleanup models do not accurately predict perforation cleanup when perforating in a DUB condition. Introduction Underbalanced perforating methods have been applied successfully since the 1950s, shooting both wireline and tubing-conveyed perforating guns. As shaped-charge jet-perforator systems became more advanced, using powdered metal liners, performance steadily improved. The art of minimizing the compacted and damaged area surrounding the perforation tunnel, commonly known as the crushed zone (Fig. 1), began shortly afterward. Much of the initial work involved shooting charges into prepared Berea sandstone cores while documenting the effect of a differential pressure toward the wellbore upon perforation efficiencies. As the benefits of an underbalanced pressure differential were observed, extensive testing established criteria for flow volumes and differential pressures required to remove or minimize the crushed zone created during the perforating event. Specifically documented was the role of trapped atmospheric pressure inside a perforating gun surrounding the shaped charge and components, known as free gun volume (FGV), which enabled the formation pressure to act as a differential and expel charge and crushed formation into the gun. As perforating research and field observations continued, a series of widely used and accepted formulas was established to document the magnitude of differential pressure required to ensure cleaned perforation tunnels. This paper reviews the effectiveness of each of these models, originally developed for a static underbalanced condition before perforating, to predict cleaning and removal of the crushed zone in a series of tests with a dynamic pressure differential. The test series uses an advanced perforation-flow laboratory to detonate an 11.1-g deep-penetrating shaped charge. Each charge will perforate a 24-in.-long, 7-in.-diameter Berea sandstone core with 3,950-psi applied pore pressure; 9,950-psi simulated overburden stress; and 4,900-psi wellbore pressure, creating a static 950-psi overbalance. Although the initial static condition will be overbalanced, a DUB condition will be established by wellbore and pore fluids filling the FGV upon detonation.

Targeted Fracturing Using Coiled-Tubing-Enabled Fracture Sleeves

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 154391, ’Reducing Operational Time, Fluid Usage, Hydraulic Horsepower, Risk, and Downtime: Targeted Fracs Using CT-Enabled Frac Sleeves,’ by Luis Castro, SPE, Thomas Watkins, SPE, Brian Bedore, SPE, and Robert Holt, Baker Hughes, and Greg Manuel, Pioneer Natural Resources, prepared for the 2012 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 27-28 March. The paper has not been peer reviewed. Unconventional reservoirs are an increasingly important part of the hydrocarbon production pool in North America. Because reservoir conditions typically require hydraulic fracturing for economical production, a significant amount of resources are focused on making the fracturing process faster and more efficient and on lowering its environmental impact. A novel technique to create targeted annular hydraulic fractures rapidly involves deploying an activation tool on coiled tubing (CT) to open fracture sleeves in a horizontal well. The new technology uses fracture sleeves that are activated swiftly using a CT bottomhole assembly (BHA). The system, already used in thousands of fracturing stages in Canada, speeds up the completion process, uses less fluid, minimizes risks, and reduces overall downtime. Introduction Unconventional reservoirs in the United States are commonly stimulated using what is known as the “plug-and-perf ” (P&P) method. This method requires a tubing-conveyed perforating (TCP) device run, typically on CT, for the first stage to open a conduit for pumping down the casing. The first stage of the fracturing treatment is then pumped down through the open perforations. Once completed, a composite plug and perforating guns are run on wireline to isolate the first fracture stage and to perforate intervals in the second stage (each interval is commonly referred to as a “cluster”). Running wireline in horizontal wells requires pumping fluid from surface to push the wireline BHA through the wellbore like a piston. After retrieving the wireline from the well, the subsequent fracture treatment is pumped. This process is repeated until all stages are completed. After the fracture spread moves off of the location, a CT unit is commonly brought in to mill the composite plugs and allow the well to produce. Although this method is the one most commonly used, it has drawbacks. P&P fracs are time consuming: They require numerous days on location to prepare the well (i.e., running the TCP device, known as a toe-shoot), complete all the stages designed for the fracturing treatment, and finally mill the plugs.

