SPE/IADC 105443 Are Swelling-Elastomer Technology, Preperforated Liner; and Intelligent-Well Technology Suitable Alternatives to Conventional Completion Architecture? Gary P. Hertfelder, SPE, and Kurt Koerner, SPE, Plains E&P Co.; Allen Wilkins, SPE, Easywell; and Lilian Izquierdo, SPE, Schlumberger Copyright 2007, SPE/IADC Drilling Conference This paper was prepared for presentation at the 2007 SPE/IADC Drilling Conference held in Amsterdam, The Netherlands, 20 22 February 2007. This paper was selected for presentation by an SPE/IADC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers or International Association of Drilling Contractors and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the SPE, IADC, their officers, or members. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers and International Association of Drilling Contractors is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836 U.S.A., fax 1.972.952.9435. Abstract An independent operator in offshore California has integrated swelling elastomer technology and preperforated liners with triple-zone intelligent well completions for an extended-reach drilling (ERD) campaign in their Rocky Point field. To date, three deployments have been successfully installed in this field, and each has provided successful zonal isolation without conventional cementing and perforating methods. The Rocky Point reservoir is highly fractured and can rapidly initiate water production, dependent upon both wellbore orientation and fracture network connectivity. Achieving successful zonal isolation is critical to minimize early water production. The arduous task of attaining successful liner cementing practices in high departure and high-angle wells is circumvented by the use of swelling elastomer technology. Additionally, incorporating intelligent well equipment reduces the need for intervention to manage water production because it inherently controls and manages flow rates in each completion interval. Safety in operational strategies is paramount to this operator. Use of remotely operated downhole valves enhances safety by eliminating the hazards typically associated with conventional well intervention operations, such as tubingconveyed perforating and coiled-tubing equipment. Additionally, these downhole flow control valves and monitoring equipment minimize the need for platform personnel to expose themselves to high-pressure wellhead components when making adjustments for well optimization. This paper focuses on the operator s innovative use of advanced completion technologies to lower developmental cost and optimize production rates. Also discussed is the safety provided by the intelligent-well completion systems, which were installed without incident. The three field deployments using swelling elastomer, preperforated liner, and intelligent completion technologies will be discussed along with the initial design, installation objectives, safety attributes, field installation, and performance results. The challenges to deploy these technologies in a highly fractured and highly faulted, complex reservoir will also be presented. Introduction The Rocky Point field, 6 miles northwest of Point Conception (Fig. 1), is a series of complexly faulted anticlines that trend northwest-southeast across OCS tracts P-0451, 452, and 453. Existing platforms Hermosa, Hidalgo, and Harvest are on adjacent leases to the east and south and produce from the Monterey formation in the larger Point Arguello field. Plains Exploration and Production (PXP)-Arguello Inc. is the operator for both Rocky Point and Point Arguello fields. Fig. 1 Rocky Point field location.
2 SPE/IADC 105443 The Rocky Point Unit totals 8,585 acres. The field was discovered in 1982 by the Chevron OCS-P 0451-1 well, and was further delineated by wells 451-2, 452-2, 452-3 and 452-5. An additional exploratory well, Rocky Point B-7, was drilled directionally by Chevron from Platform Hermosa in 1988. The Rocky Point field is smaller than the adjacent Point Arguello field, making it difficult to support the additional expense to construct and install a dedicated platform. Thus, ERD technology was chosen to develop the field from the existing Platform Hidalgo. Additional, benefits derived from use of an existing platform include: 1) an established infrastructure, 2) low environmental impact, 3) production to market sooner, and 4) elimination of additional platforms. Geologic Description of the Rocky Point Field TheRocky Point field, located 6 miles northwest of Point Conception, is a doubly plunging anticline that trends northwest-southeast across OCS tracts P-0451 and P-0452. The anticline is very tightly folded and highly faulted by a series of NW/SE-trending faults (Fig. 2). Production at Rocky Point field is similar to that of Point Arguello field located southwest of Rocky Point (Fig. 3), which produces from the fractured reservoir of the Monterey formation. The main productive formations in the Rocky Point field are the Sisquoc and Monterey. Fig. 2 Point Arguello and Rocky Point fields. Sisquoc Formation. The upper Miocene (Delmontian late Mohnian) Sisquoc formation is generally a continuous depositional sequence of clayey, partly laminated siltstone that grades to a diatomaceous mudstone/claystone. It contains porcelanites and resinous to microsucrosic dolostones. The lower section of Sisquoc grades from mudstone and claystone to laminated, silty, siliceous shale. Interbedded within the shales and mudstones or claystones are increasing amounts of dolostones and porcelanites, with decreasing amounts of siltstone and rare to common occurrences of pyrite. The fractured reservoir of the lower Sisquoc contributes to Rocky Point production. Monterey Formation. The Monterey formation is middle Miocene in age (early Mohnian Luisian). The fractured Monterey is, with the lower Sisquoc, the producing interval in the Rocky Point field The upper Monterey is similar lithologically to the overlying basal Sisquoc, although with an increased fracture density and reservoir quality, but it is more resistive because of increased biogenic content. The upper Monterey is basically banded, laminated, siliceous shale with waxy porcelanites, dolostones, abundant pyrite, and a trace of chert. The lower Monterey becomes even more highly resistive and is characterized by abundant cherts and dolostones interbedded with the laminated siliceous shales and porcelanites. Production Characteristics Rocky Point field produced fluids are similar to the light pool Monterey production at Pt. Arguello field. The reservoir and all overlying formations are normally pressured. The associated gas contains hydrogen sulfide (H 2 S), and the crude ranges from tar to an API gravity of about 30. Oil gravity, H 2 S content, and water/oil contact depth varies between the fault blocks. Typical completions for Rocky Point were expected to be similar to Pt. Arguello. Most of the original Pt. Arguello wells produce by gas lift through a conventionally perforated 7-in. liner and 3½-in. tubing. Most wells are acidized immediately after being perforated. A few Pt. Arguello wells have been completed barefoot, and several wells at platforms Harvest, Hermosa, and Hidalgo have been retrofitted with electric submersible pumps. Drilling Highlights Project planning began with the mechanical feasibility study performed by a recognized leader in ERD well design. This study involved running many well trajectory plans to optimize the wellpath to meet geologic and wellbore intervention objectives. The initial study also identified specific drilling rig design operating specifications as well as meeting seismic design requirements. The fit-for-purpose rig equipment included 1) 750-ton AC top drive, 2) three 1,600-hp mud pumps, 3) 1,800-bbl capacity drilling fluid system, 4) 500-kip setback, and 5) racking capacity of 22,000 ft. of 5½-in. drillpipe. Fig. 3 Top Monterey formation structure map, Rocky Point field.
