Oilfield produced water usually comprises both the formation water and injected fluids from prior treatments. Produced water may be environmentally hazardous and usually contains bacteria, hydrocarbons, and high levels of dissolved salts. As such, the proper disposal of produced water is often expensive. Meanwhile, fresh water used to formulate oilfield treatment fluids is becoming more costly and more difficult to obtain. Operators, as well as service companies, have therefore shown a strong desire to use produced water in field operations to reduce costs. Consequently, a series of laboratory experiments have been performed to optimize the viscosity profile of fracturing fluids prepared with produced water. Preparation of polysaccharide-based fracturing fluids with produced water frequently resulted in fluids with poor viscosity profiles despite the fact that the produced water was pretreated with biocide. Furthermore, the problem could not be resolved by just adding more biocide. In a number of representative cases, the guar-based fracturing fluids, prepared with produced water and regular biocide, quickly lost their viscosity after hydration, possibly because of the degradation of the guar by the bacterial enzymes in the produced water. A new fluid stabilizer was recently invented to address the problem, and it was observed that the addition of the stabilizer dramatically extended the lifetime of the polysaccharide-based fracturing fluids prepared with produced water. The fluid stabilizer was simply added to produced water prior to mixing the polymer. The polysaccharide-based fluids prepared with the stabilizer-treated produced water showed stable viscosity profiles at both surface and bottomhole temperatures. The use of the fluid stabilizer has greatly enhanced the fluid performance and job efficiency since its initial introduction in the field in June 2008 and was implemented in about 80 successful fracturing and sand control jobs by the end of 2008. The invention and successful application of the fluid stabilizer have reduced the operating costs for the operators and service companies. At the same time, this new technology has also helped improve the environment by cutting the fresh water usage in the field. This paper will discuss the chemistry, experimental studies, and case histories. Background Oilfield produced water is a term used in the oil industry to describe the water that is produced along with the oil and/or gas, and it may contain formation water, flowback fluids, surface water, and water from any other sources. Produced water is in good contact with various environmental elements such as air, soil, formation, and contaminated water tanks, and it is therefore not surprising that produced water often contains high level of bacteria and/or bacterial enzymes as bacteria are ubiquitous in almost every habitat on Earth. Formation water usually consists of salty water that may be the ancient seawater trapped in the formation. On the other hand, produced water stored in tanks or ponds is often subjected to evaporation that can further increase the salt concentration in the water. Measured by volume, produced water is the largest waste generated during the production process, and the volume of produced water can be several times that of hydrocarbons produced (Stephenson, 1992). The potential benefit of using such produced water, if feasible, for oilfield operations is at least twofold. First, the cost related to the proper disposal of produced water can be reduced. Produced water usually contains high levels of salt and hardness as well as bacteria. Without proper treatment, produced water is environmentally hazardous. It can be, however, costly to clean up produced water following the local, state, or federal regulations. If produced water can be treated in situ and then used to prepare fracturing fluids, the operating cost is expected to decrease. Second, as large amount of fresh water is used for oilfield operations such as water flooding, subterranean fracturing, etc. (Gleick, 1994), reusing produced water can cut the consumption of fresh water that is becoming more costly and more difficult to obtain since neighboring residents and municipal and state governments are putting more restrictions on water availability from either surface or subsurface aquifers. Operators, as well as service companies, are therefore interested in using produced water to reduce operating costs and gain competitive edges.

fax 01-972-952-9435.Abstract CO2 based fluids are commonly used to fracture stimulate formations with low reservoir pressure as well as formations that are more sensitive to water treatments (high capillary pressure, swelling clays etc). In particular, the Frontier Formation located in Bighorn Basin, Wyoming, has seen a variety of stimulation fluids used over the past years with varying degrees of success. When dealing with water sensitive formations, a common practice has been to use oilbased fluids. However, fluids of this nature can have detrimental effects on gas zones with low reservoir pressure and this might be the reason for erratic well performance of previously treated Frontier completions. It has also been determined that oil-based fluids can alter the reservoir wettability and hence cause formation damage. With this in mind and considering the environmental and economical benefits of using a water-based fracturing fluid, a novel viscoelastic surfactant based, CO2-compatible, high foam quality (>60%) fluid was proposed as the main fracturing fluid. This paper will discuss the first application of this visco-elastic based fluid on wells in Park County, Wyoming. This paper will discuss stimulation with the new fluid and how pin-point pressure measurement enabled the operator to make informed decisions to define fracturing/completion strategy. We also present the additional benefits of incorporating existing dipole sonic tool information to calibrate "in-situ" stress, Young's Modulus and Poisson's ratio. Finally, a production history match is conducted on wells treated with the new fluid.

