Estimates of worldwide oilfield water production are as high as 300 to 400 million barrels of water per day (bwpd), while oil production is only 75 million barrels per day (bopd)1. Put in different terms: for every 1 bopd produced, our industry produces approximately 4 to 6 bwpd, and for many depleted areas of the world this oil-to-water ratio can be much higher, reaching up to 1:100. Excessive water production from oil and gas wells can cause serious reductions in well productivity and significantly increases operating expenses. In an attempt to reduce the oil industry's dilemma related to water production, there has recently been an increased interest in water control treatments using relative permeability modifiers (RPM). A new and unique RPM polymer is yielding significant economic benefits by increasing hydrocarbon production from treated wells. Generally, RPMs are designed to control water production from high permeability streaks or due to coning issues. The polymer adheres to formation rock exposing its hydrophilic (water-loving) side to the pore throats. The RPM restricts water movement through the pore throat by reducing the effective size of the throat in the presence of water and by increasing drag on formation water flowing through the reservoir matrix. Because it deforms in the presence of hydrocarbons, the RPM typically does not adversely effect oil or gas flow. The newly developed RPM (along with careful selection of well candidates, correct treatment design, and proper placement) is helping increase the success of RPM treatments. This paper will discuss the application and economic benefits from using the new low-risk RPM polymer. Multi-well RPM matrix treatments were performed on offshore Gulf of Mexico (GoM) frac-packed and gravel-packed wells. One particular RPM treated gas well showed a significant decrease in water production, a five fold increase in gas production and double the amount of oil. Payout for the entire treatment was just 7 days. Introduction Oil and gas well profitability is often compromised by excessive water production. Decreased well productivity and increased operating expenses are among the inherent problems associated with excessive water production. In addition, environmental concerns and local/federal regulatory agencies are making disposal of produced water increasingly difficult. The cost of handling produced water ranges from less than $0.10 to more than $4 per barrel of water produced, costing the industry billions of dollars per year. Mature field development is driving the need for effective water management technologies in our industry, especially as marginal fields become more common and environmental regulations become more stringent. Numerous methods and attempts have been made over the years to control water production; however the difficulty begins with understanding the source of the water (i.e., channels behind casing, casing leaks, coning, encroachment, water breakthrough, natural or induced fractures, or high perm streaks). If the water source can be easily identified, then mechanical intervention (such as bridge plugs and/or various cement system solutions) can often be successfully implemented. Other options include the use of various products such as polymer blocking, silicate and phenol-formaldehyde gels but each of these methods must be applied only after the water source is identified. Then, the problem zone needs to be isolated to prevent the unintentional placement of the blocking/damaging chemicals into the hydrocarbon producing sections of the zone. Herein lies the crux of the problem, locating the water source can be costly, time-consuming and, at times can even include guesswork in diagnosing the water source and/or water-producing pathway. If the water source diagnosis is incorrect and a subsequent treatment is misapplied to the hydrocarbon interval, the effects on production can be devastating.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAs deepwater exploration projects in the Gulf of Mexico and other offshore areas have gained momentum, development activities in all areas of drilling, completion and production of these wells have faced significant challenges. One key area of concern in completion of these wells is the design, application and compatibility of the fracturing fluid to ensure optimum well performance. Deepwater engineering design and application of fracturing fluids are presented with some unique challenges in well depths that can exceed 20,000 ft with pore pressures greater than 20,000 psi. One major issue facing deepwater fracturing is generating enough bottomhole treating pressure to create a hydraulic fracture at the sandface without exceeding the limitations of the hydraulic equipment at the surface. In order to overcome these surface hydraulic equipment limitations and still create the needed hydraulic fracturing pressure at the sandface, weighted fracturing fluid formulations have been developed to address these issues. Furthermore, due to the increased travel distance to the sandface and the extreme temperature ranges that the fluid is exposed from the mudline to the BHT, the fracturing fluid must have flexibility to be designed to meet specific density, extended crosslink delay times, friction pressures, and compatibility specifications.This paper summarizes a study to formulate a sodium bromide weighted, delayed crosslink fracturing fluid system to meet the fluid and engineering guidelines for the fracturing application. After baseline fluid formulation studies with the weighted sodium bromide, delayed crosslink fracturing fluid system were designed, rheological performance with breakers at BHT were run, stacked cell regained conductivity lab measurements were performed and friction pressures were determined. Additional studies were also conducted with this weighted fracturing fluid to determine compatibility with the well's produced crude oil and returned permeability studies utilizing formation cores.
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