SPE/IADC 105443 3 Rocky Point Well Design The directional plan was optimized to assist casing running and to avoid rotating the drillstring into the hole. The keys to success were to minimize hold inclination and overall dogleg severity. This required: a) kicking off the well in the 22-in. hole section below the 24-in. structural casing, b) dropping continuously from 16,000 ft measured depth (MD) to total depth (TD), and c) using a rotary steerable tool in the long 12¼-in. hole. The use of the rotary steerable tool also enhanced hole cleaning and increased rate of penetration (ROP) compared to conventional steerable motor systems. The 13 3 / 8 -in. casing was designed to be set at 7,200 ft. MD to maximize the number of axial casing roller centralizers on the 9 5 / 8 -in. casing. An assumption was that rollers are effective only in cased hole. After successful deployment of the 9 5 / 8 -in. casing, the surface pipe of the subsequent well was reduced from 7,200 ft. to 5,500 ft. This was done to reduce the slowerdrilling 17½-in. hole section. The 9 5 / 8 -in. casing is negative weight and was run using a combination of selective flotation (i.e., mud over air) and friction-reducing rollers. Negative weight strings will not slide into the wellbore conventionally. Maximum drillstring torque occurs in the 8½-in. hole and exceeds the API makeup torque for premium class drillpipe. Thus, special high-torque connections were specified for the drillstring. Because of the presence of H 2 S, a special string was used. Supplemental means to reduce torque included friction-reducing mud chemicals, and nonrotating drillpipe protectors were implemented. Equivalent circulating density (ECD) was a critical design issue in the 8½-in. hole due to the naturally fractured reservoir rocks. A tapered drillstring (5½-in. 4-in.), careful control of mud properties, and pressure-while-drilling technology was used to minimize the risk of lost returns. A 7-in. liner was used for the production. The large liner was specified to allow use of intelligent completion equipment. Specialized ERD operating practices pertinent to each hole section were implemented to ensure casing installation went as planned. The distance from the existing platform to the prime bottomhole well locations at Rocky Point made the initial well especially challenging. Proper training of the crew and contractors in ERD-specific operating procedures was crucial. Familiarizing a new crew with the rig and building an effective team was essential. The 24-in. structural casings were set in batch. This served two purposes. First, it allowed the rig crews to get familiar with the new rig and provided extra time for the crew to work together. Secondly, it allowed an economic benefit, because it optimized on specialized equipment needs for drilling and running and cementing the 24-in. structural casings. Initial wellpaths investigated were 1) hold-through zone and 2) drop-through zone, with the final wellpaths as presented in Fig. 4. Each of these paths has advantages and limitations. The wellpath in both cases was a 2D S-turn with upper and lower targets at the top of the pay and at total depth. Key considerations for the final wellpath design were: Use a moderate build- and drop rate (3 /100 ft and 2 /100 ft, respectively) to minimize the possibility of sharp doglegs that could cause problems running the critical casing strings. Kick off in the 22-in. hole near 1,100 ft MD [537 ft Below Mud Line (BML)] to reduce the tangent hold inclination. (This shallow kickoff point has been used on previous wells from this platform.) Minimize the hold angle to maximize the depth to which 13 3 / 8 -in. casing can be run conventionally. Follow a continuous drop plan to reduce the length of curved section that the 9 5 / 8 -in. casing shoe must negotiate at it approaches TD (i.e., finding the hole in curved sections increases drag). Fig. 4 ERD well configuration. A natural drop tendency is typical in these formations beginning in the lower part of the 12¼-in. hole and continuing through the pay zone. This will facilitate the plan to continuously drop angle. Drilling Fluids A seawater-gel mud was used in the 17½-in. hole, which was drilled to a greater measured depth than previous wells from this platform. Hole stability is not normally an issue in this section. However, because of the high angle, a higher mud weight than that used previously (~9.8 lbm/gal) was recommended while drilling the lower portion of the hole and for final cleanup to run casing. A large percentage of hole cleaning in this section is by cuttings dispersion into the mud. High pump rates were, therefore, not as critical for hole cleaning, because the operator would be using a nondispersive mud. A low-toxicity mineral oil base mud (MOBM) was used to drill the 12¼-in. hole sections to ensure hole stability in the water-sensitive shales in the upper Sisquoc formation. Stability was crucial to running the 9 5 / 8 -in. casing successfully. Other benefits of using MOBM include higher sustained penetration rates, longer bit life using polycrystalline diamond compact (PDC) bits, and reduced drillstring torque.
