Field applications of conformance improvement gel treatments

This page discusses field experience in the application of various types of conformance improvement gel treatments.

Fracture problem sweep-improvements treatments

Fig. 1 shows the type of production response that is possible when applying a polymer gel treatment to a waterflood injection well to improve sweep efficiency. The sweep-improvement treatment involved the application of a chromium(III)-carboxylate/acrylamide-polymer (CC/AP) gel treatment. The figure shows the combined production-response of the four direct offsetting production wells to the gel-treated injection well. The gel treatment was applied for waterflood sweep-improvement purposes to the naturally fractured Embar carbonate formation surrounding Well O-7 of the highly mature SOB field in the Big Horn basin of Wyoming. The wide variations in water/oil ratio (WOR) and oil production rate are quite common in many of the well patterns of this highly fractured reservoir. Sydansk provides more details regarding the 20,000 bbl gel treatment. The economics of applying this gel treatment were exceptionally good.

• 

  Fig. 1 – Production response to the CC/AP gel treatment applied to injector O-7 in the SOB field.

Fig. 2 shows seven years of incremental oil production response for the combined direct offset producing wells to CC/AP gel-treated injection well O-17 of the SOB field. This figure illustrates the type of treatment longevity that can be expected from CC/AP gel treatments. Well O-17 was treated in approximately the same manner and as part of the same gel treatment series cited for the Well O-7 gel treatment in Fig. 1.

• 

  Fig. 2 – Production response to the CC/AP gel treatment applied to injector O-17 in the SOB field (after Sydansk and Southwell).

Water shutoff treatments

Fig. 3 shows the production response type that can occur when a gel treatment is applied to a production well to reduce excessive water production. In this case, a CC/AP gel treatment was applied to a production well for water-shutoff purposes. The gel treatment was applied to the 145°F fractured carbonate reservoir surrounding production well LSD N-17P in a field in Wyoming’s Big Horn basin. The excessive water production, which was occurring during primary production, was thought to be edge water encroaching through fractures from a strong aquifer. Water production before the gel treatment was 5,000 barrels of water/day (BWPD). Following the treatment, the water production was reduced to 1,000 BWPD. There was a short-lived (several months) modest oil production increase following the treatment that paid out the cost of the gel treatment. The primary objective and benefit was the water shutoff.

• 

  Fig. 3 – Production response to the CC/AP gel water-shutoff treatment applied to production well LSD N-17P.

A large number of CC/AP gel water-shutoff treatments have been successfully applied to often old and highly marginal production wells of the dolomitic Arbuckle formation in Kansas. The excessive and detrimental water production is believed to be aquifer water coning up to the production wells via fractures or some other type of high-permeability anomaly. Successful Kansas Arbuckle CC/AP gel water-shutoff treatments often reduce the water production rate by more than 90%.

Willhite and Pancake reported in 2004 that more than 250 CC/AP water-shutoff treatments had been applied to Kansas Arbuckle wells. Their paper reported that incremental oil production was, in general, the business driver for conducting these gel treatments. The focus of their paper was on seven of these gel treatments that were studied in detail, where downhole pressure data was obtained before, during, and after the gel treatments. Highlights relating to these seven Arbuckle gel water-shutoff treatments are as follows:

• Water production was reduced in every well by 53 to 90%
• Incremental oil production was obtained for 5 out of the 6 wells that were produced for 6 months after the gel treatment
• Oil productivity indexes increased following the gel treatments
• Incremental oil production increased with increasing volume of the gel treatment for the wells that were completed open hole
• The duration of the treatment response is expected to be a function of the volume of the gelant injected

Rodney Reynolds reported on the performance of 300 CC/AP gel water-shutoff treatments that were applied in the Arbuckle formation of Kansas by more than 30 different operators. The 250 CC/AP gel water-shutoff treatments of Willhite and Pancake are likely a subset of these 300 gel treatments. The following analyses are based on performance data that were obtained from 95 of the 300 treatments and then factored/proportioned up to the 300 CC/AP gel water-shutoff treatments. Reynolds reported the following performance attributes for the 300 Arbuckle water-shutoff treatments (based on the 95 gel treatments analyzed):

• Shut off 110,000,000 bbl of excessive and undesirable water production
• Generated 1,600,000 bbl of incremental oil from these, in general, old and marginal wells
• Cost of the gel pumped ranged from approximately US $10 to $15 per bbl
• Average treatment size was 2,600 bbl of gel fluid injected
• For gel treatments with “average performance,” payout times ranged from 3 to 6 months (based on incremental oil production only)
• Average incremental oil production from these “marginal” production wells was 5,500 bbl of oil
• Operators reported reserve development costs for the incremental oil of US $2 to $7 per bbl

Gas shutoff treatments

Sanders, Chambers, and Lane reported on 37 CC/AP gel gas-shutoff treatments that were applied to 31 production wells in the 190 to 220°F reservoir of Alaska’s Prudhoe Bay field. It reported that these gas-shutoff gel squeeze treatments cost 75% of comparable Portland cement gas-shutoff squeeze treatments in this field and afforded a higher success rate. Sanders, Chambers, and Lane also reported that these gel gas-shutoff treatments had been credited with a gross initial (one month of production) incremental oil production rate of 22,000 barrel of oil/day (BOPD) and that these gel treatments reduced gas production to 213 MMscf/D. Sanders, Chambers, and Lane stated that “squeeze longevity has been greater than one year [to date] in some cases with drawdown pressures exceeding 1,500 psi.”