Use of High-Strength Coiled Tubing in High-Pressure/High-Temperature Perforating Operations

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 143079, ’Use of High-Strength Coiled Tubing in High- Pressure/High-Temperature Perforating Operations,’ by K. Makris, SPE, and D.A. Barclay, Halliburton, and W.D. VanArnam, NOV-Quality Tubing, originally prepared for the 2011 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 5-6 April. The paper has not been peer reviewed. A major operating company demonstrated interest in the development of high-strength (greater than 125,000-psi yield) coiled tubing (HS CT) for use in high-pressure/high-temperature (HP/HT) fields in the central North Sea. The objective of the operator was to perforate underbalanced with CT using as much as 1,700 ft of guns in one run. The CT had to be sufficiently strong to avoid collapsing while pulling the weight of the bottomhole assembly (BHA) and the string from the working depth. Introduction During last 2 decades, more unconventional reservoirs have been targeted, such as those in HP/HT fields. An HP/HT field typically has bottomhole pressure (BHP) greater than 10,000 psi and a bottomhole temperature greater than 300°F.The reasons for targeting these fields includes the high yield of hydrocarbons they offer, which justifies the high drilling and completion costs, and the depletion of the more-conventional reservoirs in areas with well-established oilfield-support services, meaning that this already-established network can offset the increased well costs. The range of well services used in HP/HT fields includes the provision of CT services, which have proved to offer a popular way to perform certain operations in these fields, such as deploying tubing-conveyed-perforating (TCP) guns. Often, the weight of the BHA and/or the wellhead pressure after perforating prohibits running perforating guns on wireline. On the other hand, using the rig blocks to deploy, run in hole, and reverse deploy the guns can be time consuming and costly. Hence, CT often can provide a carrier solution and perform such a task faster than the rig because it is stronger and has increased potential for wellbore access when compared to wireline. However, CT is limited by the weight it can pull and the differential pressure (CT annulus vs. CT pumping pressure) it can sustain. Exceeding these limits can result in a CT failure and result in a costly and time-consuming fishing job, or even a well-control situation. While more HP/HT fields are being developed, operators are considering the use of CT to perforate deeper wells with higher wellhead pressures. For the well-intervention industry to rise to the task, the need for stronger CT is obvious.

Polymer Treatment Controls Fluid Loss While Maintaining Hydrocarbon Flow

Technology Update The loss of pumped fluids that are circulated from surface to total depth (TD) and back during various drilling, completion, and intervention operations poses numerous problems affecting wells and reservoirs. Fluid loss (FL) to the formation is costly not only in terms of the fluid itself, diverted from its task, but in the time and expense required to mitigate the problem. Well control can be compromised, wellbore cleanouts impaired, and reservoirs damaged, sometimes permanently, as a result of fluids entering the formation. A low-viscosity, solids-free FL treatment can help (1) cure lost circulation, (2) prevent loss of expensive drill-in fluid during workovers, (3) improve well control by maintaining a hydrostatic column, and (4) provide FL control in vertical- and horizontal-well gravel-packing operations. The treatment technology, developed by Halliburton as the LO-Gard fluid-loss-control system, relies on an associative polymer to decrease matrix permeability to aqueous fluids, limiting leakoff into treated zones. A significant property of the treating fluid is that it causes little or no damage to the flow of hydrocarbons. The treatment fluid may be used in various applications.Well intervention cleanouts by coiled tubing and hydraulic workoverGravel packingMost lost-circulation events occurring during cementing, fracturing, and drillingAfter tubing-conveyed perforating (TCP) operationsFL control before, during, and after gravel packingElectrical submersible pump (ESP) replacement operationsCirculation maintenance in horizontal openhole completions across unconsolidated sands (Fig. 1)Formation permeability reduction inHigh-permeability streaksThinned or eroded drill-in fluid wall cakeBreeched or fractured wall cakeNatural- or hydraulic-fracture networks FL Problems and Causes During workovers, gravel-pack completions, ESP replacement, underbalanced TCP (UTCP), and other applications, aqueous well fluids are usually circulated continuously between the surface and TD. Maintenance of a hydrostatic column is necessary for well control and to enable treatment fluids to be injected into the targeted intervals downhole, without fear of overdisplacing the treatment fluids.

