Carlos BroccoA preflush technique was successfully used in fracturing oil zones near water-producing intervals in nine Pioneer Resources Inc. wells in Argentina.
Pioneer Resources Inc.
E. Dwyann Dalrymple
Halliburton Energy Services Inc.
Halliburton Energy Services Inc.
Halliburton Energy Services Inc.
The treatment has also been successfully used in wells in the U.S.
Data from the initial 3 months of production from the wells in Argentina indicate that the stimulations were economically justified. The treatments limited water production to less than 15% in some wells and in other wells water production was negligible.
The preflush technique involves an in situ-generated, polymer-conformance system (PCS) that reduces water flow by decreasing the formation's permeability to water.
In the past, permeability agents were used to help eliminate water production in high water-saturated intervals. However, because these agents were designed to stop water production, they were also likely to curtail oil production and/or damage the formation.
The PCS preflush, developed in 1995, is effective because it does not shut off water flow. Instead, it disproportionately reduces the formation's effective permeability to water. This permeability reduction lessens water flow without significantly impairing hydrocarbon production.
This technique has significant economic potential, both for enhancing production from newly drilled wells, and obtaining production in existing wells from intervals where stimulation was previously ruled out.
Field tests indicate that the technique is effective in stimulating formations subject to water coning and those containing high-permeability streaks with high water saturation.1 2
BackgroundFor years, operators have avoided stimulating hydrocarbon-containing formations that have a high water saturation because of the possibility of unmanageable water production. In these formations, stimulation almost always results in a fracture intersecting a water stringer within the targeted interval, or extending into a high-water saturated zone above and/or below the interval. This can cause water cuts as high as 60-70%, which can make production uneconomical.
Water production is a major problem because:
- Every barrel of water produced reduces the quantity of oil that is recoverable in a given period, provided the production techniques remain unchanged.
- With time, the percentage of water flow typically increases because water has greater mobility than oil. Therefore, oil production decreases as rapidly as water production increases.
- Lifting, separating, and disposal costs of water significantly increase producing costs.
- Water production can cause or exacerbate problems such as sand production, and corrosion on tubulars and surface equipment.
- The oil and water mixture can be lifted to surface, where it is separated with the water being disposed of.
- A plugging agent can be squeezed into the formation to help prevent water entry.
PCS-enhanced stimulationThe PCS treatment is effective and economical because:
- It does not degrade with shearing or contact with other downhole fluid systems.
- It requires no rig time, and zonal isolation is unnecessary.
- In its liquid, pumpable state, PCS has a water-like viscosity and generates a polymer in situ; therefore, placement requires no pressure greater than that required for water.
PCS chemistryPCS is a combination of two chemical components which are diluted with water and blended.
The solution is then placed downhole as a preflush ahead of a fracture stimulation. In some cases, the PCS may be preceded by a solvent preflush that removes deposits of asphaltenes and/or paraffins in the formation.
After the PCS is injected and the fracturing treatment placed, the well is shut in for 10-18 hr, during which in situ polymerization occurs.
The conventional belief is that a "brush polymer" forms, bonding with the rock face so that it does not produce back. Conformance experts have hypothesized that this water-inhibiting polymer is assisted by hydrophilic branches that extend from the polymer into the pore-throat region and act as "microvalves" or "polymer brushes" in the presence of water.
By residing in the formation pores, this polymer can effectively control the passage of fluids, curtailing water flow while permitting hydrocarbons to pass freely.
The PCS is designed as a preemptive treatment, and has very little effect on zones with significant oil saturation. Therefore, the PCS technique is not appropriate in previously stimulated wells. Stimulation allows oil to contaminate water zones and prevents the PCS treatment from effectively reducing the water flow.
Argentina jobsIn an Argentina well, the PCS preflush was included in stimulation treatments of several intervals having high water saturation, as shown on logs. None of the intervals had been stimulated previously because of the potential for water production.
One of the first PCS applications in Argentina was in a well bore perforated in the Lotena formation, between 5,558 and 5,591 ft. A water layer had been detected 11 ft below this interval.
The stimulation included linear gelled spacers pumped before and after the PCS for pH control. Preflush and postflush stages were coordinated in an attempt to place the treatment fluid half the distance of the total fracture depth.
After the PCS was placed, fracturing fluid was pumped downhole at 14 bbl/min. The well was shut-in for 3-hr before being put back on production.
Immediately after the stimulation treatment, production rates reached 547 bo/d (87 cu m/d) and 4% water production. The rate steadily declined, as expected, to 132 bo/d within 30 days (Fig. 1a [119,157 bytes]).
The water/oil ratio never surpassed 15% during this period. About 50 days following the PCS treatment, water production became negligible, and oil production leveled off to about 94 bo/d.
Based on these production rates, the treatment cost, estimated at $60,600, was recovered within the first 30 days of production.
Because fracture stimulation treatments had not previously been attempted in this region, a point of comparison does not exist for accurately assessing production of this formation with and without the PCS application. However, the economic benefits of stimulating production in an interval that previously produced no revenue are unmistakable.
Cost and production analyses based on PCS applications in other geographic areas have confirmed these benefits.
