Robert S. Taylor

Liquid Petroleum Gas Fracturing Fluids for Unconventional Gas Reservoirs

Unconventional gas reservoirs, including tight gas, shale gas and coalbed methane, are becoming a critically important component of the current and future gas supply. However, these reservoirs often present unique stimulation challenges. The use of water-based fracturing fluids in low permeability reservoirs may result in loss of effective frac half-length caused by phase trapping associated with the retention of the introduced water into the formation. This problem is increased by the water-wet nature of most tight gas reservoirs (where no initial liquid hydrocarbon saturation is, or ever has been, present) because of the strong spreading coefficient of water in such a situation. The retention of increased water saturation in the pore system can restrict the flow of produced gaseous hydrocarbons such as methane. Capillary pressures of 10 to 20 MPa or higher can be present in low permeability formations at low water saturation levels. The inability to generate sufficient capillary drawdown force using the natural reservoir drawdown pressure can result in extended fluid recovery times, or permanent loss of effective fracture half-length. Furthermore, use of water in subnormally saturated reservoirs may also reduce permeability and associated gas flow through a permanent increase in water saturation of the reservoir. Secondary costs, such as rig time for swabbing, can add to the negative economic impact. Gelled liquid petroleum gas-based fracturing fluids are designed to address phase trapping concerns by replacement of water with a mixture of liquid petroleum gas (LPG) and a volatile hydrocarbon fluid. Once the well is drawn down for flowback, some of the LPG portion of the fluid may be produced back as a gas, dependent upon temperature and pressure. The remaining LPG remains dissolved in the hydrocarbon fluid and is produced back as a miscible mixture using a methane drive mechanism. By eliminating water and having LPG as up to 80 - 90% of the total fluid system, cleanup is greatly facilitated, even in wells having very low permeability and reservoir pressure. The effects of fracturing fluid retention on gas flow in the fracture face can be as important as fracture conductivity when designing a treatment. It is possible to have a conductive fracture with good half-length in the desired productive zone and still not realize economic or optimum gas production if phase trapping and/or relative permeability effects are restricting gas flow.

Enhanced Aqueous Fracturing Fluid Recovery from Tight Gas Formations : Foamed CO2 Pre-pad Fracturing Fluid and More Effective Surfactant Systems

Underpressured, tight, deep formations represent a challenge in terms of recovery of fracturing fluids. CO 2 , N 2 and binary high quality foams are widely used in this type of reservoir due to their capacity to energize the fluid and improve total flowback volume and rate. Surfactants designed to reduce surface and interfacial tension are also a key element in the design of fluid systems to enhance recovery and reduce entrapment of fluid barriers within the formation. Enhanced fluid recovery improves overall completions economics due to less total treatment cost and less time required for flowing back fluids. The most important benefit is achieving a less damaged proppant pack, resulting in higher fracture conductivity. This document will discuss the application of CO 2 foamed fluids and surfactants to enhance fracturing fluid recovery and other techniques adopted by one operator in the Wild River Field to improve completion practices.

Prevention of Refinery Tower Plugging by Residual Oil Gellant Chemicals in Crude-Pilot Plant Evaluation of Alternative Oil Gellants

Earlier work by the authors (1) described refinery plugging caused by volatile phosphorus components originating from phosphate ester oil gellants. Also documented were two successful field trials of new phosphonate ester oil gellants which were shown to address this problem. In a later work (2) the authors presented the results of additional field testing of phosphonate ester gellants directed at the optimization of cost and performance. In addition to the phosphonate ester systems previously tested, new modified phosphate ester systems will also become commercial. These modified phosphate esters also reduce volatile phosphorus according to ASTM D-86 distillation testing. However, several questions required further investigation. One of these is the comparative ability of phosphonate and modified phosphate esters to control volatile phosphorus and tower fouling at higher temperatures in the presence of steam. Distillations used to evaluate volatile phosphorus to date have had a 250°C endpoint and did not include water. Another continuing area of concern has been organic halide formation under distillation tower conditions. Although no organic halides were detected in either of the two initial field trials reported earlier (1) , further testing under more realistic conditions was required. To address these questions in the most meaningful way possible, full-scale pilot plant testing was conducted over several days with flowback captured after actual fracturing treatments. Fouling of a tray inserted in the pilot plant distillation tower was measured as well as fouling of the packing material. In addition, any changes in operating parameters such as rate, temperature or pressure over the time of each test were noted, as these could also be indicative of fouling. This paper presents the conclusions of this testing and should serve as a guide to the selection of oil gellant systems for the reduction of refinery tower and heat exchanger fouling.

Total Phosphorus Recovery in Flowback Fluids After Gelled Hydrocarbon Fracturing Fluid Treatments

A previous work described refinery plugging caused by volatile phosphorus components originating from phosphate ester oil gellants. Also documented were two successful field trials of new phosphonate ester oil gellants shown to address this problem. Another paper presented the results of additional field testing of phosphonate ester gellants directed at the optimization of cost and performance. A maximum of 0.5 ppm volatile phosphorus in crude specification has been proposed to address costly unplanned refinery shutdowns. This specification is based on what is considered achievable through a combination of new chemistry and typical field dilution. However, this specification is based on average concentrations of phosphorus free to begin with. In some flowback studies, total and resulting volatile phosphorus concentrations greatly in excess of that added have been observed. In addition, refinery plugging is more the result of total phosphorus throughput than peak concentrations at any one point. Therefore, an understanding of total phosphorus recovery in addition to peak concentrations is needed. The objectives of this paper are to study: 1. Total percent recovery of phosphorus originally added as phosphorus based gellant; 2. Total percent recovery of volatile phosphorus as a function of total phosphorus; 3. Peak concentrations of total and volatile phosphorus; 4. Phosphorus concentrations in new and reused fracturing fluids before the addition of gellants; and, 5. Potential exp)lanations for phosphorus concentrations significantly higher than those originally added, which include phosphorus removal resulting in a positive/negative initial mass balance and long-term phosphorus removal with respect to overall mass balance.

