Swellpacker Technology Bests Zonal Isolation Challenge in High-Pressure Wells

Transcription

1 E A S Y W E L L Swellpacker Technology Bests Zonal Isolation Challenge in High-Pressure Wells R e d Te c h PA P E R Part of the RedTech Learning Series O c t o b e r HALLIBURTON

2 E A S Y W E L L Industry Challenge The field to be developed contains several reservoirs that share the general features of being deep, highly pressured and sour. Reservoir simulations for a major Middle Eastern Operator s first EOR project in southern Oman indicate a significant increase in recovery can be achieved, but only by successfully isolating gas and water in the event that either or both breaks through prematurely to producing wells from the miscible gas injection wells. To obtain the additional reserves, zonal isolation is required, however, conventional cementing techniques have proven unsatisfactory. Cement bond logs run in every well showed in practically every case that a microannulus conductive to reservoir fluids had been created, preventing zonal isolation. Innovative cementing techniques to increase the probability of reliable zonal isolation and minimize expensive workover operations are required. Halliburton Solution Combining oil-swellable elastomer technology (Halliburton s Swellpacker isolation system) with a primary cementing job provides an effective means of addressing microannulus concerns and incomplete cement sheath issues. This is a technically viable option to meet the EOR project s stringent zonal isolation requirements in the event the cement debonds from the casing and hydrocarbons attempt to flow through the microannulus. Instead of the hydrocarbons conducting, they instead activate the swellable elastomer upon contact; because the swelling rubber element can conform to almost any irregular geometry, it can swell to close the microannulus and thus reestablish the hydraulic seal required. To ensure an effective annular seal between multiple reservoir layers, the Swellpacker isolation system can be installed as part of the production liner. It can also act as a backup in the event that a microannulus is created at the cement/liner interface. Operator Results The Middle East field to be developed consists of nine reservoirs, each with distinct characteristics. In general, the reservoirs are deep and highly pressured and they contain sour, light hydrocarbons. More than 50 wells have been drilled in and around these fields. The initial wells have a shallow 13-3/8-in surface casing, a long 9-5/8-in production casing and a cemented 7-in liner over the reservoir section. They are completed with 3½-in tubing and some have a permanent downhole pressure gauge. HAL9422 1

3 The cluster is being developed in three phases. The objective of Phase 1 was to determine from a number of data sources whether a miscible gas injection project would be feasible in some fields. Phase 2 will involve primary depletion in a number of fields followed by gas injection in some of them. Phase 3 will involve formation-wide depletion and gas injection in the remaining fields. To maximize ultimate recovery from these fields, gas (and water) shutoff is required during Phase 2 and Phase 3 of the project. Therefore zonal isolation over the reservoir is essential. A substantial effort was made during Phase 1 to determine whether zonal isolation was being achieved using conventional cementing techniques. Cement bond logs were run in every well over the liner section to determine the quality of cement. These logs showed in practically every case that a microannulus had been created. During well completion, cement from the production liner debonded because of differential pressure, leading to the creation of a microannulus. Subsequently, the cement cannot re-seal and a permanent flow path between cement and production liner may arise, preventing zonal isolation. Selective perforating during the well testing campaign showed that this microannulus was conductive to reservoir fluids. In one incident, reservoir fluids leaked all the way to surface, providing further evidence of inadequate zonal isolation. Expandable pipe was not a technically feasible option owing to the presence of high levels of hydrogen sulfide. A focused effort was initiated to find an improvement over conventional cementing techniques, and attention settled on the Swellpacker isolation system. Laboratory testing To determine if the Swellpacker isolation system would be able to withstand the anticipated differential pressure levels in the various reservoirs, laboratory testing preceded a field trial. Testing aimed to verify the cement assurance principle of the Swellpacker isolation system with a 2-m-long, 4.82-in outer diameter (OD) rubber element on a 4.5-in OD base pipe placed in a 4-m-long, 6.1-in OD autoclave. The sealing ability of the Swellpacker isolation system was tested by introducing a microannulus on one side (90 ) and allowing the rubber element to swell and seal off the annulus by flowing hydrocarbons through it. The pressure test was aborted at 300 bar (maximum pressure rating of the test unit) and the Swellpacker isolation system was able to hold the differential pressure with no detected leak. The system proved to be effective in sealing off a simulated microannulus between the cement and pipe interface and could withstand a differential pressure in excess of 300 bar. The test also demonstrated that the Swellpacker isolation system sealed off irregular surfaces at the cement edge. These results provided confidence that the Swellpacker isolation system can effectively seal off a microannulus that develops downhole between the pipe and cement interface for example, as the result of operations during well construction. Field trial It was therefore decided to run a field trial of the combination of a cement slurry with the Swellpacker isolation system. The objective of the production test was to expose the Swellpacker isolation system to oil and then to measure changes in flow rate, fluid composition and static pressure. The critical parameters to be tested were as follows: 2