4 SPE/IADC 105443 Use of a MOBM required rig upgrades to provide adequate storage and ensure containment. Also required was careful logistical planning formation cuttings and oily fluid disposal were accomplished by cuttings reinjection because ocean discharge was not permitted in this area for mineral oil or synthetic drilling fluids. Further, onshore disposal was not logistical or an economical alternative. A marginal producing well was converted to a dedicated cuttings injection well. An existing wastewater disposal well was used as a secondary backup well for cuttings injection. This proved valuable in several instances when the cuttings injection well had plugged an required coiled-tubing cleanout intervention. In the initial well, C-12, a minimum-weight polymer drillin-fluid was used on the pay section to provide optimum conditions for mud logging and electric logs. This also minimized the financial risk of lost returns in the naturally fractured pay interval. The C-13 and C-14 wells successfully used an MOBM in the pay zone. Calcium carbonate was added to prevent loses into the fractured formation. Additionally, MOBM had the advantage of reducing the number of mud swaps and eliminating reliance on mechanical devices and mud lubricants to reduce drillstring torque. Completion was performed in filtered seawater, weighted, as required, with salt or concentrated brine with additions of a lubricant to reduce friction, thus allowing easy running of the 4½-in. completion tubing string. Directional Drilling Each well was kicked off in the 22-in. hole section using a conventional steerable motor assembly to drill a 17½-in. pilot hole. The final angle was about 21 at the 18 5/8-in. casing point near 1,600 ft. The shallow kickoff reduces the tangent section hold angle for the well, which facilitates easier running of the 13 3 / 8 -in. and 9 5 / 8 -in. casing strings. A rotary steerable tool was used to drill the entire 17½-in. hole section, which resulted in much smoother build. This significantly reduced torque and drag later in the well (e.g., to successfully run the 13 3 / 8 -in. and 9 5 / 8 -in. strings, to avoid negative-weight drillstring tripping in the 12¼-in. hole, etc.). Using rotary steerable tools will also increase average ROP compared to that with steerable motors. The rotary tool was preferred over a 12¼-in. 17½-in. ream-while-drilling assembly available for this application. The 12¼-in. hole section was drilled with a rotary steerable system to maximize drilling and hole cleaning efficiency. (Slide drilling feasibility becomes marginal in the lower tangent section.) Swell Packers The completion alternatives considered for the Rocky Point Unit (RPU) wells were either a conventional cemented and perforated liner combined with swelling elastomer technology or a slotted or predrilled liner. Historically, Monterey wells have been successfully completed with slotted liners. Typical stimulation technologies applied for Monterey wells have been acid washes using opposed cup wash tools and the bullhead acid technique. This completion technique does not, however, allow zonal isolation, because of slotted liner lengths that can exceed 3,000 ft. As water cut increases, this type of completion is plugged back by pulling the production tubing, setting a cement retainer (either by wireline or tubing conveyed), and then pumping cement. Applying this technique to shut off water is debatable. Based on the operator s limited experience with swelling elastomer technology, the option initially selected for RPU was the conventional cemented and perforated liner. Thus, the first three RPU wells have utilized the conventional completion technique with varying degrees of success. Rocky Point ERD Well Construction The original completion design for the Rocky Point wells was to cement 5½-in. liner in an 8½-in. hole. Running 5½-in. casing allowed for an adequate cement sheath around the pipe, thus increasing the chance of achieving zonal isolation. Several nearby operators have used this type completion liner design. However, the intelligent well downhole hydraulic valves would not fit in that size. These valves require a 7-in. liner. See Fig. 5. Thus, more modeling was required to ensure that the 7-in. liner would be able to run to bottom with the planned friction factors. Torque-and-drag modeling proved that the 7-in. liner would get to bottom. The only concern was the reduced amount of cement sheath around the 7-in. pipe and the increased ECD caused by the reduced annular area. The cementing vendor had designed a fit-for-purpose cement that met the objectives of 1) high compressive strength for perforating and 2) a thin slurry to help reduce ECDs. Fig. 5 Rocky Point well.
