Openhole Horizontal Wells Research Articles

Technology Focus: Drilling and Completion Fluids (November 2013)

Technology Focus This year has been a great year for me; I was able to play more rounds of golf than expected! I was also successful in sealing a few research collaboration agreements within the oil and gas industry. In September, I completed my 2-year tenure as deputy director of the University of Malaya Center of Innovation and Commercialization (UMCIC). UMCIC is the technology-transfer office at the University of Malaya, and it is responsible for protecting inventions through intellectual-property registration (patent, copyright, trade secrets) as well as promoting ideas through commercialization activities (licensing, outright sale, creation of spinoff companies). It is no secret that commercializing research output is not as easy as 1, 2, 3. One important lesson I learned is to ensure that each patent filed originates from a great, novel idea. Ideas that are not new are considered prior art. A patent cannot be filed on previous ideas. Even if filing were possible, it would be a huge challenge to commercialize it. Thus, new steps have been introduced by UMCIC, leading to a panel of select experts of various backgrounds who perform comprehensive patent screening and evaluation. The experts also provide valuable advice to researchers. The reality is that innovative ideas facilitate commercialization of the idea itself. Brilliant ideas are one of the main elements that drive the technological advancements in the industry. This is particularly true in upstream oil and gas. The scarcity of natural resources and increases in the demand for oil and gas cause the industry to rely heavily on novel technology. To stay relevant and competitive, companies tend to focus on four key initiatives: the use of technology as a means to innovation, sound management through flawless execution, integration of a broad range of functional areas, and application of best practices. In this feature, I highlighted four interesting papers on innovative ideas and technology in the upstream oil and gas industry. Innovation is everywhere—and the game of golf is no exception. Novel ideas and technological breakthroughs have helped many golfers enjoy their game much more as they shoot lower scores. A golfer like me needs the technology out there to ensure “green in regulation” and to “get up and down.” Selecting the right technology will allow you to lower your scores, lengthen your career, have more fun, and, most importantly, walk and smile like Tiger Woods on the golf course. I hope you enjoy and benefit from the selected and highlighted papers. There are other interesting papers on the recommended reading list. For further reading, the OnePetro online library has additional papers. Recommended additional reading at OnePetro: www.onepetro.org. SPE 156575 Development of Environmentally Friendly Lost-Circulation Materials for Riserless Drilling by Hitoshi Matsui, Waseda University, et al. SPE 164748 Engineered LCM Design Yields Novel Activating Material for Potential Application in Severe Lost-Circulation Scenarios by Sharath Savari, Halliburton, et al. SPE 165335 A Novel Mud Formulation for Drilling Operations in the Permafrost by Ahmed H. Kamel, The University of Texas of the Permian Basin SPE 161914 Evaluation of Nonreactive Aqueous Spacer Fluids for Oil-Based-Mud Displacement in Openhole Horizontal Wells by Peter Osode, Saudi Aramco, et al.

Study on Axial Force of Multi-Stage Fracturing String in Horizontal Wells

In order to investigate packer failures during multi-stage fracturing in horizontal open-hole wells, mechanical model is established according to the working process of multi-stage fracturing. The influence of temperature and pressure changes on packers and tubing string is considered in this model. Case study indicated that force in each packer changes obviously in different fracturing stage; the force on the hanger is large in the whole fracturing process, and it will change direction opposite to the original direction in the last fracturing interval; in a given fracturing interval, the force in the upper packer is much higher than that in the lower packer; due to the restriction of the packers, the axial force distribution of the tubing is not smooth and changes abruptly at packers. Therefore, the pressure bearing capacity of packers should be taken into account during design and operation, and based on which appropriate packers and operation parameters be selected.

