Guntis Moritis
Drilling/Production Editor
Oil production from CO2 and low-molecular-weight hydrocarbon miscible/immiscible (HC) gas injection projects is rapidly increasing in the U.S., as,,the Journal's exclusive worldwide survey in this issue shows.
Since OGJ's previous worldwide biennial EOR survey in 1988 (covering the situation at the beginning of 1988), enhanced oil production has more than doubled from HC projects and increased by 49% from CO2 projects (Table 1).
Total enhanced oil production in the U.S. at the start of 1990 was 656,700 bo/d or a 6.2% increase over the same period in 1988. The accompanying box with block diagram defines EOR processes covered in the alphabetical tables in this report. An indexed list of these tables and the abbreviations used are also covered in accompanying boxes.
Worldwide there has been little increase in EOR output although the survey shows an increase of 11.5% to some 1.2 million bo/d. This increase is misleading because the data for two large projects, the Duri field steamflood in Indonesia and the Intisar 103D field HC miscible project in Libya, were not included in the 1988 survey. The former came in too late and the latter was inadvertently left out.
After taking into account the 115,000 bo/d these two projects were producing at the start of 1088, the actual worldwide enhanced oil production has remained virtually the same with only a 0.1% increase.
A contact at the U.S.S.R.'s All-Union Scientific Research Oil & Gas Institute in Moscow says the Soviet Union has a large number of EOR projects scattered from Sakhalin Island in the east to the Ukraine in the west, and from the polar circle in the north to Azerbaijan in the south. He says that the U.S.S.R. does have active thermal, gaseous, chemical, and microbiological projects. He says there was not enough time to furnish details on each by this year's deadline for the survey. A total EOR production figure was also apparently not available.
This year's survey reveals that the more expensive enhanced oil recovery processes that involve chemical injection have experienced a dramatic decrease in the U.S. The number of projects with chemical EOR at the beginning of 1990 had dropped to 50 from the 124 projects at the beginning of 1988 (Table 2).
Likewise, production from chemical projects has been halved to 11,856 bo/d from 22,501 bo/d in 1988. Observers say that the high cost of chemicals in most cases put these projects in jeopardy. Also the demise of the federal windfall profits tax took away the incentive for maintaining some such projects.
HEAVY OIL
The 1990 survey also includes a look at heavy oil projects (Table L). The definition we used for heavy oil fields are those that could not be produced through conventional primary or secondary means, and were not mining projects.
All responses on active projects came from Canada and include 19 fields producing a total of 115,007 bo/d. The largest by far is Esso Resources Canada Ltd.'s Cold Lake cyclic steam stimulation. The project started in 1964 and involves 1,200 wells. Current production is 88,060 bo/d.
For 1990, eight projects are slated for start-up (Table M). Two are in the U.S., and the others are in Canada. Planned investment is $51 million.
INTERNATIONAL
The most noteworthy international project has been the continued expansion of the Duri, Indonesia, steamflood. P.T. Caltex Pacific Indonesia operates the project under a production-sharing contract with the Indonesian state oil company, Pertamina.
Earlier this year, Duri became the largest EOR project in terms of daily production in the world, surpassing the production rate from the Kern River field in California. Steam injection in Duri started in 1985.
The current total production rate in Duri is about 160,000 bo/d, or 15,000 bo/d more than shown in our tabulation. The cut off date for our survey was the end of 1989.
A peak production of 330,000 bo/d is expected in Duri by 1993.
About 20% of this oil will be burned to generate steam for injection.
Ultimate tertiary recovery from this $1.8 billion project is estimated to be 2 billion bbl of oil. To date, $700 million has been invested. The remaining $1.1 billion is expected to be spent by 1996.
In Duri, development of four of the planned twelve areas has been completed. The total area developed will eventually grow to about 15,100 acres from the 4,000 acres shown in our tabulation.
The number of wells is scheduled to peak at 3,202 producers and 1,408 steam injectors. At the cut off date for our survey, 952 wells were producing and steam was being injected into another 288 wells.