Microgel sweep-improvement treatments

Colloidal dispersion gels of acrylamide polymer crosslinked with aluminum citrate have been applied somewhat extensively in the US Rocky Mountain region, especially in the Minnelusa sand formation. These large-volume gel treatments were applied to secondary and tertiary projects to promote in-depth permeability modification in highly heterogeneous “matrix” sandstone reservoirs. Mack and Smith reviews the recovery and economics of 29 such aluminum-citrate colloidal dispersion gel treatments. The polymer concentration of the aluminum-citrate colloidal dispersion gels was typically in the 200 to 1,200 ppm range. The mechanism by which these aluminum-citrate colloidal dispersion gel treatments function is not well understood, and technical issues relating to this technology are being debated.

Fractures intersecting a horizontal well

Lane and Seright reviews the successful design and application of polymer-gel water-shutoff treatments that were applied using bullhead placement for treating excess water production from horizontal wellbores into which the excessive and competing water production was emanating from a “vertical” natural fracture that intersected the horizontal borehole and extended into an underlying aquifer. This is an emerging gel water-shutoff technology that is creating substantial interest because of the large number of expensive multilateral and/or subsea horizontal wells for which any water-shutoff treatments to be applied through these horizontal wells must be bullheaded due to their often openhole, multilateral, and/or subsea completions that do not readily permit the use of mechanical zone isolation.

Use during CO₂ flooding

Borling reported on successful conformance improvement CC/AP gel treatments that were applied at the Wertz field CO₂ tertiary water alternating gas (WAG) flooding project in Wyoming’s Wind River basin. He reviewed 10 injection-well gel treatments applied to a 165°F naturally fractured Tensleep sandstone reservoir. The following benefits were reported to have been derived from applying these gel treatments during the Wertz CO₂ flooding project in this naturally fractured reservoir. The gel treatments promoted incremental oil recoveries of up to 140,000 barrels per well pattern and increased oil production rates by 100 to 300 BOPD per well pattern. The gel treatments extended the economic lives of marginal well patterns by nearly two years. They reduced gas/oil ratios (GORs) and WORs, reduced gas and water cycling, reduced gas and water breakthrough times, and improved water and gas injection profiles. The CC/AP gel treatments reduced operating expenses, contributed substantially to the fieldwide decline rate reduction in 1992 from 24 to 9%, were effective where conventional oilfield foams had failed, and had rapid payout times of often less than three months. The Wertz conformance improvement gel treatments were responsible for recovering substantial reserves that would not have been otherwise recovered.

Hild and Wackowski reported on 44 injection-well CC/AP gel treatments that were applied during 1994 through 1997 at the CO₂ miscible WAG flooding project of the Rangely Weber Sand unit in northwestern Colorado. These injection well treatments (average size ~10,000 bbl) had an 80% success rate and rendered an economic rate of return of 365%.

Gas shutoff in an openhole gravel-pack completion

A “successful and selective” gas-shutoff treatment, using an organically crosslinked acrylamide-polymer gel, has been documented. The gel treatment was applied to an offshore well in the Norwegian North Sea. The gel treatment was applied to a gravel-packed well penetrating a multilayer reservoir containing shaley sandstone strata. A temporary blocking gel of crosslinked hydroxypropyl guar was selectively placed to temporarily seal and protect the upper producing portion of the well, while the organically crosslinked acrylamide-polymer gel for shutting off the lower gas-producing strata was being injected.

Carbonate vs. sandstone reservoirs

Table 1 shows a comparison of the production response and the economic performance of a series of large volume (4,000 to 37,000 bbl) CC/AP gel treatments that were applied, between 1985 and 1988, as sweep improvement treatments to naturally fractured injection wells in Wyoming’s Big Horn basin. The averaged combined production responses of the four direct offsetting production wells to the treated injection wells are shown. For this set of treatments, 11 of the gel treatments were applied to the naturally fractured Embar carbonate formation and six of the gel treatments were applied to the naturally fractured Tensleep sandstone formation. The gel treatments performed well in both the carbonate and sandstone reservoirs. The difference in performance of the gel treatments in the two sets of reservoir mineralogies is believed to have resulted mostly from differences in fracture characteristics and not from differences in gel performance in the two types of mineralogical formations. The fracture network of the carbonate formation in this instance is believed to be more conducive to being successfully treated with gel sweep improvement treatments.

• 

  Table 1 - Comparison of Wyoming injection well treatments in carbonate vs. sandstone formations.

Chemical liner completions

More than 100 successful CC/AP gel gas-shutoff treatments were applied as chemical liner completions and were performed during a drilling program involving the drilling of short-radius horizontal wellbores in the Yates field of Pecos County, Texas. The gel chemical liner completions were applied to the openhole curved section of the horizontal wellbores. The lateral borehole of these wells penetrates a relatively thin oil column in a fractured dolomitic reservoir, where the oil column is overlain by a substantial gas cap. The openhole curved section of the short-radius borehole partially extended up into the gas cap. If the curved section of the boreholes were not sealed, the horizontal wells would produce excessive, and often uneconomic, high GORs. In 1995, the first 80 of these horizontal wellbores, which had been treated with the gel chemical liner treatments, were producing 12,500 BOPD and had recovered approximately six million cumulative barrels of crude oil.<html><parsererror style="display: block; white-space: pre; border: 2px solid #c77; padding: 0 1em 0 1em; margin: 1em; background-color: #fdd; color: black">

Noteworthy papers in OnePetro

Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read

External links

Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro

See also

Gels

Conformance improvement gel treatment design

Placement of conformance improvement gels

Evaluation of conformance improvement gels

Types of gels used for conformance improvement

PEH:Polymers,_Gels,_Foams,_and_Resins