Technology Focus: Horizontal and Complex-Trajectory Wells (November 2009)

Technology Focus The past year has experienced dramatic changes in industry activities. Despite the downturn, it has been encouraging to see that there has remained an active interest through various industry events and discussions in improvement in the delivery of complex wells. I had the opportunity to participate in several SPE Advanced Technology Workshops (ATWs) and Forums related to this topic, and it was great to see record attendances, which provided for a diverse, yet high-quality, discussion and interaction. Design factors, improving drilling execution, and complex-well design, along with maximizing reservoir contact for horizontal and complex wells, are still major industry drivers, even though the industry has already drilled and completed many thousands of these wells. Every year, new technology enters the market place providing potential for improvement of all aspects of horizontal-well operations, but on the basis of excellent and open discussions at SPE events, there still are further challenges to overcome. Conclusions from several meetings included positive reactions to the introduction of new technologies in helping drive performance to new levels, but it was highlighted that the repeatability depended upon good knowledge capture and transfer of learning. Development of the structured approach, focused on continuous improvement, is as relevant today as it was 20 years ago. This message was echoed at all ATWs and Forums. The reduction in nonproductive time and overcoming operational challenges through better planning, although well known, are still a required focus. As the industry adapts to a constantly evolving horizontal- and complex-well environment, positional accuracy and placement of the well trajectory are critical to better reservoir contact and production. One interesting conclusion was that the successful drilling of many highly challenging wells appears to have been taken for granted. However, delivering the completion phase on long-stepout wells and management of the reservoir remain challenges for the future. Horizontal and Complex-Trajectory Wells additional reading available at OnePetro: www.onepetro.org SPE 118809 • "Beyond the Technical Limit: Turbodrilling—A Paradigm Shift to World-Class Horizontal-Well Construction" by Todd Mushovic, BP plc, et al. SPE 119599 • "Inflow-Control Device: An Innovative Completion Solution From Extended Wellbore to Extended Well Life Cycle" by Saif Ali Al Arfi, ADCO, et al. SPE 120579 • "A Comparison Between Multifractured Horizontal and Fishbone Wells for Development of Low-Permeability Fields" by Xiance Yu, University of Louisiana at Lafayette, et al. SPE 123008 • "First Applications of Inflow-Control Devices (ICDs) in Openhole Horizontal Wells in Block 15, Ecuador" by P. Roman, Petroamazonas, et al. OTC 19910 • "The Longest Challenge: Overview of a Groundbreaking Horizontal Well in Gimboa Field, Angola" by K.D. Contreiras, Sonangol Pesquisa & Produção, et al.

A Novel Stimulation Technique for Horizontal Openhole Wells in Carbonate Reservoirs—A Case Study in Kuwait

Summary Effective matrix acidizing in Kuwait's horizontal openhole wells is a big challenge. Reservoir heterogeneity and the length of the horizontal wells make acid placement and diversion difficult, particularly in high-water-cut (WC) wells in which water has broken through as a result of high-permeability streaks or natural fractures. Furthermore, acid penetration is limited by the large surface area of the horizontal wellbore, and this is exacerbated by the relatively small injection rate imposed by the use of coiled tubing (CT). To make matters worse, formation damage in horizontal wells is usually very deep as a result of long exposure times. This paper discusses the application of a new viscoelastic-surfactant (VES)-based, self-diverting acid system for stimulation of more than 20 horizontal openhole wells in carbonate reservoirs in Kuwait. The application also deployed a new nonparticulate material that forms a highly viscous plug when it contacts water and that degrades when mixed with oil in the formation. The new fluid system is pumped before the acid treatment to effectively prevent the acid from stimulating high-water-saturation sections. The field results show significant improvement in post-stimulation production, owing to effective diversion and water-production control compared with wells in which a conventional polymer-diversion technique was used in the past with no consideration for water-production control in high-WC cases. The new technique has been selected as the standard stimulation practice in most horizontal openhole carbonate wells in Kuwait.

