GEL CONFORMANCE TREATMENTS INCREASE OIL PRODUCTION IN WYOMING

Robert D. Sydansk
Marathon Oil Co.
Littleton, Colo.

Phillip E. Moore
Marathon Oil Co.
Cody, Wyo.

Chromic-carboxylate acrylamide-polymer gels have been applied successfully as conformance treatments in a number of fields in Wyoming's Big Horn basin.

As a result of these treatments, significant amounts of incremental oil will be recovered in a profitable manner.

The gels were applied to naturally fractured reservoirs of intermediate fracture intensity. The gel treatments improved sweep efficiency of oil-recovery drive fluids in fields that were under either primary production, waterflooding, or polymer-augmented waterflooding.

Ultimate incremental oil production from the 29 gel treatments is projected to be 3.72 million st-tk bbl, or on average, 128,000 bbl/treatment. An average 13 bbl of incremental production are projected to be recovered for every 1 lb of polymer injected.

Of the 29 treatments, 17 were applied to injection wells and 12 to production wells. Of the total projected incremental oil recovery from the 29 treatments, 98.3% is attributed to the injection well treatments.

FRACTURED RESERVOIRS

When reservoirs are naturally fractured and there is a fracture network, injected oil-recovery drive fluids tend to channel through the relatively small-volume and high-permeability fracture anomalies.

As a result, the drive fluids bypass and ineffectively sweep oil from large volumes of relatively low-permeability matrix rock. As a consequence, poor sweep efficiency occurs during flooding operations. In turn, cycling and inefficient utilization of the oil-recovery drive fluids result.

Examination of reservoir cores from the gel-treated formations of the Big Horn basin indicated numerous fractures. Theoretical considerations along with observations made during reservoir core studies indicated that the conductive fractures in these Big Horn basin reservoirs are primarily vertical.

Early water and polymer breakthroughs strongly suggested channeling through fractures. Also, some of the successfully treated injection wells showed poor or negative pattern responses when they were first put on water injection, as shown by increased water/oil ratios (WORs) and higher fluid levels at the offset producers.

Pressure transient and interference testing studies suggested the presence of numerous fractures and indicated directional permeability characteristics.

For the two formations most successfully treated with the gels, analysis showed that the fracture networks were of intermediate intensity (widely spaced fractures having an irregular pattern of interconnections) and that the fracture networks possessed directional characteristics. The directional characteristics resulted from the most conductive fractures having preferred orientations.

These Big Horn basin reservoirs do not possess intense fracture networks (e.g., fractures that have intersection frequencies, on the average, of about every 1-10 ft). The fracture frequency in the treated Big Horn basin reservoirs is fairly high, and the fractures are usually interconnected.

Fracture-conformance gel treatments function by reducing the fluid-flow capacity of the treated fractures to reduce channeling. As a result of reducing fracture fluid-flow capacity and reducing channeling of the oil-recovery drive fluids, sweep efficiency is improved and the drive fluids are subsequently diverted to the relatively low-permeability matrix rock (or possibly to less conductive fractures).

Conformance treatment gels can be applied either from the injection-well or the production-well side. When treating fracture conformance problems, gels should be designed to reduce the fluid-flow capacity of the fractures, while simultaneously not substantially invading the adjacent matrix reservoir rock and reducing its permeability.

A more complete discussion of conformance problems and treatments, especially as relating to fracture conformance problems, can be found in an earlier paper.1

GELS

Aqueous chromic-carboxylate acrylamide-polymer gels are formed by crosslinking acrylamide polymers with a chromic-carboxylate-complex crosslinking agent.1-3

The gels are a single-fluid system and do not involve sequential injection of fluids. These gels, as used in Wyoming, are produced by metering the crosslinking-agent solution into the polymer solution on the fly just prior to injection.

An entire family of gels, having consistencies ranging from highly flowing to rigid rubbery gels, can be produced at the well site by simply varying the formulation of the same chemical set. Thus, the gels are applicable to a broad range of conformance problems and other oil field uses. Highly controllable gel times, ranging from minutes to weeks, are possible and can be preselected.

Chromic-carboxylate gels have been shown to possess exceptional strengths and to be effective plugging agents.

The gels can be used over a broad pH range. Gels of this technology are insensitive to oil field interferences and environments, especially H2S.12

These gels were shown to be compatible with all tested oil field fluids (including crude oil and a variety of saline and hard produced waters) and equipment and with all tested reservoir rocks and minerals.12 A successful field test of this gel technology, where the produced waters contained 300 ppm H2S, has previously been reported.4

The gels are relatively inexpensive because they contain, as used in these Wyoming treatments, between 97.8 and 99.7% water with the remainder being low-cost chemicals. The fracture treatment chromic-carboxylate gels are specifically designed to be effective fracture-plugging agents, without significant invasion by the gels into the adjacent matrix reservoir rock.12

Gels formulated with polyacrylamide (PA) and partially hydrolyzed polyacrylamide (PHPA) were used in these treatments. All of the injection-well gel treatments involved use of 11 million molecular weight (MW) PHPA which was 30 mole % hydrolyzed. All of the production-well gel treatments involved use of 11 million MW PA of 1-3 mole % hydrolysis.