One-Trip Completion System Eliminates Perforations

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 101086, "One-Trip Sand-Control/Liner-Hanger/ Big-Bore Completion System," by C.R. Hoffman, SPE, Baker Oil Tools, prepared for the 2006 SPE Asia Pacific Oil & Gas Conference and Exhibition, Adelaide, Australia, 11–13 September. A new completion system replaces conventional tubing-conveyed perforating (TCP) and gravel packing. This technology also eliminates formation damage caused by perforating and reduces skin values. It is a new-generation, screenless-sand-control completion system. A telescoping conduit containing sand-control media composed of stainless-steel beads was chosen for its durability and erosion and plugging resistance. The system contains no explosives, eliminating many issues. Introduction A joint-investment project team consisting of three major operators, a service company, and an independent tool manufacturer was formed and charged with the task of developing a system that eliminated formation damage and greatly reduced skin values. Conventional perforating is a major cause of formation damage, so the primary goal was to eliminate perforations and still achieve connectivity with virgin reservoirs and maintain full-bore production and/or injection rates. Also, one-trip capability and user-friendliness were of primary concern; if this system were to cost operators more throughout the completion of a given well, it would have no merit in the marketplace. Therefore, the system was designed around conventional liner and cementing techniques. Purpose Fractured and compacted zones, perforation debris, and formation blockages are common types of damage that can occur in a conventional-perforation tunnel. Case histories have proved that skin values are significantly increased over the life of a well as a result of perforation-tunnel depth and fines that accumulate or are never properly cleaned from these tunnels. Studies have shown that for a 7½-in.-deep perforation tunnel, there may be as much as 60 lbm/ft of debris that must be cleaned from the wellbore. By design, this new technology addresses these factors affecting well productivity. The new technology had to satisfy the following criteria: one-trip deployment, primary cementing of casing tubulars, connectivity to a virgin reservoir, and sand control, all while maintaining cost effectiveness. One-trip installations reduce rig costs greatly. This new technology also addresses some of the problems associated with conventional cased-hole gravel packs such as incomplete perforation packing, voids in the annular pack, and poor communication with the reservoir. Drilling the New Well Use of a calcium-carbonate-based drill-in fluid while drilling the production or injection interval is quite common today. A manganese weighting agent may be used in these fluids to increase fluid density. The carbonate-based fluids provide a very thin, very uniform filter cake on the wellbore wall, providing stability to sensitive and unconsolidated formations. Also, the carbonate particles are acid soluble. This is imperative for this new system because when the telescoping conduits extend and contact the wellbore, a small amount of this material may be trapped on the face. With a barite-based mud there would be no way to remove this obstruction because barite is inert.