A New Barnett Shale Horizontal Completion Lowers Cost and Improves Efficiency

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 103046, "New Barnett Shale Horizontal Completion Lowers Cost and Improves Efficiency," by D. Lohoefer, SPE, Eagle Oil and Gas, and J. Athans, SPE, and R. Seale, SPE, Packers Plus Energy Services, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September. A new completion has been deployed in the Barnett shale that is fast, efficient, and less costly than the former standard completion. By use of specially designed mechanical openhole packers run on the production liner, mechanical diversion in the openhole section can be accomplished at predetermined points. Each stage in the horizontal section can have a specifically designed fracturing or stimulation procedure. The system also allows all of the fracturing or stimulation treatments to be pumped in one continuous operation, with the added benefit of restimulating all or selected intervals at a later date if desired. Introduction During the past 5 years, horizontal drilling has become the exploitation method of choice in the Barnett shale. Several completion methods have evolved during this time. In one standard completion process, the horizontal section is cased and cemented, and completing the well consists of running and setting a composite plug on coiled tubing (CT), perforating, stimulating, flowing the well back, and repeating the process for the required number of stimulations for the horizontal wellbore (Fig. 1). This process is very costly and time consuming, with the added risk of having to remove the composite plugs; also, there currently is no viable method for restimulating these wells at a later date. One of the most successful and efficient completion methods has been a recently developed openhole completion providing mechanical diversion. Nearly 6 years ago, a technology gap was identified for openhole completions in horizontal wells. It was determined that mechanical diversion was needed to fracture various sections of the lateral effectively. Without mechanical diversion, there was no viable way to direct the fracture for optimal production results. Fracturing operations were concentrated in one particular section of the horizontal well, typically at the heel, thus leaving much of the wellbore unstimulated and, ultimately, unproductive. It is from these initial system developments that the horizontal openhole fracturing system that exists today was produced. A mechanical openhole packer was developed specifically to withstand the harsh environments encountered in the high-pressure/high-temperature (HP/HT) fracturing environment. The packer and system components were designed to hold 10,000-psi differential operating pressure at temperatures up to 425°F while having expansion capabilities greater than 50% of the original packer outside diameter. System developments also included fluid-deployment systems placed between the openhole packers to deliver the fracture treatment in the optimal position. This field-proven system is now more than 4 years old, with more than 300 successful systems deployed in horizontal openhole wells. Applications include wells from 1,000 to 15,000 ft true vertical depth with horizontal wellbores as long as 6,700 ft. Further evidence of the versatility of the system is the ability to design the stage length at the rigsite and place the components from the two systems together to optimize the stimulation for a particular zone or to segregate a nonproductive zone.

Horizontal-Openhole Gravel-Packing Operations in the Campos Basin

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 106364, "The 200th Horizontal-Openhole Gravel-Packing Operation in Campos Basin: A Milestone in the History of Petrobras Completion Practices in Ultradeep Waters," by L.C.C. Marques, SPE, L.C.A. Paixao, V.P. Barbosa, M.O. Martins, A. Calderon, SPE, C.A. Pedroso, SPE, L.H.C. Fernandes, J.A. Melo, C.M. Chagas, and N.J. Denadai, Petrobras, prepared for the 2007 SPE European Formation Damage Conference, Scheveningen, The Netherlands, 30 May-1 June. The full-length paper presents an overview of the evolution of openhole gravel-packing practices and experience after 200 wells have been completed successfully with this technique in the Campos basin. A comprehensive description of the main steps taken to improve horizontal-openhole gravel-packing (HOHGP) practices in unconsolidated oil-bearing turbidites is presented. Since the first HOHGP job in 1988, completions have moved progressively from shallow- to ultradeepwater scenarios. Along this path, a series of innovations has been incorporated into the sand-face-completion practices. Introduction The most prolific reservoirs in the Campos basin are the Upper Cretaceous and Tertiary turbidites. The high-permeability (approximately 1,000 to 8,000 md) stacked and amalgamated reservoirs are spread over shallow, deep, and ultradeep water within the basin. Dictated by the depositional model associated with turbidites, the sand uniformity of these poorly- or unconsolidated sand lenses varies significantly. The presence of reactive-shale streaks is recurrent in some of these turbidites. As in many other offshore basins in the world, the first oil discoveries (early in the 1980s) were in shallow waters. These good exploratory results propelled the move progressively from shallow to ultradeep water. However, since the original oil discoveries, it has been realized that a sand-management strategy was necessary to achieve desirable production levels. Sand control is an umbrella term comprising different approaches to dealing with sand-production problems. Sand-control methods include frac pack, chemical consolidation, screens, and gravel packing. The Petrobras philosophy is one of zero tolerance for sand production. Should there be the slightest chance of sand production, a sand-control method is installed in wells. This preventative approach stems from wellbore-integrity concerns, prohibitively high well-intervention costs, the need to maximize production rates, safety concerns, and the inability of topside equipment to handle sand. Gravel packing is considered the best alternative for sand control in horizontal-openhole wells with good vertical permeability, nonuniform sands, and no lamination. In addition, filling the screen/wellbore annulus of an openhole horizontal well with properly sized gravel creates a secondary barrier to the migrating sand grains, thus increasing the longevity of the gravel-pack screens.

