Water-Alternating-Steam Process Improves Project Economics at West Coalinga Field
- K.C. Hong (Chevron Oil Field Research Co.) | C.E. Stevens (Chevron U.S.A. Production Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- November 1992
- Document Type
- Journal Paper
- 407 - 413
- 1992. Society of Petroleum Engineers
- 5.4.6 Thermal Methods, 6.5.2 Water use, produced water discharge and disposal, 7.1.9 Project Economic Analysis, 5.8.5 Oil Sand, Oil Shale, Bitumen, 5.3.2 Multiphase Flow, 5.4 Enhanced Recovery, 5.4.1 Waterflooding, 7.1.10 Field Economic Analysis, 5.5 Reservoir Simulation, 4.1.5 Processing Equipment, 5.8.7 Carbonate Reservoir, 2.4.3 Sand/Solids Control, 4.1.2 Separation and Treating, 4.2 Pipelines, Flowlines and Risers, 2.5.2 Fracturing Materials (Fluids, Proppant)
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The water-alternating-steam process (WASP) was applied to vertical expansion(VE) sands in the pilot area of Section 13D, West Coalinga field to stopwasteful steam production and to improve vertical conformance of injectedsteam. Before the WASP application, steam breakthrough in the VE sands causedwell sanding, cutting of downhole tubulars, and high-temperature-fluid handlingproblems. To alleviate these problems, pumps had to be raised in five wells andone well had to be shut in, reducing oil production from the VE sands and thelower waterflooded zones. A production from the VE sands and the lowerwaterflooded zones. A WASP field test, based on a numerical simulation study,was implemented in July 1988 with alternating slugs of water and steam, eachinjected over 4 months. The WASP eliminated steam production, allowing thepumps to be lowered and the one shut-in well to return to production. Oilproduction remained constant through the first WASP cycle and increased duringthe second cycle. Sales oil (total production minus oil used to generate steam)increased as a result production minus oil used to generate steam) increased asa result of saving generator fuel during the water leg of each WASP cycle,resulting in improved project economics.
Steam injection was first used in the late 1950's to recover high-viscosityoils. This EOR method has become increasingly popular during the past 30 yearsand now accounts for more than 1 million B/D of oil production worldwide, abouthalf coming from heavy-oil fields in the U.S.
Despite the success of steam in improving the recovery of viscous oils.characteristic problems are associated with its use: steam gravity override andsteam channeling. Steam gravity override. resulting from the large densitydifference between the injected steam and in-situ fluids. reduces reservoirvertical conformance and leads to early steam breakthrough at production wells.If high-permeability channels are present in the reservoir, steam can propagatethrough them, also leading to early steam breakthrough and poor verticalconformance. These events are undesirable because they reduce the ultimatesteamflood oil recovery and cause such well production problems as sanding,cutting of downhole tubulars, and high-temperature fluids in the wellbore.
Several methods to combat the steam breakthrough and reservoir conformanceproblems currently are in use or being field-tested. One method involves theuse of surfactants to form steam foams in situ that reduce steam mobility andcontrol injection profiles. While field tests of this method reported technicalsuccess in improving the vertical conformance, few claimed economic success.Additional research and field tests are needed before this method can be usedcommercially.
Converting from steamflood to waterflood when the steamflood shows signs ofmaturity (e.g., high monthly steam/oil ratio and large steam production) isanother method used to combat the reservoir conformance problem. This method,however, has been used almost exclusively to terminate a steamflood project atthe end of its life. One exception to this was reported in the Okha and Usafields of the former Soviet Union, where a predetermined slug of steam wasfollowed by water for optimum use of the injected heat, rather than toterminate a steamflood project. In this method, however, the steam-to-waterconversion takes place late in the life of a project and only one cycle ofsteam and water injection is used; therefore, the method is unsuitable fortreating problems of early steam breakthrough and poor reservoir conformance.WASP was conceived to treat these problems. This paper describes a successfulapplication of the new technology.
Process Concept Process Concept WASP is analogous to thewater-alternating-gas (WAG) process used for gasfloods in that two fluids withwidely different densities are injected alternately over more than one cycle.This method of injection reduces gravity override and channeling tendencies ofthe gas phase, thereby improving the reservoir vertical conformance. One maindifference between WASP and WAG is that the gas phase in WASP is condensableand at a much higher temperature than the liquid phase.
Fig. 1 illustrates schematically how WASP might work in contrast to acontinuous steam-injection process. With the latter, steam gravity overridesthe formation and breaks through to the production well relatively early in thelife of an injection production well relatively early in the life of aninjection project. WASP, on the other hand. eliminates steam breakthroughproject. WASP, on the other hand. eliminates steam breakthrough because waterinjected after steam causes the steam zone to collapse while tending tounderrun the reservoir. As a result, more vertical thermal fronts areformed.
At the microscopic level, oil flows from the bypassed zones to the heatedpath as the steam zone collapses. Upon conversion back to steam injection, thisoil is displaced forward. Repetitive injection of steam and water slugs thusleads to good vertical sweep and improved oil recovery.
Other benefits envisioned of WASP include (1) improved areal conformance andreduced steam channeling, (2) reduced fuel consumption, (3) reduced wellboreheat loss, (4) accelerated production and increased ultimate recovery, and (5)provision of a production and increased ultimate recovery, and (5) provision ofa definite indication of the best time to go to continuous water injection if awater-after-steam process is desired. Benefits 2 and 3 are possible because,with WASP, steam is injected for only half the time required for continuoussteam injection.
Pilot History Pilot History WASP was first applied to a pilot area inSection 13D, West Coalinga field, in the San Joaquin Valley, CA. Figs. 2 and 3show the locations of the field and the steamflood patterns in Section 13D,respectively. The Section 13D steamflood began in 1973 with the 32-acre,six-pattern pilot shown in Fig. 3. After 3 years of steam injection in thepilot area, the project was areally expanded to Phases 1, 2, and 3. Phases 1,2, and 3. Steam was injected into the three lowermost sands (Sands H, J, andJv) of the Temblor formation, which contains a multitude of suitable steamfloodtargets, as shown in the type log of Fig. 4. In 1984, after 11 years of steaminjection, the steamflood in these sands showed signs of maturity: high monthlysteam/oil ratios and high flowline temperatures. Temperature surveys conductedin shut-in producers and observation wells revealed steam-zone temperatures inthe 300 to 400F range. Thus, after a thorough engineering review, these sandswere converted to waterflood in April 1984.
The temperature surveys also revealed temperatures as high as 240F in SandG, which lies immediately above steamflooded Sand H.
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