The dominant process for Canadian EOR remains HC miscible/immiscible injection, and accounts for 82.8% of the 152,953 bo/d Canadian EOR production. Because of the increase in HC projects to 51 from 42 in 1988, Canadian EOR production has increased by 5.8% from the previous survey.
Venezuelan enhanced oil production decreased during the past 2 years.
OGJ's previous survey showed 44 projects producing 216,360 bo/d of enhanced production.
Although the number of projects has only dropped by 2 to 42, enhanced oil production has decreased 45% to 118,788 bo/d. Three of the largest drops were: Bare (F.O.) field from 28,000 to 8,280 bo/d; East Tia Juana field, L.L. zone from 18,000 to 6,800 bo/d; and Bachaquero field from 41,600 to 4,000 bo/d.
The response for the Bachaquero field noted that the steam soak activity was being constrained.
STEAM IN THE U.S.
Oil production from steam EOR in the U.S. is continuing a slow decline from the peak reached in 1986 of 468,692 bo/d. A 2.7% decline occurred between the 1986 and 1988 surveys, followed by a further decline of 2.5% from 1988 to 1990. Although declining, steam still accounts for 67.8% of all U.S. enhanced oil recovery. The current rate is 444,137 bo/d.
The six reported steam projects that are planned in the U.S. between 1990 to 1991, because of their limited size of 336 acres, will not greatly influence the production decline from steam EOR projects.
Environmental laws are inhibiting the expansion of steam projects in California. Crude burned to generate steam has a relatively high sulfur content. But one positive development that might spur additional enhanced oil production is the three proposed pipelines to bring natural gas into the steam EOR areas of California.
As long as natural gas maintains a sufficient differential to the price of oil, gas should replace much of the crude oil burned in generating steam.
Better steam EOR economics may spur new or expanded development.
The Kern River Gas Transmission Co.'s Wyoming-California pipeline will move Rocky Mountain and Canadian gas to California. The Wyoming-California Pipeline Co. (WyCal) is another pipeline that will serve California's EOR customers. The third line bringing gas into the Bakersfield, Calif., area is Mojave Pipeline Co.'s Arizona-California link. All three lines are scheduled to start by late 1991.
CHEMICAL
The hardest hit by the low crude oil prices have been the chemical projects. Of the 91 terminated or completed projects in the U.S., 54 of them were chemical.
Three of these were micellar/polymer, while the rest were polymer. In addition to these, operators requested that an additional 21 polymer projects be deleted from our survey.
GAS
Because of the existing infrastructure in the West Texas area, CO2 enhanced oil recovery remains strong and is expected to grow, judging from the number of planned future projects. The infrastructure makes the expansion Of CO2 into other nearby fields relatively economical.
Half of the almost 30,000 bo/d increase in enhanced oil production from HC injection projects came from Prudhoe Bay. HC injection is the only EOR process active on the Outer Continental shelf.
FUTURE PROJECTS
In the U.S., 34 projects are planned for late 1989 through 1992. More than half, 18, are CO2 projects. The largest in area, 23,000 acres, is Mobil Oil's planned project in the Postle field in Oklahoma's Texas County.
One large project in West Texas is the Shell Western E&P Inc. expansion of the CO2 flood in the Wasson field's 28,758 acre Denver Unit. Two thirds of the unit is now under continuous CO2 injection. This area will be converted to a water-alternating-gas injection (WAG), and the remaining one third of the unit will be put on continuous CO2 injection followed by WAG at a later date.
Shell's Denver Unit is the largest CO2 EOR project in the world in terms of production.
At the end of 1989, the unit was producing 41,100 bo/d of which 25,300 bo/d were considered enhanced recovery.
Internationally only nine projects are planned; six are in Canada. The largest in area, 4,000 acres, is Mobil Oil Canada's miscible N2 project in the Carson Creek North field of Alberta.
Total planned expenditures through 1992 on these projects is estimated to be $502 million.