Torque and Drag Modeling for Horizontal Openhole Completions

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 97079, "Torque and Drag Modeling for Horizontal Openhole Completions," by R. Rezvani, Halliburton/Sperry Sun, and B. Techentien, Halliburton Energy Services Inc., prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October. With horizontal openhole sections being drilled to lengths that exceed 20,000 ft, placement of the completion string (CS) to planned total depth (TD) may not be possible if the proposed drilling plan is not studied carefully. It is important to model the well before attempting to run the planned completion to deter-mine whether the CS can withstand the strains (tension, compression, and torque) of installation, as well as whether the upper CS has sufficient weight to push the lower CS to TD. Introduction Frictional drag can prevent installation of a CS to TD of a well. This situation can be especially critical in an open-hole horizontal well with the additional challenges inherent in gravel-pack assemblies. Because of the increased costs and risks in these well scenarios, accurate assessment of the stresses to which the CS could be subjected during installation is critical. The technique that is detailed in the full-length paper provides the completion designer with an additional tool in designing a CS that can withstand the downhole stresses encountered during its running. For example, if the modeling process indicates that the CS will not withstand the stresses of installation without failing from tensile loading, buckling from the compression load, or failing from rotational torque, a different well plan must be devised. The operator then must formulate a new configuration, which then can be assessed with the torque and drag models for primary assessing of the capabilities of the new configuration. Recent technological advances in drilling have resulted in new drilling and measurement equipment for both offshore and onshore drilling. Major changes in the drilling sector have resulted from the following.The advent of rotary-steerable systems and integration of computer and information technology into the down-hole drilling processes.Larger and stronger drilling rigs.High-pressure/high-temperature measurement-while-drilling tools with an increased array of improved sensors. Real-time data can be transmitted from downhole to surface and from the rigsite to the office. These capabilities have improved drilling efficiency such that many of the wells being drilled and completed today could not have been developed and/or financed before these advances. Rotary-steerable systems have enabled drilling wells deeper and to greater horizontal lengths, as well as enabling wells to reach reservoirs that previously were not accessible. These advantages improve the overall economics of the projects. By design, downhole completion hardware is not as rugged as drillpipe or drilling assemblies. The new wellbores enabled by the advances in drilling technology can induce loads and stresses not experienced before and that must be evaluated and understood fully before designing the CS. The drillstring can be rotated to TD, and casing strings are floated to TD. However, the CS cannot be rotated or floated.

Use of Viscoelastic Surfactant-Based Diverting Agents for Acid Stimulation: Case Histories in GOM