4 ability to mechanically install Swellpacker systems ability of Swellpacker systems to withstand required pressure differentials after expansion under production conditions ability of Swellpacker systems to maintain zonal isolation. The trial well was drilled in November 2005 as a vertical production well on the western flank of the target Schematic Showing Typical Response of Cement Bond Logs in Phase 1 Wells carbonate reservoir. The reservoir from which the trial well was producing was considered a direct analog and was operated under a pressure maintenance scheme with highpressure gas injection on the crest of the structure. The reservoir consists of three main units within a 50-m-thick gross interval: an upper Unit 1 that is poorly developed and possibly gassed out in this part of the field, a middle Unit 2 ( % porosity) that is generally tight and the lower main producing Unit 3 (11.5% average porosity, 90% hydrocarbon saturation). It was decided to install 3-m-long Swellpacker isolation system at the top and bottom of the poor-quality reservoir section (Unit 2). An additional Swellpacker system was run Schematic Showing Consequence of Poor Cementing between this reservoir section and an underlying higherpressured reservoir to isolate the two formations. The intent was to selectively perforate 5 m of Unit 2. The test procedure was set up to produce from the interval between the upper two Swellpacker isolation systems with maximum pressure drawdown and to evaluate the annular isolation provided by the Swellpacker isolation systems from either of the more productive upper or lower zones. The main indicators were flow performance and fluid composition. For example, if annulus flow from the more Schematic of the Test Well Showing Swell Packer Locations in Relation to Reservoir Units productive zones was occurring, then an initial high flow rate followed by a decline could indicate the Swellpacker isolation systems were swelling and sealing the annulus. Alternately, if the produced fluid composition changed with time or was different between zones, then annular isolation could be assumed. 3

5 Swellpacker isolation systems were installed as an integral part of the cemented liner completion; they were positioned across Unit 2 at depths of 2911 m and 2919 m. Each Swellpacker isolation system element is 3 m long, 5.5-in OD (before swelling) and mounted on a 4½-in casing joint. The openhole diameter in the reservoir section is 8-3/8 in. Swellpacker isolation systems were positioned approximately 5 m from the expected main productive intervals in Unit 1 and Unit 3. A third Swellpacker isolation system, placed in the completion near the bottom of the reservoir to provide annular isolation from the higher-pressured and potentially water-bearing, deeper reservoir, did not form part of the test design. The production liner with the Swellpacker isolation systems was hung off in the 9-5/8-in casing and cemented. The liner was rotated while cementing with no losses reported. The cement bond log indicated good cement coverage across all low-porosity zones and potentially poor coverage across high-porosity sections in the main reservoir zone in Unit 3. The cement bond log showed 4 m of good cement coverage below the middle Swellpacker system to the top of the expected productive zones in Unit 3 in addition to good cement coverage above the upper Swellpacker isolation system and across Unit 1. The combination of Swellpacker isolation systems and cement achieved zonal isolation in all three zones as indicated by selective perforating, wireline logging and production testing. This is the first time that zonal isolation has been observed in these challenging, high-pressure and sour wells. Operator Benefits After perforation, stimulation and cleanup, a stable flow rate of 345 m3/d oil (150 m3/m3 gas/oil ratio) at 6000 kpa of flowing tubing head pressure was achieved from the two perforated intervals. A production profile log shows that the majority of oil production is from the Unit 3 perforations (96%) with only 14 m3/d (4%) from the Unit 2 perforations. Productivity from the Unit 3 zone was as expected. The following conclusions about zonal isolation success can be drawn from these field tests: Production test results from Unit 2 perforations indicate flow performance as expected for a Unit 2 formation. The production test indicates no communication with the more productive Unit 3 zone, even under high drawdown conditions. The low gas/oil ratio fluid composition from Unit 2 perforations indicates no communication with possible high gas/oil ratio zones in Unit 1. The production tests show good annulus isolation between Unit 2 and Unit 3 perforations. In summary, zonal isolation is crucial to the future success of the miscible gas injection project planned for the reservoirs in the field to be produced. Previous attempts using conventional cementing technology alone have so far been unsuccessful. Based on results obtained from both laboratory and field tests, the oil-swellable elastomer technology of the Swellpacker isolation system in combination with cement have demonstrated zonal isolation for the first time in these challenging high-pressure reservoirs. This discovery could enable a significant increase in reserves from these fields. Swellpacker Technology The Swellpacker isolation system employs standard oilfield tubulars with rubber layers chemically bonded along their length. The rubber element swells upon exposure to hydrocarbons to form an effective annular seal through a process known as diffusion, which occurs as hydrocarbon molecules are absorbed by the rubber molecules and cause 4

6 them to stretch. The oil enters the rubber, which swells the packer and ensures that it will remain swollen, unlike water swelling systems which can shrink due to the effect of the osmosis process being reversible. 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 Swellpacker system to absorb hydrocarbon and ultimately to set. Swelling of the packer is consistent along its length. Although hydrocarbons will not degrade the rubber, they will alter its mechanical properties, such as hardness and tensile strength, depending on the rubber s volume increase. Swellpacker elements are chemically bonded to a tubing or casing joint with element lengths tailored to accommodate the desired differential pressure. Slip-on sleeve designs are also available, normally in 12-in and 3-ft lengths, but for low-pressure applications. Thousands of Swellpacker systems have been run in numerous wells worldwide for a variety of applications, including zonal isolation across the reservoir as a substitute for cement and providing backup should the liner cementation prove unsuccessful. This Halliburton white paper is a summary of SPE PDO s Proactive Approach to Solving a Zonal Isolation Challenge in Harweel HP Wells Using Swell Packers by M.S. Laws, J.E. Fraser, and H.F. Soek, Petroleum Development Oman, and N. Carter, Easywell (now with Sensornet Ltd.); paper presented at the 2006 IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Bangkok, Thailand, November. Sales of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale. Biblio # 10/ Halliburton. All Rights Reserved. HALLIBURTON