TAX INCENTIVES
To spur on more EOR projects, the Texas legislature in 1989 reduced the oil severance tax from 4.6% to 2.7% for new tertiary recovery projects that started fluid injection after Sept. 1, 1989.
This reduced rate will be in effect for a 10-year period as long as the project remains active. The rate applies to all oil from the project and not just the incremental increase from enhanced recovery processes.
Not covered by this rate reduction are expansions of projects producing prior to Sept. 1, 1989; projects that are changed from one tertiary method to another; and pressure maintenance projects.
EOR RECOVERY MECHANISMS
OGJ's EOR survey divides recovery mechanisms into four categories: thermal, gas, chemical, and other. Each of these categories is further broken down into several other distinct processes.
THERMAL
The four categories under thermal recovery are steam, combustion, hot water, and electromagnetic. Thermal recovery reduces the oil viscosity in the reservoir and lets the oil flow into the producing well.
For the cyclic steam injection method, or steam soak, one well is used for both injection and production. Steam is injected into the reservoir and left to soak to reduce the viscosity of the oil. Then the oil and water are produced back up the same well that was used for injection. In the Duri field, after three cycles, additional steam injection proved uneconomical.
A steamflood, or steam drive, usually consists of a pattern-type flood. Steam continuously injected into a central well reduces the oil viscosity in the reservoir and then pushes the oil, generated gases, and water to the surrounding producing wells. Steamfloods are commonly installed after cyclic steam injection has recovered most of the oil in the vicinity of a well bore.
Steam is typically economical in reservoirs that are shallower than 3,000 ft, contain oil less than 30 API, and have permeability greater than 200 md. Surfactants can be added to the steam to improve recovery.
Unlike a steam project where oil or gas is burned on the surface to generate steam, a combustion EOR process burns oil in the reservoir. The in situ combustion creates a steam bank, gas from the combustion process, and evaporated hydrocarbons that drive the reservoir oil, gas, and water into the producing well.
Either air or oxygen is injected to maintain combustion. Because no heat is lost in the well bore, combustion projects can be at a much greater depth than steam injection.
Hot water is similar to a waterflood, except that the heated water reduces the viscosity of the oil.
Electromagnetic heating is another way to decrease the viscosity of the oil. No large projects have yet been undertaken using this method.
GAS
Both miscible and immiscible displacement processes are used. The miscible process can involve a concurrent, alternating, or subsequent injection of water. In immiscible displacement, the reservoir pressure and temperature are such that the injected gas is not miscible with the oil.
Carbon dioxide, nitrogen, and flue gas are the most common gases. Low-molecular weight hydrocarbons are also widely used in this type of process. The main application of miscible injection is for reservoirs with low-viscosity crude.
CHEMICAL
All of the chemical EOR processes involve augmenting waterflood performance. In these processes a slug or slugs of chemicals are injected followed by water. These processes improve recovery for crudes of low-to-moderate viscosity.
Polymers improve sweep efficiency by plugging high permeability zones or reducing the mobility of the displacing fluid.
Foam is another way to lower the mobility of the displacing fluid and create a more uniform sweep. Surfactants are used to stabilize the foam.
In micellar/polymer flooding, along with the polymers, surfactants are injected into the reservoir to lower the interfacial tension between water and oil.
Caustic soda is one common low-cost alkaline that is used to increase the pH of the reservoir. Depending on the crude, the alkaline will react with the oil in the formation to create a surfactant that can reduce the interfacial tension between water and oil. Spontaneous emulsification and wettability alteration are two other effects that can improve oil recovery with alkaline injection. In alkaline flooding, the crude should have a high acid number and a low API gravity. Surfactants tan also be combined with the injected alkalines to obtain additional oil recovery.
OTHER
Microbial EOR is another way to enhance waterflooding. The injected micro-organisms and nutrients decompose reservoir oil to produce detergents, Co2, and new cells. These products either mechanically or chemically release oil from reservoir pores.
To date, no large-scale microbial projects have been attempted. Micro-organisms have also been used in single well stimulation treatments.
Copyright 1990 Oil & Gas Journal. All Rights Reserved.