Summary Viscoelastic-surfactant (VES) -based diverting products have been used successfully in matrix acidizing in the Gulf of Mexico (GOM) in recent years. The uses of VES diverters range from remedial matrix-acid or nonacid-cleanup treatments to use before gravel- or frac-packing operations to clean up long intervals after perforating. Success or failure of these treatments is often related to the efficiency of diverting agents, especially for acid treatments on wells with long, heterogeneous intervals or multiple-zone completions. A VES diverting agent is of particular interest to remedial treatments of frac-/gravel-packed wells, because damage to the near-wellbore area and completion should be minimized for optimum production. Laboratory studies and field applications have demonstrated the nondamaging properties of a VES fluid. This paper reviews the properties of the vesicular-type VES diverting fluid, reviews the operational considerations, and presents several case histories with VES diverting agents in the GOM. The bottomhole static temperatures (BHSTs) of these cases range from 140 to 290°F for both gas and oil wells. With an internal breaker system, the diverter does not require contact with formation fluid, brine, or acid to clean up and provide optimum production. In some cases, as many as four stages of diverters were pumped in the treatment, and successful diversion was observed for each stage. The paper outlines field-operational considerations and detailed fluid properties, which were tailored to specific well conditions and formation characteristics. Details and pressure responses of the treatments are discussed. Introduction Matrix-acid stimulation has been frequently used in the GOM to remove formation damage caused by drilling-mud invasion, clay swelling and clay migration, and production impairment from inorganic scaling. When acid is injected into the reservoir below the fracturing rate and pressure, acid will typically enter the region with the highest permeability. Proper diversion is required to direct the treatment fluid into the damaged zone to achieve maximum benefit of the acid stimulation. Another area that employs acid treatment in the GOM completions is damage removal before gravel packs or frac packs. Gravel packing has been extensively used as a standard sand-control treatment in the GOM for several decades. Before or after the placement of gravel with completion fluids, low-density brines, or linear gels, an acid treatment is usually pumped to remove the near-wellbore formation damage or high skins encountered in wells perforated overbalanced (Unneland and Waage 1996; Matherne and Hall 1996). In other cases, a clay-acid package is often pumped into the formation before the gravel pack to stabilize the residual clays. The effectiveness of these treatments is often directly related to the ability of the acid treatment to remove the near-wellbore damage and connect the wellbore to the formation. In addition to determining the most effective combination of acid blends and volumes for each particular reservoir, treatment design and planning are done to ensure that the correct procedure is followed to place the acid across the entire interval. Staging of the treatment is used to force acid across the entire interval, treating the damaged portion of the completion. The successful acid placement in matrix treatments of openhole horizontal wells are even more difficult because of the length of the zone treated and potential variation of the formation properties. A successful diversion technique is critical to place the acid at the location where damage exists. A variety of diversion techniques have been practiced in acid stimulations (Rae and di Lullo 2003). Diversion sometimes can be achieved by simply increasing pumping rate during the acid treatment. Viscous diversion techniques such as hydroxyethyl cellulous (HEC) gelled brine and nitrogen foam are often used, especially when the temperature of the well is not very high. Other materials used as an acid-diverting agent include acid-insoluble particulates. A mechanic method such as a ball sealer also has been successful when it is practical. Most of these methods have some limitation to their application, especially in a completion with a sand-control method installed. VES-based diverting products have been developed and widely used in recent years, and their use has found application beyond the limitations of the previously mentioned techniques.

Techbits: Enhancing Production in Russia's Oil and Gas Fields

Nearly 100 participants in an SPE Applied Technology Workshop (ATW) in Moscow discussed the application of horizontal wells (HWs) and multilateral wells (MWs) in Russia, where horizontal drilling is widely practiced. Case studies were presented from western Siberia, Sakhalin, Canada, the Middle East, and the North Sea to stimulate discussion of where it is best to use HWs and MWs and, alternatively, where other forms of production enhancement such as hydraulic fracturing might be more appropriate. The second part of the workshop focused on execution—drilling, completion, and life-of-field monitoring. Status of Well Technology Sibneft Chief Engineer Iskander Diyashev opened the discussion, describing how the company has enhanced production in its Noyabrsk western Siberia operation with 50% of the increase coming from HWs (even though these wells make up only 4% of the total well stock). TRACS-Consult Petroleum Engineering Consultant Robert Holtslag gave an overview of HWs in Russia where there are ≈2,500 of a worldwide total of ≈75,000. The Russian wells have productivity improvement (PI) factors in the range of 1.2–3. Holtslag pointed out that a major challenge is to increase the lower end of this range so that more HWs have robust economics. Schlumberger Middle East Chief Reservoir Engineer Fikri Kuchuk examined HW and MW performance, emphasizing the shortfall in performance as a result of inadequate cleanup, water sumps in the wellbore, and uneven pressure distribution in the near-wellbore formation that may reduce the PI factor to 30–50% of its potential value. He stressed the importance of drilling horizontal sections, which avoids sumps and highs where water and gas can accumulate. Sibneft Reservoir Engineer Elena Khairulina presented implementation of modeling HW performance using many examples from Noyabrsk. Case Histories and Screening Sibneft Reservoir Engineer Larisa Gaponova described the optimization of Sugmutsky field development by use of HWs. The peak oil production almost doubled with a much smaller number of wells. She compared a 500-m-long HW with a vertical well (VW) with a vertical hydraulic fracture. The initial PI factor was ≈4.4, stabilizing at a current value of 3, while the initial water cut was two times less than that from a typical VW and stabilized at 3.4 times less. Sibneft Stimulation and Completion Engineer Andrey Brovchuk explained hydraulic fracturing of openhole HWs in western Siberia, showing that a post-frac improvement of 150% was achieved and that 3.5% of production was achieved from 14 HWs with hydraulic fractures. Economides Consulting Partner Andronikus Demarchos described a transversely fractured HW in Algeria where four fractures were created with 70-m spacing along an HW. Each fracture used 100 to 200 tons of proppant. Results will become known when bridge plugs, needed in order to create multiple fractures, are drilled out.