In another Argentina application within the Lotena formation, a PCS treatment was used to stimulate production in a well where natural production had fallen below 6 bo/d. Following the treatment, production increased to 56 bo/d and gradually decreased over a period of 4 months, leveling off at 13-19 bo/d (Fig. 1b).
During the following 6 months, production remained in that range or higher, and water production remained below 9 bw/d.
Other locationsFavorable results have also been achieved with the PCS system in newly drilled wells in New Mexico and Kansas.
In New Mexico, in April 1997, the PCS technique was used to stimulate oil and gas production in the Brushy Canyon formation (lower part of the Delaware reservoir) of Eddy County, N.M.
This area was a good candidate for the PCS treatment because it contains multiple layers of oil and water throughout the pay zone. Within the Los Medanos field, the Brushy Canyon formation is at a depth of 7,470-7,700 ft. Water-saturated production intervals exist above and below this zone and are separated from it by thin, weak intervals composed of shale.
A stimulation injection volume of 100 bbl will normally penetrate the shale and enter the water zones.
Previous conventional fracture treatments in this area had resulted in water cuts greater than 60%, and continued production was uneconomical because of damaging scale and a subsequent decline in oil and gas production.
During the initial PCS-enhanced stimulation treatment in the Los Medanos field, 33 perforations were shot into the central portion of the pay zone. The treatment included linear-gelled spacers pumped ahead of and behind the PCS for controlling polymerization.
The treatment was designed to place the PCS chemicals half the distance of the total fracture length. After the PCS was placed, fracturing fluid was pumped down the tubing at 10 bbl/min.
In the 60 days after the treatment, cumulative oil production increased 65%, to 35,000 from 19,000 bbl, cumulative gas production increased 122%, to 40 from 18 MMcf, and water production declined 60%, compared to production levels of five offset wells stimulated without PCS.
Fig. 2 [58,260 bytes] compares the average per-well cumulative production of oil, gas, and water in the two PCS-enhanced wells vs. the five conventionally treated wells.
At the end of 90 days of production, total revenue from the PCS-treated wells exceeded $760,350. Treatment cost for the PCS-enhanced stimulation exceeded the cost of conventional fracturing by only $2,800.
After 90 days of production, the five conventionally treated intervals became uneconomical to produce and were plugged and abandoned. Another interval in the well was then completed.
Two years after the treatments, the two PCS-treated wells continue to produce at 75% of the initial rate, with a water cut of 20-25%. This production has generated more than $3 million over the 2 years.
Controlling water was also a challenge for the operator of a southwest Kansas offset well that was not producing commercial quantities of oil. The original well had watered out. A second offset well watered out after an acid treatment. A third well was fractured conventionally and was producing about 32 bo/d and 5 bw/d.
The PCS-treated well is in the Chester formation in Seward County. The producing interval has two lenses, separated by a 4-ft shale stringer. Another shale stringer separates the lower lens from a water-saturated interval. A fracture treatment was designed with the goal of fracturing both lenses, and using the PCS to minimize water production.
The fracture treatment design called for perforations in the upper portion of the sandstone lenses. Linear gel spacer was pumped ahead of and behind the PCS for pH control. After the PCS was placed, fracturing fluid was pumped down the tubing at about 15 bbl/min at 3,500 psi. Treatment cost was about $42,000.
After the well was placed on line, production averaged 140 bo/d and 1,000 Mcfd of gas.
A cost analysis for a 6-month production period indicated a net revenue of $660,600 for the PCS-treated well, nearly 2.5 times the revenue generated by the conventionally treated well (Fig. 3 [59,052 bytes]).
- Dalrymple, E.D., Creel, P., Rohwer, C., and Crabb III, H., "Results of Using a Relative Permeability Modifier with a Fracture Stimulation Treatment," Paper No. SPE 49043, SPE Annual Technical Conference and Exhibition, New Orleans, Sept. 27-30, 1998.
- Dalrymple, E.D., and Creel, P., "Results of Relative Permeability Modifier Combination with Fracture Stimulation Treatments," Southwestern Petroleum Short Course, Lubbock, Tex., Apr. 21-22, 1999.
E. Dwyann Dalrymple is a scientific advisor in the research and development group, conformance technology, of Halliburton Energy Services Inc., Duncan, Okla. His 23 years of experience span all phases of water control and well preparation, conformance control, clay control, and improved oil-recovery methods.
Prentice Creel is a technical specialist who specializes in cementing and conformance technology for Halliburton Energy Services Inc.'s Permian basin business development group and technical team in Odessa, Tex. He has been with Halliburton for 18 years in various operational and technical engineering positions.
Creel holds a BS in engineering from New Mexico State University. He is currently a director for the Trans-Pecos Section of SPE.
Carlos Brocco is a drilling and workover engineer for Pioneer Resources Inc., Buenos Aires. He previously was a drilling and workover engineer for Astrafor (now operated by Pride) and Perz Companc. He has an electrical engineering degree from the Universidad Nacional de Rosario.
Horacio Peacock is a South Latin America technical consultant for Halliburton Energy Services Inc. He specializing in cementing and stimulation services. Since joining Halliburton in 1975, Peacock has worked in locations throughout Argentina, Brazil, and Peru, and has served as a field engineer, district engineer, and service manager.
Peacock has a mechanical engineering degree from the Universidad Catolica de Cordoba.
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