The acrylamide polymers used in these gel treatments were obtained from one of Marathon's field manufacturing units in the Big Horn basin. The polymer was manufactured as a concentrated surfactant-free aqueous solution (e.g., 7.5 wt % PHPA).

For the large-volume injection-well treatments, concentrated PHPA aqueous solutions were diluted at the well site with saline injection water prior to adding the crosslinking agent.

The crosslinking agent used during these gel treatments was a mixture of oligomeric chromic (Cr3+) coordinate-covalent-bonded complex ions involving acetate carboxylate anions.1-3 When dissolved in aqueous solution, a significant portion of the acetate anions are bound as ligands to the hex-acoordinate Cr3+.

The carboxylate-to-Cr3+ molar ratio was about 3.0:1. A detailed discussion of the aqueous-solution chemistry of the crosslinking agent has been reported earlier.5

The base chemical of the crosslinking agent is commonly referred to as "chromic acetate" and was obtained from McGean-Rohco Inc. as a 50 wt % active aqueous solution.

For these Wyoming gel treatments, the cost of the crosslinking agent was typically 5-10% of the total chemical cost.

The majority of the chemical cost was for the acrylamide polymer.

In contrast to Cr6+ which is highly toxic, Cr3+ is relatively nontoxic.6-10 In fact, Cr3+ has been reported to be an "essential micronutrient" for human health.6 10 At low concentrations, Cr3) is relatively nontoxic to aquatic life.10

TREATMENT PROCEDURES

The injection-well treatments involved "flowing" gels where the bulk of the aqueous phase was saline injection water. A typical injection water contained about 3,400 total dissolved solids (TDS), 640 ppm hardness, 100 ppm (20-200) H2S, and substantial concentrations of bicarbonate and sulfate anions.

The injection-well-treatment gels contained PHPA concentrations ranging from 3,000 to 8,500 ppm. The vast majority of the injected gels contained about 5,000 ppm PHPA.

The weight ratio of PHPA:Cr3+ varied between 44:1 and 88:1.

Gel volume injected per treatment ranged between 640 and 37,000 bbl and between 18 and 670 bbl of gel/ft of perforated treated interval.

Gel injection rates usually varied between 500 and 2,000 b/d.

Treatment strategy called for initial gel injection to begin with low polymer concentrations and to build polymer concentration and associated gel strength as the treatment proceeded.

Two important gel treatment strategies were followed during the treatments. First, care was taken with one failure, to inject all pregel and gel solutions at pressures well below parting pressure. Second, all gel-injection parameters, especially injection pressure, were monitored closely and continuously throughout gel injection.

Gel formulation parameters and injection rates were often modified on the fly as dictated by frequent and often unpredictable treatment pressure responses.

The production-well treatments involved injecting pregel solutions of nonflowing rigid gels where the aqueous phase was freshwater.

Because the production-well treatments were of relatively small volume, there was little economic or operational penalty in using freshwater. Freshwater was used out of convenience and as a standardization factor.

The gels of the production-well treatments were formulated to possess enough strength so as not to flow back and be produced under drawdown conditions.

All of the production-well treatment gels contained 2.0 or 2.2 wt % PA, and all were crosslinked at 88:1 by weight PA/Cr3+. Gel volumes injected per treatment varied between 6 and 920 bbl and between 0.07 and 26 bbl of gel/ft of perforated interval.

Application of the chromic-carboxylate gels proved to be attractive from an operational standpoint. All that was required was to meter the crosslinking solution into the polymer solution just prior to passing the resultant mixture through a static mixer and then injecting it into the wellhead.

Fig. 1 is a schematic of the gel injection process. For the large-volume injection well gel treatments, a concentrated polymer solution was diluted with injection water at the well site. For the small-volume and high-polymer-concentration production well treatments, this dilution was not required.

The 29 gel treatments were performed without encountering any significant operational, safety, or environmental problems. During every treatment, quality gel was readily made at the well site.

In no case was there ever any indication that the gels were not functioning downhole as intended with respect to reducing the fluid-flow capacity of the treated fractures. All but one of the 29 treatments were classified as "operational successes."

