Summary Hydraulic fracturing treatments that use treated water and very low proppant concentrations (commonly referred to as water-fracturing treatments or "waterfracs") have been successful in stimulating low-permeability reservoirs. However, the mechanism by which these treatments provide sufficient conductivity is not well understood. To understand the effects of fracture properties on conductivity, a series of laboratory conductivity experiments was performed with fractured cores from the east Texas Cotton Valley sandstone formation. The results of this study demonstrate that fracture displacement is required for surface asperities to provide residual fracture width and sufficient conductivity in the absence of proppants. However, the conductivity may vary by at least two orders of magnitude, depending on formation properties such as the degree of fracture displacement, the size and distribution of asperities, and rock mechanical properties. In the presence of proppants, the conductivity can be proppant- or asperity-dominated, depending on the proppant concentration, proppant strength, and formation properties. Under asperity-dominated conditions, the conductivity varies significantly and is difficult to predict. Low concentrations of high-strength proppant overcome the uncertainty associated with formation properties and provide proppant-dominated conductivity. The implication of these results is that the success of a water-fracturing treatment is difficult to predict because it will depend significantly on formation properties. This dependence can be overcome by using high-strength proppants or proppants at conventional field concentrations. Introduction Although proppants are routinely used to achieve conductivity during hydraulic fracturing treatments, recent fracturing treatments using treated water and very low proppant concentrations (commonly referred to as water-fracturing treatments or "waterfracs") have been successful in low-permeability reservoirs.1–4 The mechanism by which these treatments provide sufficient conductivity is not well understood. The presence of residual fracture width caused, for example, by surface asperities and proppant bridging, and the lack of damage associated with the use of gels in conventional proppant treatments, are possible explanations.2,5 Residual fracture width has been observed during laboratory experiments6 and field tests7 and can be attributed to the combined effects of surface roughness and fracture displacement.8 The surface asperities are thought to withstand high formation-closure stresses and create sufficient conductivity for wells completed in very low-permeability formations. The low concentrations of proppant are added to supplement the asperities and improve overall fracture conductivity. Factors affecting fracture conductivity and proppant-pack permeability have been reported in the literature. The importance of parameters such as fracture displacement, fracture roughness, mechanical properties, and closure stress on fracture conductivity have been demonstrated in the absence of proppants.9–12 When proppants are present, parameters such as proppant strength, proppant concentration, and closure stress have been shown to be important.13,14 However, these studies were performed with fractured cores in the absence of proppants or with proppant and flat, parallel core faces. No study has addressed the effects of fracture properties on conductivity in the presence of low concentrations of proppant (i.e., conditions that may exist during water-fracturing treatments). This paper investigates the effects of fracture properties on conductivity for a variety of conditions ranging from fractured systems to water-fracturing conditions to conventional proppant fracturing conditions. A series of laboratory conductivity experiments was performed with fractured cores from the east Texas Cotton Valley sandstone formation. Jordan sand and sintered bauxite proppants were used at concentrations of 0, 0.1, and 1.0 lbm/ft2, and the conductivity was measured at effective closure stresses ranging from 1,000 to 7,000 psi. The work investigates the relative influence of proppants and asperities on conductivity and demonstrates the benefits of using proppants. Water-Fracturing Treatments. Water-fracturing treatments discussed in the literature use a water-based fluid containing friction reducer (usually a manmade synthetic polymer, but a low concentration of natural guar polymer is sometimes used as a substitute for the friction reducer), clay stabilizers, and surfactants as necessary. This fluid is intended to serve as the pad fluid and to provide proppant transport. Common water-fracturing treatments involve pumping a pad fluid for the first 50% of the job, followed by a proppant stage where the proppant concentration is held constant at 0.5 lbm/gal. At the end of the job (usually the last 5%, based on fluid volume), the proppant concentration is increased to 2 lbm/gal. The higher proppant concentration is intended to improve connection between the wellbore and the fracture. Some potential problems with water-fracturing treatments include low conductivity and poor proppant transport. In low-permeability formations, low fracture conductivity is not a major limitation to production, provided the conductivity is not too low. The poor proppant transport is caused by the low viscosities of the water-fracturing fluids and results in rapid settling of the proppant particles. This inability to carry proppant a significant distance away from the wellbore can severely limit the effective fracture length. Fracture length is the key variable for initial production potential and ultimate recovery from very low-permeability formations. Therefore, if the proppant does not get transported toward the tip of the fracture, the success of the water-fracturing treatment will depend entirely on the conductivity created by surface asperities or some other mechanism. Experimental Methods Fractured Cores. Sandstone cores from the east Texas Cotton Valley formation were used in this study. The cores (which were obtained from depths ranging from 8,500 to 10,000 ft) had porosities of approximately 12% and permeabilities of approximately 0.05 md. Rock mechanical properties were determined from static triaxial compressive strength tests conducted at ambient temperature and 4,500 psi confining pressure. Young's modulus ranged from 3.6×106 to 7.0×106 psi, and Poisson's ratio was approximately 0.32.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractNew analysis procedures are presented for analyzing the production data of fractured wells in low permeability reservoirs to quantify estimates of the reservoir effective permeability, effective fracture halflength, and average fracture conductivity. The rate-transient based analyses reported in this paper have been used to analyze the production performance of over 200 wells in low permeability reservoirs in North America.Direct comparisons of the fracture properties resulting from conventional crosslinked fluid fractures and low viscosity base fluid ("Water-Frac") treatments in direct offset wells clearly demonstrates that more effective fractures are created in low-permeability reservoirs using the higher viscosity fracturing fluids and large proppant volumes to achieve higher conductivity fractures with greater effective halflengths than are achieved with "Water-Fracs" with little or no proppant.