SPE/IADC 105443 5 Conventional Cementing All offshore California drilling and completion operation in federal water is regulated by the United States Minerals Management Service (MMS). This agency reviews and approves all drilling and completion applications for the Pacific Outer Continental Shelf. Reviews by the MMS of a well drilling application submitted by the operator can result in significant changes to the initial drilling procedure. One such change was that the operator had to seal the 13 3 / 8 -in. 9 5 / 8 -in. casing annulus with cement. This requirement stems from the many wells in the OCS that have sustained annulus casing pressure between the production casing and surface casing strings. The argument for not cementing the annulus was that this would make it more difficult to cut and retrieve a portion of the 9 5 / 8 -in. casing string to allow redrilling a 12¼in. hole. ECD modeling of the cement pumping indicated that an attempt to bring the cement up and into the 13 3 / 8 -in. 9 5 / 8 - in. annulus would exceed the fracture gradient at the 9 5 / 8 -in. casing shoe. Thus, to meet the MMS requirement, the cementing procedure was modified to include a stage collar set near the 13 3 / 8 -in. casing shoe. Including a stage collar made the procedure more complicated because the 9 5 / 8 -in. casing used the selective floatation technique (mud-over-air) to insure that the casing reached the target depth, thus requiring additional plugs to be pumped down the casing string. The initial RPU well, C-12, used a stage collar to seal the casing annulus. However, there were complications with the firststage wiper plug during displacement of the primary cement job. This resulted in the plug stopping about 300 ft from surface because of a leaking cement head that caused pumping to be shut down several times to repair the leak. Pumping resumed until the wiper plug stopped. Pressure was increased in an attempt to get the plug moving again; however, the pressure required was about equal to the opening pressure of the stage collar. Thus, it was not evident whether the stage collar opened or whether the plug started moving again. Later, it was determined that the stage collar had opened, so it was decided to pump the second stage, which went uneventfully. These unscheduled events resulted in nearly 1,200 ft of cement inside the 9 5 / 8 -in. casing string. Thus, it was evident that an alternative method was needed to satisfy the MMS requirement to seal the 13 3 / 8 -in. 9 5 / 8 -in. casing annulus. One option to seal the annulus was the use of swelling elastomer technology. The concept was to place a 9 5 / 8 -in. swelling packer near the shoe of the 13 3 / 8 -in. surface casing. This was a logical approach because an MOBM system was used to drill the long 12¼-in. tangent hole section. The MOBM system was chosen for RPU development because of both its inhibition properties as well as its lubricity properties. Synthetic oil base mud was not used because it is not approved for overboard discharge in both state and federal waters. Laboratory testing using MOBM was performed by the swelling elastomer vendor to verify swelling times and differential pressure rating of the packer. Fig. 6 shows the results of the laboratory testing. On the basis of the test data, it was decided to use 9 5 / 8 -in. swelling packer to seal the 13 3 / 8 -in. 9 5 / 8 -in. casing annulus on the next well, C-13. This decision eliminated the stage collar to allow for a less complicated cementing operation and allowed a test of swelling packer technology. The swell packer test data was submitted to the MMS for review. On the bais of the laboratory test data, the MMS granted our request to use a swelling packer to seal the annulus. The agency specified that the packer had to be pressured tested to ensure integrity. If the test failed, then the cement had to be pumped down the back side to seal the casing annulus. Fig. 6 Swelling charts. The C-13 swell packer was placed near 5,400 ft. MD (3,500 ft. TVD). The laboratory test data indicated that it would take approximately 30 days for the packer to swell. After 30 days, the casing annulus was successfully tested to 1,500 psi. for 30 min. The successful test gave the operator confidence in swelling elastomer technology and demonstrated that the second phase using a predrilled liner and swell packers for zonal isolation could be attempted. From the demonstrated success with the swelling packer in Well C-13, the operator decided to use another swelling packer in Well C-14. A swelling packer was set near 5,400 ft MD (3,500 ft. TVD) in Well C-14. The only difference between the C-13 and C-14 packer was the set time. The C-14 packer was designed to set in about 12 days. After 12 days, the packer was successfully tested to 1,500 psi for 30 min. On the basis of successful pressure tests of the swell packers in these two wells, the operator s team members thought that trying a predrilled liner and swell packers had merit. The decision to use predrilled liners and swell packers stems from the result of poor 7-in. liner cementing on the initial 3 RPU wells. Production Liner Cementing The initial three RPU wells were conventionally cemented. The C-12 well cement job went as designed. The liner was rotated during the cementing process; however, as expected, rotation was stopped during the displacement process because of the increased rotating torque. Drillpipe-conveyed perforating of over 1,250 ft with five ½-in. holes per foot was completed without incident. A triple-zone intelligent completion system was successfully run. Each zone was selectively acidized using 15% HCL and 12/3 HF acid. The C-13 well was also cemented, however, the displacement wiper plug did not bump and the floats did not
6 SPE/IADC 105443 hold. The liner was rotated during the cementing process. Because of the possible wet shoe, a cement evaluation log was run. The cement log indicated very little cement behind the 7-in. liner, as shown in Fig. 7. A remedial squeeze was needed to provide zonal isolation. The results of the post-squeeze log indicated marginal success of achieving zonal isolation. Drillpipe-conveyed perforating of more than 870 ft with five ½-in. holes per foot was completed without incident. One of the key differences between the C-12, C-13, and C- 14 cementing was that both C-13 and C-14 production intervals were drilled using MOBM. The C-12 well was drilled with a nondamaging polymer drill-in-fluid commonly used in the Monterey formation. The decision to change mud systems was made to eliminate the time and expense of cleaning mud tanks and the time to swap out the MOBM for the water based drill-in-fluid. Fig. 7 Well C-13 below lower perforated interval, cement bond log before and after remedial squeeze. In Well C-14, the 7-in. liner was cemented as well. Again, a cement log was run; the log evaluation indicated poor cement behind the 7-in. liner, thus any chance of achieving zonal isolation was remote. Figs. 8 and 9 show the result of the cement bond log, indicating poor cement bonding. It was necessary to set a retainer and squeeze cement in an attempt to provide isolation between zones. Drillpipe-conveyed perforating of more than 565 ft with five ½-in. holes per foot was completed without incident. On the basis of the results of the squeeze (Figs. 8 and 9), it was decided not to run an intelligent