The goal of an acid fracture treatment is to generate a highly conductive pathway of sufficient length from the reservoir to the wellbore. Depth of penetration of live acid is the critical factor in determining the success of an acid-fracturing treatment. Depth of penetration is controlled by the acid reaction rate, leakoff, and stimulation rate. Acid reaction rate is a function of several factors, the most important of which is the reservoir temperature. Yet another concern, in acid fracturing in long carbonate intervals, is attaining the necessary diversion to ensure that multiple sets of perforations are adequately stimulated. Because of their high solubility and highly fractured/vugular nature, carbonate reservoirs in the Permian Basin show excellent response to acid fracturing treatments. However, inadequate diversion can leave substantial portions of the reservoir untreated. Different acid systems have been developed to counter the problems in acid fracture stimulations. Chemical and mechanical means of diversion have been used with varying degrees of success. Likewise, there have been many attempts made in retarding the reaction rates of hydrochloric acids in high temperature environments. Recently, there has been a large number of highly successful acid fracture treatments in the Permian Basin incorporating a combination of new polymer-free self-diverting acid combined with an existing acid-oil emulsion technology. This paper will discuss a combination of technologies, which has recently been applied successfully in the Strawn formation in Terrell County, Texas. It will also focus on what is being done to mitigate the affect of high temperature on hydrochloric acid's reaction rate. It will further develop improvements in reservoir characterization and pay zone determination, which has been improved by the utilization of resistivity imaging logs. Some examples presented contain information from radioactive tracers and production logs, which are fundamental to understanding how good zonal coverage was achieved using different techniques. Additionally production analysis has been conducted to determine the effective fracture half-length and etched conductivity. Finally, a relative comparison between the old and new completion methodologies is made taking into account that the new completion practices have only been applied in full combination since 2004. Background The Permian Basin in West Texas, USA is renowned for its prolific carbonate reservoirs. Covering an area in excess of 86,000 square miles, the basin is both vast and diverse in reservoir types and qualities. Even within specific areas and reservoirs, the degree of heterogeneity is broad due to the depositional and diagenetic history of the basin. Reservoir heterogeneity complicates every aspect of a well's life, from drilling to completion. New technologies and methods have greatly enhanced production by offering data and solutions that were not available in previous years. Likewise, technologies often considered archaic by today's fast paced standards continue to pay dividends when properly integrated with the new technology and enhanced methodology, which is constantly developing. Although relatively new with the Permian Basin timeline, completions in the Strawn formation in Terrell County have endured just such an evolutionary process. Production from the Strawn Formation in Terrell County increased significantly in the 1990's with the discovery of the Abilene Christian University (ACU) Strawn and Deer Canyon Strawn fields. Subsequent development of the Strawn over the past decade has resulted in a better understanding of reservoir characteristics and improved completion techniques. This maturation has allowed better decision-making as well as more efficient recovery of reserves, both of which have become increasingly necessary as depletion occurs throughout the field.

fax 01-972-952-9435. AbstractThis paper discusses the selection criteria, design methodology, and analysis of hydraulic fracturing treatments pumped using a solids-free, liquid CO 2 foam-based viscoelastic surfactant (VES) fluid system in Morrow Sand reservoirs located in Southeast New Mexico (SENM).The wells discussed in the paper were completed in various Morrow Sand intervals around 10,500 ft with an average Bottom Hole Static Temperature (BHST) of 190 o F. Wellbore completion constraints combined with reservoir parameters inclusive of low-pressured water sensitive formations, high rock Youngs' Modulus and unpredictable occurrence of water-bearing zones, lead to the selection of foamed VES fluids. This technology was successfully applied in the Morrow Sands in Eddy County of SENM. Fracture geometry analysis using surface treating pressures, radioactive tracers and production data, showed height growth containment and longer effective fracture half-lengths. Results also indicated successful stimulation past the cement squeezed intervals and temporary liner tie-backs run in to overcome lower pressure constraints. Finally, lower friction pressures helped in designing economical fracture stimulations for mature wellbores thereby generating an opportunity to recover otherwise bypassed hydrocarbon reserves.

fax 01-972-952-9435. AbstractSince the horizontal lateral Bakken dolomite play began in 1999 in eastern Montana, more than 330 wells have been permitted and more than 200 wells are now producing. The lateral play began in Richland County, Montana, and the success there is now accelerating the transfer of technology to the North Dakota side of the Bakken trend and is attracting several new and existing operators to the area. Different drilling and completion techniques have been tried since the start of the play with different degrees of success.