Hydraulic fracturing treatments using treated water and very low proppant concentrations (" waterfracs") have been successful in stimulating low-permeability reservoirs. However, the mechanism by which these treatments provide sufficient conductivity is not well understood. To understand the effects of hydraulic fractures on conductivity, a series of laboratory conductivity experiments were performed with hydraulically fractured cores from the East Texas Cotton Valley sandstone formation. Jordan sand and sintered bauxite proppants were used at concentrations of 0, 0.1 and 1.0 lb m/ft2, and the conductivity was measured at effective closure stresses ranging from 1,000 to 7,000 psi. The results of this study demonstrate that fracture displacement is required for surface asperities to provide residual fracture width and sufficient conductivity in the absence of proppants. However, the conductivity may vary by at least two orders of magnitude depending on formation properties such as the degree of fracture displacement, the size and distribution of asperities, and rock mechanical properties. In the presence of proppants, the conductivity can be proppant or asperity dominated, depending on the proppant concentration, proppant strength and formation properties. Under asperity dominated conditions, the conductivity varies significantly and is difficult to predict. Low concentrations of high-strength proppant reduce the effects of formation properties and provide proppant dominated conductivity. At conventional proppant concentrations, conductivity experiments performed with flat, parallel core faces tend to overestimate the conductivity observed with hydraulic fractures. Actual hydraulic fracture conductivity may be as much as an order of magnitude lower in the presence of low strength proppant. An important implication of this study is that the success of a " waterfrac" treatment is difficult to predict because it will depend significantly on formation properties. This dependence can be overcome by using high strength proppants or proppants at conventional field concentrations. Introduction Although proppants are routinely used to achieve conductivity during hydraulic fracturing treatments, recent fracturing treatments using treated water and very low proppant concentrations (" waterfracs") have been successful in low-permeability reservoirs1–4. The mechanism by which these treatments provide sufficient conductivity is not well understood. The presence of residual fracture width caused, for example, by surface asperities and proppant bridging and the lack of damage associated with the use of gels in conventional proppant treatments are possible explanations2,5. Residual fracture width has been observed during laboratory experiments6 and field tests7 and can be attributed to the combined effects of surface roughness and fracture displacement8. The surface asperities are thought to withstand high formation closure stresses and create sufficient conductivity for wells completed in very low-permeability formations. The low concentrations of proppant are added to supplement the asperities and improve overall fracture conductivity. Factors affecting the conductivity of hydraulic fractures and proppant packs have been reported in the literature. The importance of parameters such as fracture displacement, fracture roughness, mechanical properties, and closure stress on fracture conductivity have been demonstrated in the absence of proppants9–12. When proppants are present, parameters such as proppant strength, proppant concentration, and closure stress have been shown to be important13–14. However, these studies were performed with hydraulic fracture in the absence of proppants or with proppant and flat, parallel core faces. No study has addressed the effects of hydraulic fractures on conductivity in the presence of low concentrations of proppant (i.e., conditions that may exist during waterfrac treatments).
This paper was prepared for presentation at the 1999 SPE Mid-Continent Operations Symposium held in Oklahoma City, Oklahoma, 28-31 March 1999.
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.
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