completion in this well. A bullhead acid treatment was performed. Fig. 8 Well C-14 lower squeeze. Fig. 9 Well C-14 upper squeeze. C-14 was sidetracked using a 9 5 / 8 -in. casing whipstock and an 8½-in hole drilled to TD using the MOBM and a PDC drill bit. Given the poor primary cementing history of the initial three wells, the RPU development team members agreed to try running a 7-in. predrilled liner with swelling packers strategically placed in the producing intervals. The well production intervals were separated into three distinct reservoir intervals. Each of these zones was then mechanically separated by the swelling packers. Well C-13 was also sidetracked using a one-trip 9 5 / 8 -in. casing whipstock and an 8½-in hole drilled to TD using the MOBM and a PDC drill bit. This well, too, was completed with a predrilled liner with swelling packers for zonal isolation. The final well, C-15, was drilled using MOBM and completed with predrilled liner and swelling packers for zonal isolation. This well also included sealing of the 13 3 / 8 -in. 9 5 / 8 -in. casing annulus with a swelling packer. Completion Strategy The massive Monterey section can extend for many thousands of feet. This long productive interval makes it difficult to plan a life-of-well completion strategy. Two well completion options considered were: 1) to perforate small intervals and work up the wellbore shutting off water production by plugging back and then reperforating, and 2) to perforate the entire section at one time.
SPE/IADC 105443 7 Swell Packer PXP s ERD program encountered problematic isolation of the 81/2-in. hole section with traditional cementation operations. Conventional cementing products and techniques were extensively discussed and ultimately used with less than successful results. Swell packer technology was evaluated as an alternative solution and proved to be a successful method for the isolation of the 9 5 / 8 -in. casing as well as the 7-in. production liner. Swell packer technology development history have demonstrated the usefulness of the technology to reduce deployment cost and simplification of the well completion construction process. (1) Swell Packer Technology Swell packer technology comprises standard oilfield tubulars with layered rubber chemically bonded along their length. Once exposed to hydrocarbons, the rubber element swells to form an effective annular seal through an absorption process known as thermodynamic absorption. Thermodynamic absorption involves hydrocarbon molecules crosslinking with the rubber molecules. This crosslinkage causes the rubber molecules to stretch. The stretch permits oil to enter the structure, which swells the packer and ensures the packer will remain swollen, unlike less stable polymers. Mere trace amounts of hydrocarbons are sufficient to initiate the thermodynamic absorption process. The wellbore fluid s viscosity and temperature are key variables in determining the time required for the packer to absorb the hydrocarbon and ultimately set. Swelling of the packer is homogenous along the element length. Although the hydrocarbons will not degrade the rubber, they will alter the mechanical properties, reducing the hardness, tensile strength, and Young s modulus. The change in mechanical properties is a function of the volume change of the element. Positive swelling pressure is developed that exceeds the surrounding pressure by a few psi. This swelling pressure is very different from the sealing pressure of the packer. The sealing pressure is the maximum designed pressure differential across the packer element. Packer Types Swell packer elements are chemically bonded to a full tubing/casing joint (30 ft to 40 ft) or a pup joint (10 ft to 20 ft) with various element lengths to accommodate for the required differential pressure across the packer. Slip-on sleeve designs are also available, normally in 12-in. and 3-in. lengths. The slip-on design focus is for low-pressure applications. The core swelling rubber of the swell packer is suitable to run as is in a water-environment well that will ultimately produce oil and set the packer. However, the packer construction for an oil-based mud system normally uses a multilayered design that delays the onset of swelling while the packer is deployed into the well. The packer consists of a high-swelling inner core surrounded by a low-swelling outer layer and a diffusion barrier. The low-swelling outer layer and diffusion barrier can be adjusted to delay the packer set time to coincide with the well installation program. Design, Simulation, Testing, and Deployment The application and design of the swell packer are based on three key variables: the openhole size, required minimum differential pressures across the packer, and the time to seal. Extensive testing on the expansion properties of the elastomer has led to the development of simulators that can predict the expansion ratio, differential pressure capability, and time to seal for a given base pipe and outer diameter. These simulators are used to design and size a packer for a given application and are key to proper design. The final hole size must be considered carefully in the design phase to ensure that the swell packer is sized correctly to fill the annular space and sustain the required differential pressure. A key feature of the swell packer is its ease of deployment. With no moving parts, downhole activation, or surface equipment required, the packer is simply made up as part of the completion or casing string and deployed as a single-trip assembly. Additionally, the simplistic deployment of the swell packer negates the requirement for service technicians. Intelligent Completion Objectives As a part of the development of the Rocky Point project, PXP considered completion alternatives for the Rocky Point field reservoir. In May 2003, before beginning the drilling project, an initial front-end engineering and design (FEED) study was performed to evaluate completion system options. On the basis of available data, it was clear that there was a high degree of uncertainty in the overall recovery expected, rates attainable, pressure support available, time to first water breakthrough, and in how quickly the water cut develops and how this impacts the economics. The FEED study focused on maximizing early and ultimate recovery while minimizing the potential for early water breakthrough in this highly fractured, strong-water-drive reservoir. The design incorporated a long-reach horizontal arm in thoroughly isolated multiple zones with selective control of water breakthrough by zone, either by shutoff or zonal pressure control. The FEED study concentrated on minimizing total costs for the life of the well, including reducing or eliminating intervention costs, while maintaining the ability to control water production and to provide adequate means of isolation between producing zones. Other concerns were: Reliable design to afford required longevity and minimize total life-of-well costs. Minimizing risk exposure associated with completion technology new to the Rocky Point asset. Evaluating zonal productivity for future development. Providing an easy-to-install-and-operate reliable completion that would ensure zonal isolation. Minimizing the topside footprint. Managing H 2 S. Maximizing commingled production while controlling water production. Knowledge of valve position.