In no case was any substantial amount of gel, Cr3+, or gel polymer produced after the gel treatments. Following treatment application, produced fluids of all the direct offset production wells to the injection-well treatments were routinely monitored for chromium content. In no case was any chromium (

At times, small amounts of gel were retrieved from within the well bore during post-treatment workovers of production wells which were treated with this gel technology.

PRODUCTION RESPONSES

Between June 1985 and September 1988, 29 gel treatments were applied to three formations in nine fields of the Big Horn basin.

As of January 1990, seven of these field tests had produced 965,000 bbl of incremental oil. At that time, for these seven treatments, the rate of incremental production was 490 bo/d.

The cost of the recovered incremental oil was $0.51/bbl. However, because of the ongoing incremental oil production, this cost figure will be significantly reduced.

The 29 treatments were applied to 17 injection and 12 production wells. A total of 27 different wells were treated.

Typical reservoir properties of the three formations (Embar/Phosphoria carbonate, Madison carbonate, and Tensleep sandstone) are summarized in Table 1.

Oil recovery from these reservoirs normally involves a combination of direct drive and imbibition mechanisms. Bottom water drive is not considered to be a significant factor. A more detailed description of these gel treatments and a more detailed discussion of the production responses, has been reported previously.

Several general observations have been made relating to production responses following the gel treatments. Directional treatment-response effects were often noted. For the injection-well treatments, production responses were at times more notable at certain of the offset production wells (e.g., east/west wells), whereas little production response was noted at the other production wells (e.g., north/south wells).

Production responses to the injection-well treatments, especially when directional response characteristics were present, were at times noted at production wells beyond the direct offset producers.

Decline-curve analyses were used when determining incremental oil production attributed to each gel treatment. When determining incremental oil recovery beyond what had already been produced, projected recovery was determined by taking the difference between the projected pre and post-treatment decline curves.

For determining projected ultimate incremental oil recovery, post-treatment decline curves were projected out to the economic limit for each well.

The bulk of the incremental oil production occurred during the first several years following the gel treatments; therefore, projected ultimate incremental-oil-production values are believed to be fairly accurate. However, attainment of the projected ultimate incremental oil recoveries is contingent on the assumption that after the production-response analyses, no significant operational or pattern changes will be made in the well patterns affected by, or offsetting to, the gel-treated wells.

An overview of the production responses to all 29 of the Big Horn basin gel treatments is presented in Column 1 of Table 2. Incremental production resulting from the gel treatments is projected to ultimately be 3.72 million st-tk bbl. Average incremental production per treatment is projected to be 128,000 bbl.

The cost of an average treatment was $44,300. Treatment costs included all chemical, gel injection, and workover costs.

Average incremental production per pound of polymer in the gels injected is projected to be 13.1 bbl. Cost of the incremental oil, on the average, is projected to be $0.34/bbl.

INJECTION WELLS

The injection-well treatments were applied either during waterfloods or polymer-augmented waterfloods. In all cases, where the gel solutions were injected when surface pressure existed or when a downhole gauge was utilized, significant injectivity reductions were noted during gel injection and following the gel treatments.

For example, as a result of gel treating injection well S-23 in a highly fractured area of the Madison carbonate formation in Field C, downhole pressure increased by 1,000 psi for the same water injection rate when comparing pre and post-treatment injection pressures.

At offsetting production wells to the successful injection-well treatments, water production often was reduced, but not always. For most of the injection-well gel treatments, reduced WORs resulted at the offsetting production wells.

In addition, offset production wells often experienced reduced fluid levels and larger drawdowns. For the injection-well treatments applied to wells used as injectors during polymer-augmented waterflooding, the gel treatments often greatly reduced channeling and cycling of polymer.

Favorable production responses to the injection-well treatments typically occurred at the offset production wells within a time frame ranging from weeks to months.

An overview of the production responses to the 17 injection-well treatments is presented in Column 2 of Table 2.

Incremental production resulting from all of the injection-well treatments is projected to be 3.65 million bbl. Average incremental production per treatment will be 215,000 bbl.

Cost of an average treatment was $45,200. Incremental recovery per pound of polymer injected is projected to be 13.6 bbl. Cost of the incremental oil is projected to be, on average, $0.21/bbl.

Injection-well treatments were used most successfully in the Embar carbonate and the Tensleep sandstone formations in Field C. Oil production and WOR responses for two of these injection-well treatments are depicted in Figs. 2 and 3.

It should be noted that a small portion of the incremental oil rate attributed to the 0-7 injection-well treatment (Fig. 3) may have resulted from a neighboring injection-well gel treatment applied 2 months prior to application of the 0-7 treatment.

The neighboring well is in a secondary offsetting pattern, but the two wells do lie on a high-permeability directional trend.