Techbits: Workshop Covers Scope of Deepwater Completions

One hundred forty attendees participated in the SPE Deepwater Completions Applied Technology Workshop (ATW) held in Galveston, Texas, and organized by Steering Committee Chairperson Syed Ali of Chevron. Kevin Lacy of BP presented the keynote speech, "Deepwater Completions—Failure Is Not an Option!" Seven informal technical sessions were conducted during the 2-day workshop. Topics includedDrilling/Completion Interface, chaired by Earl Coludrovich of Chevron and Lee Nirider of Marathon Oil.Upper-Completion Design, chaired by Stu Gosch of BP and Travis Hailey of Halliburton.Sandface Completion, chaired by Hugo Morales of Schlumberger and Brian Stewart of Devon Energy.Completion Evaluation, chaired by Mike Hecker of ExxonMobil and Tim Walker of Energy XXI U.S.A.New Technology Gaps, chaired by Jackie LaFontaine of Shell and Mike Loudermilk of Baker Oil Tools.Life-Cycle Management, chaired by Mitch Cornette of Chevron and Kevin Renfro of Anadarko.Best Practices, chaired by Sam Larkin of ConocoPhillips and John Mather of Chevron. Lacy kicked off the ATW, noting the industry's fundamental mission to find new resources, convert resources to reserves, monetize reserves at a "fair" profit, and reinvest profits to find new resources. Companies and managers that can effectively recognize, develop, and reward "mission-critical" skills not only survive but thrive, he said. Completions engineering is mission critical—for example, a successful single-well subsea tieback can provide a net present value of U.S. $136 million, but if the completion fails after 3 years, the net present value can drop by $65 million. He noted that completion costs had risen from 10–20% of total well-construction costs in the 1970s to today, where they are 40–50% and, in the near future, will be more than 50%. In the 1970s, drilling was considered a separate operation from completions, but today, drilling and completions usually are integrated into one "well construction" department. However, those departments usually are managed by people with drilling backgrounds; therefore, the complexities of completions—especially in deep water—and their "mission criticality" are often neither well understood nor appreciated, he said. He challenged the completions-engineering community to work toward driving cultural changes in drilling and completions to attain leadership and commitment at all levels of the organization and to attain data-based communication, effective supplier partnerships, and common processes. Drilling/Completion Interface Jack Burman of Exploitation Technologies discussed 10 wells developed for Anadarko and pointed out a number of rig-logistics opportunities that were exploited to save rig time. These included an annular "slick joint" of SM 2550 material to reduce blowout preventer wear between overhauls and improve control while doing multiple frac packs; the use of long (approximately 93 ft) assemblies lifted into place with a riser skate to reduce "invisible lost time" during completion operations and use of equally long intelligent-well packer assemblies; and working from this riser skate to use greater than 30-ft assemblies in wellbore cleanouts, tubing-conveyed perforating, pulling packer plugs and wear bushings, and in placing gravel-pack assemblies.

Underbalance Perforation in Long Horizontal Wells in the Andrew Field

Summary Andrew field in the U.K. Continental Shelf, which is operated by British Petroleum (BP) Exploration, is being developed using horizontal oil producers and completed with cemented liners. The main challenges of perforating these wells are maximizing well productivity by avoiding formation damage, minimizing the possibility of sanding, maximizing ultimate hydrocarbon recovery, perforating long horizontal sections safely and efficiently, optimizing the economic value of perforating, and minimizing perforating debris. In general, to avoid impairing well productivity, it is best to perforate the underbalance. However, the advantage is compromised, because of the fluid invasion and loss-control material, if a well will be killed when the tubing-conveyed perforating (TCP) guns are removed. Existing deployment methods with coiled tubing (CT) enable perforation and subsequent gun removal in an underbalance condition. Unfortunately, various limitations would require multiple runs with CT for perforating each horizontal well in the Andrew field, which would result in significant time and unbalance perforation for each subsequent run. The combination of the newly developed mechanical ball valve and the deployment of TCP guns with hydraulic workover units enables long horizontal wells to be perforated in one run in underbalance, and enables the guns to be removed without killing the well. Specially engineered guns and perforating charges are used to minimize sanding and gun debris. This paper describes how these new technologies, used for perforating operations, meet many challenges. The same technologies can be used readily for perforating other long horizontal wells with similar problems. To date, three horizontal wells in Andrew field were perforated successfully with the method described in this paper. The initial results indicate that the combination of the cemented liner completion, the engineered perforation systems, and the correct TCP gun deployment method using the mechanical deployment valve have contributed to improve well performance, to reduce cost, and to improve operability and safety in long horizontal wells.

Deploying Tubing-Conveyed Perforating Guns in a Live Well

This article is a synopsis of paper SPE 38147, "Method for Deploying Tubing-Conveyed Perforating Guns in Live-Well Conditions," by E.W. Van Sickle, SPE, Baker Oil Tools; Z. Sehnal, SPE, Statoil A/S; and K.D. Ireland, R.C. Harrison, SPE, and K.J. Haugvaldstad, Baker Oil Tools, originally presented at the 1997 SPE European Formation Damage Conference held in The Hague, The Netherlands, 2-3 June.