8 SPE/IADC 105443 At the design stage, the engineering service provider evaluated completion alternatives that could achieve the production and reservoir expectations of the operator. The first triple-zone intelligent completions ever installed off the U.S. west coast are up and running in three of the Rocky Point field ERD wells. Intelligent completion systems provide the ability to remotely choke or shut off offending zones to yield an immediate response on the well performance without any well intervention or workover. PXP s intelligent completions have enabled the production of up to four zones in a triple-zone configuration, thus allowing real-time production allocation and monitoring without the need for intervention (Fig. 10). The three zones were controlled by 3½-in. tubingretrievable flow control valves. The valves range from open/close to multiposition valves and allow dedicated monitoring of pressure and temperature. The valves were positioned at the level of each reservoir, and isolated by means of 7-in. 3½-in. multiple-port packers. Intelligent Completion Design Four zones were completed in each of the Hidalgo platform wells with three premium multiple-port retrievable packers. The packer used was a tubing-conveyed, hydraulicset, retrievable packer designed for intelligent completions. It features a multiple-bypass configuration for hydraulic control line or electric conduit applications. Because the lower-zone holds both the highest productivity potential and highest probability of water production, it was isolated with the lower isolation packer in the 7-in. liner. A custom-designed, multiposition, tubing-retrievable hydraulic variable valve was used to control water production and reduce coning, thus increasing reservoir sweep. This multiposition flow control valve was sized to allow for the maximum production rates. The annular tubing-retrievable flow control valve provides remotely actuated downhole control of reservoir flow in intelligent completions. Communication with the hydraulic, tubing-retrievable control valve is maintained through a dedicated, single 0.25-in. hydraulic capillary tube that controls the choke section of the tool. The valve is adaptable to control of flow on incremental adjustments by its integral choke. The valve enables 11 positions for reservoir control, (1 fully closed and 10 choke positions). The flow area is equivalent to the tubing string flow area The middle zones were commingled below a 7-in. isolation packer, and upper zones were commingled below the 7-in. production packer. Each of these zones is producing through open/close tubing-retrievable hydraulic valves for water control. The open/close, hydraulic, tubing-retrievable control valves for both the upper and middle zones enable two positions fully open or fully closed. The valve consists of a dual hydraulic-acting piston actuated by two hydraulic control lines for operation. In other wells, the valve configuration included multiposition tubing-retrievable flow control valves for all the three producing zones. A 4½-in. chemical injection mandrel, a series of 4½-in. gas-lift mandrels with 1½-in. gas-lift valves, and a 4½-in. tubing-retrievable safety valve were installed above the top packer. Fig. 10 Intelligent well completion deployment. The chemical injection mandrel provides the ability to inject chemicals (emulsion inhibitors and/or scale inhibitors) through a 3/8-in. hydraulic control line close to the top of the
SPE/IADC 105443 9 production packer. This chemical injection system uses a onepiece, corrosion-resistant, eccentrically machined body that provides fully enclosed dual-check valves and an optional rupture disk The tubing-retrievable, surface-controlled, subsurface safety valve features a rod-piston actuation, metal-to-metal seal body joints, a rugged flapper-closure mechanism, and a minimum number of critical seals to ensure maximum reliability. The wells are cased with 9 5 / 8 -in., 43.5-lbm casing to an average depth of 18,000 ft. MD. The 7-in. liner is hung off of a hydraulic set liner hanger and liner top packer. A tapered 4½-in. to 3½-in. production tubing string was run to maintain completion strength while allowing for optimal gas lift efficiency. High-shot-density (5 spf) perforating was used to ensure coverage in the highly laminated formations. The well was perforated by tubing-conveyed perforating in a single trip and then killed before pulling the perforation string. Formation damage caused by killing the well after perforating was not considered a significant factor in these highly fractured formations, especially using deep-penetrating charges. The production permanent gauge monitoring system includes a single permanent quartz pressure/temperature gauge in each interval below each packer. Three gauges are connected using a single gauge line. These gauges can be used for: Reservoir pressure monitoring. Wellbore lift optimization. Productivity measurement and back allocation. Monitoring and variable control of the lower-zone to reduce/delay water production. Individual zone transient testing while minimizing wellbore storage effects. Vertical interference testing. The monitoring system provides a permanent measurement of the flowing or static bottomhole pressure and the corresponding temperature. The gauges are mounted on a rugged tubing mandrel which is run downhole with the intelligent completion string during the well completion. The mandrel enables the measurement of the pressure inside or outside the tubing. The Rocky Point gauges consist of a pressure-sensing element associated with electronic circuits that convert pressure and temperature to an