New Levels in Technology: Seizing the Moment

At a time when the industry faces unprecedented demand and extraordinary challenges, participants in the 2005 SPE Annual Technical Conference and Exhibition (ATCE) will find a mammoth array of new technology and industry wisdom. This year’s event, “Knowledge Shared,” is all about striving to reach new levels in every operating arena. The conference will take place 9–12 October at the Dallas Convention Center. Selected by the SPE ATCE Program Committee from more than 530 upcoming pre-sentations, the following four papers exemplify industry initiatives and demonstrate the expansive topics on this year’s technical agenda. An assessment of how the fate of 160 wells led to the development of highly useful flux-based guidelines for Na Kika’s sand-control completions; a testament to use of novel techniques and exceptional field execution to streamline deepwater completions like Marco Polo; an update from Chevron on the road from corporate vision to an actual digital oil field; and a compelling case of common process with an online integrated project-management application promise to improve the industry’s rapidly changing and increasing knowledge base. Setting Safe Maximum Producing Rates The best of all worlds, particularly on a deepwater development such as Na Kika, is to meet targeted production rates without unnecessarily compromising long-term sand-control reliability. To achieve this objective, Shell and BP jointly developed the Na Kika offtake guidelines by using a blending of recent sand-control operational methodologies from each company. This paper focuses on the use of the Bpflux (a registered trademark of bp plc) guidelines, which provide the maximum safe operating rates for sand-control completions using a C-factor that is directly proportional to the perforation velocity. This C-factor allows wells with excellent completion quality to produce at twice the rate of wells with unknown or poor completion quality. The Na Kika development includes five subsea fields in the deepwater Gulf of Mexico (GOM) and is jointly owned by Shell and BP. All 10 wells in the Na Kika development have sand-control completions; two are openhole horizontal wells with gravel packs, and eight are cased holes with frac packs. There is also a wide variety of completion types. One field has two openhole horizontal wells with 1,500-ft laterals that are oil wells. The other eight wells are cased-hole frac packs, with three triple-stacked completions, two stacked completions, and three singles, for a total of 16 separate frac-pack completions. There are three gas and seven oil wells. Four of the cased-hole wells have intelligent completions. “We have powerful new methods to safely operate high-profile sand-control completions,” said author Richard Keck. “Application of the guidelines at Na Kika has yielded substantial incremental production and helped keep the field at plateau rates much longer than was planned.” This paper offers an overview of the new guidelines and demonstrates how they were used during the life of the field, including well planning, during well startup, and later, when wells have increasing skin. The authors also present a review of the actual Na Kika completion quality, examining those elements of completion design and execution that correlate with the measured skins.