Results From the Heidrun Field Cased-Hole Gravel Packs

Summary During the initial phase of the Heidrun field development, five wells were precompleted with state-of-the-art cased-hole gravel-packing techniques. The wells were tested and temporarily abandoned, awaiting tieback to the Heidrun tension-leg platform (TLP). This paper describes the completion techniques applied and presents results of an evaluation of gravel-pack efficiency for the wells. Flow and buildup tests were carried out on the semisubmersible drilling rig before and after gravel packing to evaluate initial productivity. Stabilized well-test data acquired on the Heidrun TLP at full production are presented to document ultimate completion performance for each well. Innovations Perforating with tubing-conveyed perforating guns on a drillstem-test (DST) string allowed perforating, perforation cleanup and flowback, pre-gravel-pack testing, and gravel prepacking to be performed in a single run. A unique loss-control-material (LCM) formula was developed and applied to control fluid losses to the formation. Prepack modeling and alternating stages of clear brine and slurry were used to optimize gravel placement. A temporary-abandonment system was developed and installed that used a weight-actuated ball valve to abandon the well temporarily without placing any damaging fluids across the production zone. Gravel-pack screen assemblies included alternative-path gravel placement with four shunt tubes per gravel-pack screen assembly. The innovative gravel-packing techniques used at Heidrun resulted in high completion productivity and correspondingly high flow rates. A study performed to evaluate the economic impact of acceleration showed that going from a 20,000- to a 30,000-BOPD well rate added $108 million in pretax net present value to Heidrun project economics. Actual results will be greater because well rates have exceeded 43,000 BOPD. Introduction The Heidrun field lies 120 miles offshore mid-Norway in the Haltenbanken area in approximately 1,140 ft of water in the Norwegian Sea. Hydrocarbons were proven in three main reservoirs of Jurassic age: the Middle Jurassic Fangst group and the Lower Jurassic Tilje and Are formations. Fig. 1 provides a type log. The field is being developed from the world's first concrete-hull TLP. Ten wells were predrilled from the main 56-slot template along with six subsea, seawater injection wells drilled from the two four-slot satellite templates. First oil production occurred on Oct. 18, 1995. The Heidrun TLP is currently producing at plateau rate of more than 230,000 BOPD.

Monitoring and Analysis of Gravel-Packing Procedures To Explain Well Performance

Gravel-packed gas wells completed in the Gulf of Mexico since 1980 were reviewed to build a selective database for a completion-effectiveness study. Gas wells with clean, uniform sands were selected for analysis. Significant monitoring data identified were injectivity tests at different points during the completion and fluid loss rates (barrels per hour). Injectivity before gravel pacing and productivity after gravel pacing were classified according to sidewall-core permeabilities. Different gravel-pack preparation and execution techniques were reviewed. Fluid-loss-control pills were identified as the greatest source of damage restricting gravel-packed well productivity. Injectivity tests and sidewall-core permeabilities provide valuable information for monitoring well completion procedures.

A New Method of Overbalanced Perforating and Surging of Resin for Sand Control

Summary Gravel packing of perforations is the conventional method for sand control in the petroleum industry. Case histories of 12 well treatments provide details of a new procedure for high-energy resin placement that controls sand in a formation. The new consolidation method uses an extremely overbalanced pressure surge with liquid resin on perforations. This paper presents the problem, theory, process description, job procedure, and results of resin treatments with perforating or surging with a high-energy overbalanced pressure pulse. Highlights include potential applications. Benefits of the technique include accelerating on-line production and reducing completion rig time spent on controlling sand. The method appears to yield equal or better results than previous conventional gravel-packing techniques. Introduction The underbalanced method is the petroleum industry standard for perforating wells requiring sand control. Efforts to prevent the perforating guns from sanding up with for mation sand restrict the amount of underbalanced differential pressure. Sufficient underbalanced pressures for full perforation cleanup is not standard. Perforations that are not cleaned adequately will not readily accept resin during matrix injection. Operating companies took underbalanced perforating to offshore operations with the introduction of tubing-conveyed perforating guns in 1970. Today, few offshore operators consider overbalanced pressure in wellbores when perforating a well for sand control. Environmental concerns or equipment limitations provide a few cases of overbalanced perforating. In these rare instances, the fluid hydrostatic pressure will slightly exceed reservoir pressure. This reduces fluid invasion from mud or expensive brine water before the gravel-pack procedure. Until now, the industry has accepted underbalanced perforating and gravel packing as the best way to complete a well for sand control. Oryx Energy Co. began a research project on sand control in wells with gas generators and resin in Oct. 1988. Success with the propellant-gas fracture resin placement method led to extension of the research to include extreme overbalanced perforating with resin in Aug. 1990. The downhole high-energy placement of resin for sand control now challenges the industry's conventional standard of underbalanced perforating and gravel packing for sand control.