electronic digital signal. This signal is transmitted to surface through a single-conductor electric cable that is also used to send constant current power downhole to the gauge. During completion operations a multiline spooling system was used to run the multiple hydraulic and electric lines. The system included an electric line for the permanent gauges, four hydraulic lines for the control of the three tubing-retrievable flow control valves, one dedicated line for the chemical injection mandrel and one more for the surface controlled safety valve, for a total of seven control lines. (Fig. 11). Pressure, temperature, and valve position data are acquired and stored on a dedicated personal computer and periodically backed up on the platform server. Fig. 11 Multiline system during operations. As each well was completed, stimulation was limited to acid treatments bullheaded from the surface through the tubulars. The flow path from each zone is through a dedicated hydraulic, tubing-retrievable control valve into common 3½-in. tubing. Commingled flow moves through the top multiple-port production packer into the 4½-in. tubing to surface. The operator installed the first and fully integrated surface hydraulic control system and remote manifold for control and manipulation of each hydraulic line. This system can manage up to 15 hydraulic lines from surface Valve choking will be used to control the flowing bottomhole pressure at the sandface of zones producing water, thus limiting the drawdown at the sandface and delaying water production. This will increase oil production from the zones not yet producing water. This valve was sized according to the initial reservoir model to suit emerging reservoir conditions. Its performance is being optimized to production and reservoir management objectives by modeling the ongoing data provided by the wells instrumentation. These data include inlet pressure, tubing hydrostatic pressure, flowing bottomhole pressure, static reservoir pressure, downhole temperature, zonal flow rate, and fluid characterization. Completion Results The initial well in the Rocky Point structure, Well C-12, in which 7-in. casing was cemented in 8½-in open hole, was perforated using tubing-conveyed guns run on drillpipe and was completed initially with a conventional gas lift completion using 4½-in. tubing to the top of the liner and 3½in. tubing inside the liner with a hydraulic-set packer. No cement evaluation logs were run, and the available intelligent well completion equipment was not used initially in an effort to hasten first production from the field. The well was fitted with a 3/8 in. chemical injection capillary and chemical injection mandrel below the lower-most gas lift mandrel for the application of a viscosity reducer and/or corrosion inhibitor. Design alternatives were considered for the production tubing because of the presence of significant concentrations of H 2 S in the nearby Point Arguello and Point Pedernales fields
10 SPE/IADC 105443 as well as evidence of H 2 S from a drillstem test in the Rocky Point structure. The entire 1,250-ft perforated interval was bullheaded with 15% HCl and 12/3 HF acid, including stages of nitrified polymer slugs for diversion. Water breakthrough began almost immediately. It was decided that, after drilling the second well (C-13), the rig would be used to pull the existing C-12 completion and run the intelligent completion equipment in lieu of running a production log suite because of the costs associated with using coiled tubing to log the high-angle hole. Approximately 3 months after initial production from C- 12, the tubing was pulled and the intelligent completion equipment was run to separate the completed interval into three zones. A series of zonal production tests were conducted before performing a second acid stimulation that used the intelligent completion for positive diversion. Fig. 12 is a screen dump from the onboard data acquisition system illustrating the bottomhole pressures during the second stimulation in which the lower interval was first to be stimulated, then the middle, and finally the upper. As can be seen, upon initiation of pumping the lower-zone stimulation, there is a slight increase on the upper-zone pressure gauge, but none on the middle-zone, possibly indicating a slight leak in the intelligent completion valve. Near the end of the lower-zone stimulation, there is a noticeable increase in pressure in the upper interval and, again, near the end of the middle-zone stimulation. There is also a pressure rise in the lower-zone near the end of the middlezone stimulation indicating communication behind pipe, which is further cleaned up during the upper-zone stimulation. It can be seen that all three zones are recording stimulation pressure with only the hydrostatic differential because of vertical depth separation. Efforts to isolate the water production with manipulation of the intelligent completion zone valves proved unsuccessful owing to behindpipe communication. of the completed interval. Fig. 13 is a plot of bottomhole zonal pressures for the initial acid stimulation of C-13. Pressure C-13 Initial Completion Stimulation - Downhole Pressures 1/5/05 Lower Zone Middle Zone Upper Zone Fig 13 Well C-13 bottomhole zonal pressure. As can be seen, upon initiating the lower-zone acid treatment, there is an immediate reaction on the middle-zone pressure that indicates communication. The upper-zone is unaffected by pumping on the lower or middle zone, thus indicating good zonal isolation. The communication between the lower two intervals was found, after pulling the completion and running cement evaluation