Mobility control for CO2 EOR using SPI gels

The purpose of performing silica polymer initiator (SPI) treatments in EOR CO₂ floods is to increase oil production and ultimate oil recovery. SPI gels do this by redirecting injected CO₂ away from already swept zones in the reservoir rock with no oil left to recover and into new unswept zones. EOR operations using CO₂ are expensive. Once started, CO₂ will continue to flow through the same oil-depleted zone because of its very low viscosity and high mobility relative to the oil and water in the reservoir. As this process continues, the operation becomes more and more inefficient and eventually becomes too costly to continue. Improving that recovery efficiency by blocking the depleted zone will allow the EOR operation to continue at a profitable level and recover additional oil.

SPI gels are multicomponent silicate-based gels for improving (areal and vertical) conformance in EOR operations, including waterfloods and CO₂ floods, drilling well problems, and other applications. They were originally developed under a U.S. Department of Energy- (DOE-) funded Stripper Well Consortium project in 2006 and have been continuously improved. They are patent pending and are environmentally friendly, containing many food grade components. SPI gels are pumped as a water-like liquid into the oil-depleted zones of the formation and can then be triggered by an initiator (e.g. CO₂) to lower its pH and form light gels up to very thick paste-like gels. SPI gels can be three to 10 or more times harder (per penetrometer tests) than any crosslinked polyacrylamide (PAM) gel now available, allowing it to seal in difficult applications where PAM systems would break down. However, the hardest SPI gel is not as strong as cement or epoxy, allowing it to be chemically washed/jetted and/or otherwise removed from the wellbore without drilling.

Field testing

This DOE-funded project field-tested a total of eight SPI treatments in six wells (five injection wells and one production well) in a relatively new central Mississippi sandstone under immiscible CO₂ flooding and in a mature west Texas San Andres dolomite under water-alternating-gas/CO₂ (WAG) miscible flooding. The SPI treatment sizes ranged from 130 bbl to 4,349 bbl. Chemical and water buffers before and after the SPI mix ensured that the pre-gelled SPI mix got placed out into the formation before contacting CO₂ and setting into a hard gel.

Clean Tech Innovations’ laboratory performed static bottle/beaker tests to improve the SPI chemistry and find new chemicals for easier/lower cost field treatments. Tests also were done on core rock material, brine and crude oil samples from both fields to ensure compatibility in the field tests. Brookfield Viscometer readings showed that even high-concentration SPI gels had viscosities near water at reservoir temperatures. But once set, SPI gels are stronger than commercially available crosslinked high molecular-weight (HMW) PAM gels, allowing use in difficult applications. Additives were developed to prevent significant losses into tighter zones of the reservoir.

Dynamic flow tests in this equipment with Ottawa sand (crushed and sieved to 20-40 mesh) showed permeability reduction from 737 millidarcys to 8 millidarcys, with one low-concentration SPI treatment that was initiated with CO₂. A second SPI treatment reduced that permeability down to only 2 millidarcys. This calculates to residual resistance factors (Frr) of 92 for the first SPI treatment, four for the second treatment and 450 overall for the Ottawa sand. Dynamic testing with Field A sandstone (at 43 C [110 F]) showed an overall Frr of 123, and with Field B San Andres dolomite (at 41 C [105 F]) the overall Frr was 2,425, both with two SPI treatments.

The overall goal of this program was to test SPI gels in as wide a variety of CO₂ flood field conditions as possible: The tests were successful. The earliest field treatments were in Field A, a central Mississippi sandstone that is about 1,524 m (5,000 ft) deep. The sandstone reservoir matrix has a Dykstra-Parson ratio of 0.97, and there are multiple natural fractures in the area of the SPI-treated wells. It is a fairly new immiscible CO₂ flood with no water injection. Most producers are forced-flow, with a few on artificial lift. These earliest SPI field treatments have lasted for more than a year.

The later West Texas treatments in Field B were in the San Andres dolomite formation, also at about 1,524 m deep. These were in a mature, miscible WAG injection cycle CO₂ flood. There are only eight months of injection and production data available under these variable WAG conditions, which are insufficient to fully evaluate the treatments. Monitoring of this field continues to finalize the evaluations. Both fields had other operational events and offset well work occurring during both the treatment and evaluation periods that complicated the treatment evaluations.

Field A injector Well #1’s SPI Treatments of 950 bbl during SPI1 and 3,842 bbl during SPI3 showed:

• 58% CO₂ injectivity reduction, indicating that the injected CO₂ is now going into new, lower-permeable zones/paths. That reduction has lasted for more than one year;
• Increased oil production in five offset/area production wells, totaling about 14,250 bbl over the first year. Offset work complicated this evaluation, and the total impact of the treatment was reduced accordingly. The value of that incremental oil is estimated at $1.283 million (at $90/bbl sold); and
• A reduction in the produced gas-oil ratio (GOR) in five offset producers, indicating a direct operation cost savings and improved CO₂ utilization in the reservoir. Operator A estimated the CO₂ recycle cost to be $3.18/Mcm ($90/MMcf) in Field A “because it is a compression-limited operating environment. The primary value for reducing the GOR is the additional oil resulting from more efficient use of the compressed gas.” Redirecting the injected gas should cause long-term benefits of increased oil production.

Field A marginal producer Well #2’s SPI2 treatment of 691 cu. m (4,349 bbl) showed:

• Increased oil production totaling 1,500 bbl; and
• An initial 81% GOR reduction that dropped to 44% and then trailed down to its pre-treatment level by the end of the first year.

In West Texas Field B, data collection is ongoing on 21 offset/area production wells and nine injectors to evaluate the total impact of the five SPI treatments in four wells in the field. To date, results include:

• The four treated injection wells (Wells #3, 4, 5 and 6) showed 23% to 71% reductions in CO₂ injectivity after the treatments;
• One offset production well has shown increased oil production from 28.5 bbl/d to 47.3 bbl/d of oil post-treatment, or a 66% increase, for an incremental recovery of 1,468 bbl, equal to $132,000 for the 90 days monitored;
• One offset production well showed a decrease in water production from a pre-treatment 70 water/oil ratio (WOR) to an 11 WOR; and
• Ten (12 total including the two above) offset production wells show increasing/positive trends that will be monitored for up to one year.

In addition, comparison was made between the SPI treatments and other competing treatments performed in the same fields and, in some cases, in the same wells. Competing treatments included one Marcit treatment, a few PolyCrystals treatments and many HMW crosslinked PAM treatments. Two wells have direct comparisons to SPI treatments: Field A Well #1 had a Marcit treatment in 2010 that did not change CO₂ injectivity nor impact any offset production wells, and Field B Well #3 had a crosslinked PAM gel treatment, which did reduce water injectivity but not CO₂ injectivity, adversely increasing offset well GOR and gas/liquids ratio and resulting in no incremental oil recovery. However, SPI gel treatments in both fields, and specifically in those two direct comparison wells, showed injectivity decreases and some impact on their offset wells.