Deepwater Subsea Completion Benefits From Horizontal Fracture Stimulation

In late 2004, for the first time in history, a deepwater, subsea well was fracture stimulated using hydrajet-based fracturing with no downhole isolation. The well is located in 1,000 ft of water in the Campos Basin, southeast of Brazil. As the stimulated well had two branches abandoned due to drilling problems it behaved like a triple-lateral in terms of stimulation design. The 2.5-day treatment for Petrobras, closely monitored in real time from Duncan, Oklahoma, and Macaé and Rio, Brazil, resulted in five acid fractures created using the ZCA acid system. Production rate for the first 15 production days following the treatment with Halliburton’s SurgiFrac service approximately doubled the maximum historical rate of this well and was approximately four times the monthly production rate. As with vertical wells, in horizontal completions underachieving wells are common. This can be caused by many things, such as unexpectedly low permeabilities in the area; however, in horizontal wells, underperformance often is attributable to one or more of the following: - Permeability anisotropy (especially vertical-permeability limitations). - Skin damage or near-wellbore plugging of a natural-fracture network. - Ineffective stimulation techniques. The third item is especially the case in openhole horizontal wells and even more so in wells that are completed with slotted or preperforated liners. Perforated liners could be deemed the worst-case scenario when attempting to place multiple hydraulic fractures in the horizontal section. Controlling Fracture Placement This technology is the first method to resolve the problem of openhole fracture-placement control using dynamic diversion and consists of a combination of three processes—through-tubing hydrajetting, through-tubing hydraulic fracturing, and coinjection down the annulus with separate pumping equipment. An important aspect of this technique is dynamic sealing capability (Fig. 1). Unlike other techniques that require hardware-type packers or plugs or even chemical plugs, this process creates a seal using fluid movement. Packers are generally not used; therefore, the existence of passageways behind liner or through fractures rarely affects performance. The technique is based primarily on the Bernoulli principle, which states that the energy level of a fluid is generally maintained constant. To accomplish the SurgiFrac process, a jetting tool is placed near the toe of the well and is then used to jet perforate the casing and the formation rock, forming a 4- to 6-in.-deep cavity. Based upon the Bernoulli equation, as pressurized fluid exits the jet-ting tool, the pressure energy is transformed into kinetic energy or velocity. Since the fluid velocity around the jet stream is the highest, pressure in this area is the lowest (the fluid does not tend to “leak” out). Conversely, fluid from the other areas of the well will flow into the jetted area. The fluid contains some abrasives to help the fluid penetrate the steel liner and the formation rock. As cavities are formed by each jet, high-velocity fluid impacts the bottom of the cavity (i.e., velocity becomes zero—an energy change from kinetic back to potential energy, or pressure), causing pressure inside the rock to become high enough to create a fracture. Annulus pressure is then increased to assist in fracture extension. After the fracture is completed, the tool is moved to the next fracturing position and another fracture is placed.

Development of the Alba Field—Evolution of Completion Practices, Part 2: Openhole Completions, Conventional Gravel Packing After Drilling With SOBM

Summary Chevron has been successfully drilling and gravel packing openhole horizontal wells in the Alba field (central North Sea) since 1998, and 13 openhole gravel-packed (OHGP) wells drilled with water-based mud (WBM) are currently in production with no history of sand production. Although these wells have been hugely successful with significant net present value (NPV) returns, it was recognized that the future, mature redrill and infill targets cannot sustain the current costs associated with traditional OHGP completions. The challenge was to develop alternative techniques to maintain the benefits of OHGP wells but to achieve a low-cost well and completion concept to assist in realizing new drilling opportunities. Drilling the shale above the top of the reservoir and the productive interval in a single hole section would require removing conventional requirements for setting an additional casing string and changing over to a water-based system before drilling into the reservoir. This would save costs but raises a question concerning the gravel-packing operation. Hitherto, attempts to gravel pack that involve alpha/beta placement techniques using an aqueous carrier fluid following drilling with oil-based systems have had only limited success. The prospective problems were examined by extensive laboratory tests carried out cooperatively by Baroid and Chevron. A new, synthetic oil-based mud (SOBM) formulation was developed, and compatible displacement fluids and procedures were devised. Based on this work, 1,500 ft of shale and reservoir were drilled, a liner that was predrilled over the reservoir section was installed, and screen was run inside the liner. Gravel was pumped using brine as the carrier fluid, and complete gravel placement was achieved. The well has achieved productivity levels at least as good as existing WBM wells. A second well completed in the same manner has given a similar performance. This combination of a liner system and SOBM fluids offers several advantages. There is the prospect of considerable savings with respect to operating time, cementing, and drilling fluids. The liner also gives protection to the screen. This new approach, which represents potential large savings in costs and excellent productivity, is considered applicable to other types of completions when it is desirable to drill with oil-based mud even though conventional thinking would have called for water-based drill-in fluid. This consideration applies to targets in the Alba field and worldwide.