Prevention of Refinery Plugging by Residual Oil Gellant Chemicals in Crude-Optimization of Phosphonate Ester Oil Gellants

Aostract Previous research (1, 2) described refinery plugging caused by volatile phosphorus components originating from phosphate ester oil gellants. Also documented were two successful field trials of new phosphonate ester oil gellants used to address this problem. In this paper, results of additional field testing are presented as a final step to broad field application. The objectives of this additional work were to optimize cost and performance, investigate any remaining questions, and establish quality control specifications based on both performance testing and NMR compositional analysis. The synthesis methodology of this new molecule has been refined as a means to reducing final production costs. One objective of the additional field testing was to ensure both operational performance and the ability to control volatile phosphorus while continuing to meet the standards of the first two field trials. Several questions also needed further investigation. One issue was the ability of phosphonate esters to control volatile phosphorus at higher temperatures. Distillations used to evaluate volatile phosphorus to date have had a 250°c C end point. This temperature was chosen because it represents the approximate temperature experienced at the distillation tower trays where plugging has been observed from components condensing from the gas phase. However, the actual peak temperature in the tower bottom is closer to 350° C. This higher temperature is the actual temperature at which decomposition or volatilization will occur. Therefore, to more fully understand our ability to control volatile phosphorus, distillations were conducted with a 350° C end point. Volatile and total phosphorus to both 250° C and 350° C end points are reported. Another continuing area of concern has been organic halide formation under distillation tower conditions. Although no organic halides were detected in either of the two initial field trials. further testing was conducted during the additional field trials reported in this paper. Finally, quality control methods have been established based on both performance testing and compositional analysis determined using NMR. Overall conclusions are drawn in preparation for broad field implementation regarding: • Ability to control volatile and total phosphorus; • Ability to prevent organic halide formation; • Cost and availability; • Rheology and CO 2 compatibility; • Temperature stability; • Field handling and typical concentration ranges; and, • Quality control specifications based on performance testing and NMR analysis.

Enhanced Aqueous Fracturing Fluid Recovery From Tight Gas Formations: Foamed CO Pre-Pad Fracturing Fluid and More Effective Surfactant Systems

Underpressured, tight, deep formations represent a challenge in terms of recovery of fracturing fluids. CO 2 , N 2 and binary high quality foams are widely used in this type of reservoir due to their capacity to energize the fluid and improve total flowback volume and rate. Surfactants designed to reduce surface and interfacial tension are also a key element in the design of fluid systems to enhance recovery and reduce entrapment of fluid barriers within the formation. Enhanced fluid recovery improves overall completions economics due to less total treatment cost and less time required for flowing back fluids. The most important benefit is achieving a less damaged proppant pack, resulting in higher fracture conductivity. This document will discuss the application of CO 2 foamed fluids and surfactants to enhance fracturing fluid recovery and other techniques adopted by one operator in the Wild River Field to improve completion practices.

Optimum Hydrocarbon Fluid Composition for Use in CO Miscible Hydrocarbon Fracturing Fluids and Methods of Core Evaluation

Previous studies(1-4) described the theory and application of CO 2 miscible hydrocarbon fracturing fluids for gas well stimulation. These fluids are ideally suited to gas reservoirs susceptible to phase trapping resulting from high capillary pressures when water-based fluids are used. Gas reservoirs particularly prone to phase trapping are those with in situ permeability less than 0.1 mD, those with initial water saturations less than what would be expected from normal capillary equilibrium (subnormally water saturated) and those that are under pressured. Such reservoirs represent a growing proportion of the market. This, combined with increased gas prices, creates a strong need for an optimized gas well fracturing fluid system. Hydrocarbon-based fracturing fluids present an ideal solution to phase trapping concerns associated with water-based fluids provided the hydrocarbon fluid can be effectively and quickly removed from the formation after the fracturing treatment. This paper investigates in more depth what constitutes an ideal hydrocarbon-base oil for this application. This involves consideration of many factors including cleanup mechanisms, safety, cost and capability to be gelled and broken. In order to meaningfully evaluate fluid clean up, regained core permeability evaluations must be conducted by accurately duplicating downhole conditions. This paper presents testing methodologies designed to achieve this goal. To illustrate the need for these methodologies, the applicable phase behaviour and fluid displacement mechanisms by which these fluid systems operate are discussed. Topics covered will include: Methane drive fluid recovery mechanism involving the use of CO 2 with hydrocarbons and resulting effect on interfacial tension (IFT). • Secondary recovery mechanism based on vapour pressure of light hydrocarbons resulting in their being produced back in the gas phase with methane. • Application of these concepts to address phase trapping in low-permeability gas reservoirs and how these effects are accentuated in formations that may be subnormally water-saturated, have low reservoir pressure or have low permeability. • The need to simulate downhole conditions accurately to properly represent the recovery mechanisms. This includes duplication of temperature, pressure and fluid-loss mechanisms. Duplicating leakoff is the key to representative duplication of phenomena at the fracture face. • Compare nitrogen to methane for reference and fluid recoveries and discuss why it is necessary to use methane to obtain proper simulation and modelling of the actual field performance of the fracture fluids. To illustrate fluid performance and demonstrate test methodologies, results of a regain permeability evaluation conducted with the optimum fluid and test methodologies discussed will be presented. It will be shown that in a formation known to be highly sensitive to water-based fluid retention (phase trapping), 100% regain permeability can be achieved at a minimal 140 kPa of applied drawdown pressure.