The cost of an average treatment, in Field C, was $34,000. Average incremental production per treatment is projected to be 320,000 bbl. Average development cost of the incremental oil is projected to be $0.11/bbl (Table 3).

Of the 17 injection-well treatments, 11 were applied to the Embar and Madison carbonate formations and 6 to the Tensleep sandstone formation.

Average incremental production per treatment is projected to be 261,000 bbl for the treatments applied to the carbonate formations and 129,000 bbl for the treatments applied to the sandstone formation (Table 4). Average treatment costs were similar. As a consequence, the average cost of $0.18/bbl for the incremental oil obtained from the carbonate formations is about one half that of the cost of the incremental oil obtained from the sandstone formation.

As would be expected for conformance problems involving vertical fractures and associated areal conformance problems, no significant correlation between gel-treatment-induced injection or production profile changes and incremental oil recovery was noted.

At times, no change in injection profile occurred following the injection-well treatments, even for treatments that promoted large volumes of incremental oil recovery.

Of the 17 injection-well gel treatments, 5 did not result in any significant change in injection profiles following the treatments. Changes in injection profiles are not necessarily expected to occur following successful conformance treatments applied to injection-wells that suffer from areal conformance problems resulting from vertical fractures.

PRODUCTION WELLS

Total ultimate incremental recovery resulting from the 12 production well treatments is projected to be 63,000 bbl or on the average, only 5,300 bbl/treatment. Cost of the incremental oil is projected to be, on the average, $8.21/bbl (Table 2).

The production-well treatments, as applied in these reservoirs of the Big Horn basin, routinely and significantly reduced water production and lifting costs. However, if too much gel was injected, reduced oil production often occurred.

Many of the production-well treatments (especially if the wells were not overtreated) did promote substantial increases in oil production rates immediately, following the gel treatments, but the enhanced oil recovery rates would often fall back rather rapidly to pretreatment oil production rates.

No significant amounts of Cr3+, polymer, or gel were noted in the produced fluids following any of the production-well treatments. Post-gel-treatment produced fluids were routinely monitored for gel and gel components.

An example of post-treatment production of Cr3+ and polymer following a production-well treatment has previously been reported.4 The example showed that only very minor amounts of Cr3- and polymer were produced back.

Reductions in water production rates and total well productivities, reduced fluid levels, and increased drawdowns following the production-well treatments were usually highly sustained with time and post-treatment production.

TREATMENT UPDATE

Updated production responses for the nine gel conformance treatments previously reported4 are presented in Table 5. General trends for these production responses tend to parallel those for all 29 of the gel treatments.

However, because the two production-well treatments were both relatively successful, the production responses for the two earliest production-well treatments appear more favorable.

Table 6 updates production for all seven of the injection-well treatments reported in an earlier paper. For the five successful injection-well treatments, reserve development cost of the ultimate incremental oil recovery is projected to range from $0.06 to $0.33/bbl, and incremental oil production is projected to range from 42,000 to 718,000 bbl/treatment.

Interestingly, for the five successful injection-well treatments, both maximum incremental oil production rate and projected ultimate incremental oil recovery tend to roughly correlate with the amount of gel injected per perforated foot of treated interval.

Obviously, this apparent relationship cannot hold as the volume of gel increases to some relatively, large value. When this correlation was reevaluated for all 17 of the injection-well gel treatments, the correlation was not as good.

One motivation for including the update on these nine gel treatments is to provide an opportunity to report on actual incremental oil recovered, without having to invoke any analyses involving projected incremental oil recoveries. As in the earlier paper,4 only production data for the seven economically successful gel treatments (five injection-well and two production-well treatments) are analyzed.

One of the lessons that was learned from these, the first nine field tests of this gel technology in Wyoming, was that we would not treat the Madison carbonate formation of Field C in a similar manner in the future with this gel technology. As a result, the two injection-well treatments applied to the Madison carbonate formation were not included in the following analysis.

Updated production responses to the seven successful 1985 and 1986 field tests are as follows. Through January 1990, recovered incremental production was 965,000 bbl. At that time, the seven gel treatments were being credited with an incremental production rate of 490 bo/d. In view of the fact that the cost of the seven gel treatments (including all chemical, gel pumping, and workover costs) was $488,000, the cost of the recovered incremental oil was $0.51/bbl. However, this cost is still being reduced because of ongoing incremental oil production. As of January 1990, 6.2 bbl of incremental oil production had been produced per pound of polymer injected.

At the end of 1991, these seven successful get treatments continue to perform, in general, as expected.

ACKNOWLEDGMENTS

We thank the management of Marathon Oil Co. for its support of this work and permission to report it. The assistance in preparing this article by Karl Dreher is gratefully acknowledged.

REFERENCES

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