Sensitivity Analysis of Horizontal Well Productivity Under Steady-State Conditions

Many horizontal wells are being drilled all over the world to increase productivity in comparison to that of vertical wells. Horizontal wells increase reservoir contact area and thus increase productivity. Therefore it is essential to be able to predict the horizontal well productivity. The major objectives of this investigation are to (1) develop a comprehensive evaluation of currently-used steady-state productivity equations of horizontal wells, (2) investigate the effect of horizontal well length and pay zone thickness on the productivity ratio of horizontal well to vertical well when both have the same drainage area and identical flow conditions, and (3) study the influence of pressure drop on production rate of horizontal wells using different steadystate flow equations. In this study, six different steady-state equations of the open-hole horizontal wells under identical conditions of flow parameters and reservoir geometry are subjected to a wide range of horizontal well lengths (100-3,000 ft), pay zone thickness (50-500 ft), and pressure drop (10-200 psi). These horizontal wells were used to calculate the productivity and study the influences of flow rate and pressure drop on the sensitivity of these equations. The obtained results showed that all steady-state equations provide similar horizontal well productivity for horizontal well length <1,000 ft, while a remarkable difference appears and increases when well length increases >1,000 ft. In addition, the results using all steady-state equations confirmed the recommendation of the application of horizontal wells for thin formations and do not recommend it in thick ones (h > 250 ft) for wells having identical rock and fluid properties. Comparing the performance of steady-state equations showed that all of these equations are sensitive to the increase in pressure drop, which yields an increase in the flow rate of horizontal wells. The results of this study have important implications in reservoir simulation studies, since it evaluates some important variables including pay zone thickness, well length, and pressure drop on the performance of each flow equation.

Selectively Placing Many Fractures in Openhole Horizontal Wells Improves Production

Summary This paper presents the results of a study on an openhole well that was treated with a new fracturing process—hydrajet fracturing. In only a single pass, hydrajet fracturing allows operators to use high-pressure jets to place multiple fractures accurately in several locations in a well. To fracture the well most effectively, the process uses surface and downhole data recorders to monitor well conditions. Study results show that the hydrajet fracturing process is an effective, economical method for fracture-treating openhole horizontal wells.

Optimization of Mud Cleanup for Openhole Horizontal Wells

Summary Successful completion of openhole horizontal wells requires removal of potential impairment from the near wellbore and formation face. Impairment can reduce well productivity and lead to failure of sand control screens due to plugging and erosion. Shell has adopted the practice in the Gulf of Mexico of employing drill-in fluids with acid-soluble bridging and weighting agents for all openhole drilling and extensive displacement and acid cleanup procedures during horizontal well completions. Drill-in fluid and filtercakes are removed with specially formulated sweeps and by attainment of sufficient velocity to achieve effective displacement. Filtercakes are removed with specially formulated washes applied using washcups or coil tubing to ensure that the cleanup formulations contact the filtercake materials. Drill-in fluids and cleanup systems must be specially formulated and evaluated for specific applications. We have adopted a suite of laboratory screening tests to evaluate formation damage and removal chemistries to ensure that each well is effectively cleaned. These tests can also be used to evaluate new fluid systems before taking them to the field. Our approach in this instance is to compare data from new fluids to results obtained with fluids with which we have a successful field track record. In this article we will review these procedures and the results with a variety of fluid systems.

Stimulation-Chemistry Optimization for Openhole Horizontal Wells

This article is a synopsis of paper SPE 49098, "Optimization of Stimulation Chemistry for Openhole Horizontal Wells," by L.N. Morgenthaler, SPE, R.I. McNeil, SPE, R.J. Faircloth, A.L. Collins, and C.L. Davis, Shell E&amp;P Technology Co., prepared for the 1998 SPE Annual Technical Conference and Exhibition, New Orleans, 27-30 September.