Completion and Testing of the 242°C BHST Well Dinjevac-1

Summary Well Dinjevac-1 (Di-1), located 120 km northeast of Zagreb, Croatia, was drilled in 1982 to a total depth (TD) of 5502 m. Mud logs, electrical logs, and drillstem tests (DST' s) in the Miocene section of the Pannonian basin indicated hydrocarbon saturation, extremely high temperatures, and relatively high pressures. These Miocene sediments are characterized as compact, low-permeability sandstones. In 1988, the abandoned cement plugs were drilled out and a bottomhole static temperature (BHST) of 242°C was measured. Temperature was the critical factor in the design of the completion and testing method. In spite of some minor quality-control and operational problems, five zones were tested successfully, providing all the relevant information about the reservoirs and the formation fluids. The operation incorporated a one-trip, hydraulically set, high-temperature, high-differential packer with a polished-bore receptacle and tubing-conveyed perforating guns with large, deep-penetrating charges. This paper describes the completion and testing objectives, considerations, operations, and results under probably the hottest completion conditions ever encountered.

Tubing-Conveyed Perforating: Operating Experience

Summary In 1981, Huffco Indonesia, a production-sharing contractor to Pertamina, was the first company in Indonesia to use tubing-conveyed perforating (TCP) in its well completions. This paper draws conclusions on the benefits of using a TCP technique over wireline perforating techniques. Of the 75 TCP jobs done, less than 10% can be considered failures. The results achieved with various amounts of underbalance are compared with published results. TCP is considered the most effective perforating technique currently available.

Single-Trip Tubing-Conveyed Perforating, Production Testing, and Pressure-Buildup Testing in Nonflowing Wells

Summary This paper describes tools and procedures for tubing-conveyed perforating (TCP) and subsequent production testing of a well with a reverse-flow jet pump with a specially designed blanking sleeve. A downhole shut-in pressure buildup is also obtained and all equipment is pressure-actuated, eliminating the use of wireline.

Analyses and Applications of Pressure, Flow Rate, and Temperature Measurements During a Perforating Run

Summary Perforating technology has undergone significant advances during the last decade. Tubing-conveyed perforating, under-balanced perforating, high-shot-density guns, better shaped charges, and improved gun systems have contributed to safer operations and improved productivity of the perforated completions. A recent development described in this paper is a perforating tool that makes real-time downhole measurements [including pressure, flow rate, temperature, gamma ray, casing-collar locator (CCL), and cable tension] during a perforating run and can selectively fire a number of guns at different depths or times. In addition to providing better control of the perforating process, the simultaneous downhole measurements can provide in a single trip a production log, conventional well tests before and after perforating, and a fill-up or slug test soon after perforating for underbalanced conditions. Thus, the completion can be evaluated in real time and any needed remedial reperforating can be performed while the gun is still in the hole. Other applications include limited-entry perforating, monitoring of bottomhole pressure (BHP) during minifracture jobs, better depth control with a gamma ray detector, fluid-level monitoring, and underbalance control. The applications of these measurements, with field data obtained with the Measurement While Perforating (MWPSM) tool, are the subject of this paper. Examples show the capabilities and the versatility of the MWP tool.