logs, to be caused by poor cement bond. Zonal tests indicated that the upperzone was dry oil production, but with the communication between the lower zones, manipulation of the lower-zone choking valve or of the middle-zone on/off valve did little to inhibit water production. It was decided to pull the completion, run cement evaluation logs, squeeze cement, and re-run the intelligent completion equipment. Fig. 14 is a plot of bottomhole zonal pressure vs. time immediately after the workover to squeeze cement. C-13 Post Workover BHP Acid Job Zonal Testing pressure - psia Fig. 12 Bottomhole zonal pressure data during well stimulation. The second well in the Rocky Point field, C-13, was again 7-in. casing cemented in 8½-in open hole, but was initially completed with the intelligent completion equipment. Upon initial downhole-gauge data acquisition, it was apparent that there was communication between the lower and middle zones C-13 Lower C-13 Middle C-13 Upper Fig. 14 Well C-13 bottomhole zonal pressure vs. time after cement squeeze. As illustrated, the cement squeeze was successful in achieving zonal isolation, but water production increased over time. The well was eventually sidetracked utilizing the intelligent completion equipment in conjunction with
SPE/IADC 105443 11 preperforated casing and swelling elastomer packers as opposed to conventional cemented casing for the completion. The final three wells drilled in the Rocky Point field were completed with 7-in. casing preperforated with ten ½-in. diameter holes per foot fitted with swelling elastomer packers (swell packers) as shown in previous diagrams. Well C-14ST was completed with a conventional gas-lift string, and not the intelligent well equipment. Wells C-13ST and C-15 were completed with the intelligent well equipment. From initial completion through the current time, both C-13ST and C-15 have exhibited positive zonal isolation. Fig. 15 is a plot of zonal bottomhole pressures during the initial acid stimulation of C-13ST. production as well as an increase in oil production from increased drawdown on the middle-zone. Although the upper interval experiences interference from well C-14ST; overall, oil production from the field is maximized with the upper interval open in both wells (Point D ). Long-term positive isolation of the lower-zone water production is evidenced with its continued pressure buildup over time (Point E ). C C-13ST Lower Zone shut in E 3000 2500 C-13ST INITIAL ACID STIMULATION - ZONAL BOTTOM HOLE PRESSURES A 2000 Pressure - psi Upper Zone closed B D BPD 1500 1000 Pressure - psi Upper Zone opened again 500 0 Perfect Zonal Isolation UPPER psi MID psi LOWER psi BOPD BWPD Fig. 16 Liquid production rate and zonal bottomhole pressures vs. time after acid stimulation of C-13ST. UPPER psi MID psi LOWER psi Fig. 15 Well C-13ST bottomhole zonal pressures during acid stimulation. It can be clearly seen that each interval is hydraulically separated from the other two during the acid stimulation using the intelligent valves for positive acid diversion. Furthermore, subsequent zonal production testing indicated dry oil production from the upper and middle interval with nearly all the water production coming from the lowermost interval. Shutting in the lower valve resulted in immediate and positive anomalous water production shutoff, which continues to hold to the present time. Fig. 16 is a plot of liquid production rate and zonal bottomhole pressures vs. time for a one-month period following the initial acid stimulation of C-13ST. The advantages of intelligent well equipment coupled with competent zonal isolation provided by the swell packer application become obvious upon analyzing data in Fig. 16. Upon initial downhole-gauge data acquisition from C-13ST, the upper interval pressure was significantly lower than the expected pressure (Point A on the plot). During the acid stimulation of the upper interval, a production increase was observed in the nearby well C-14ST with extremely low ph. This indicated direct communication between the two wells, with the lower pressure related to drainage from C-14ST. This is later illustrated by a pressure drop in the upper interval of C-13ST upon closure of the upper valve (Point B ), which indicates crossflow from the lower intervals to the relatively depleted upper-zone. In addition, periods of downtime on C- 14ST are immediately evidenced as a pressure spike on the shut-in upper-zone in C-13ST (Points C ). Complete control of each producing interval in C-13ST is evident upon shut-in of the lower-zone, which results in a dramatic drop in water Fig. 17 is a plot of bottomhole pressures vs. time for Well C-15. psia Shut in Lower Interval C-15 BHP Plot Excellent zonal isolation provided by swelling elastomers Shut in Middle Interval Open Lower Interval Upper Psia Middle Psia Lower Psia Fig 17 Well C-15 bottomhole pressure vs. time. Here again, positive zonal isolation is demonstrated from the pre-acid stimulation zonal tests, through the initial acid job, post-acid zonal tests, and throughout the production history to date. Additionally, the pre- and post-acid treatment zonal testing in the middle and lower intervals, in conjunction with the intelligent well completion equipment, provided excellent drawdown and buildup data with minimal wellbore storage affect with which to perform pressure transient analyses. The analyses where used to confirm acid treatment efficacy, and additional testing is planned to ascertain reservoir limits. Project Management Approach The operating company has taken a long-term, life-of-the-field perspective in developing and managing its Rocky Point asset.