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One of the considerations in hydraulic fracturing treatment optimization in unconventional (shale/tight/ CBM) reservoirs is creating fracture complexity through reducing or possibly eliminating or neutralizing the in-situ stress anisotropy (differential stress) to enhance hydraulic fracture conductivity and connectivity by activating planes of weakness (natural fractures, fissures, faults, cleats, etc.) within the formation in order to create secondary or branch fractures (induced stress-relief fractures) and connect them to the main bi-wing hydraulic fractures. However, actual field experience has shown that some reservoirs under certain treatment designs exhibit excessive fracture complexity due to excessive induced stresses or stress shadowing that can result in pressureout or screenout, and thus, poor well completion and productivity performance. Therefore, it is crucial to identify the reservoir candidates and treatment strategies that are suitable for enhancing fracture complexity to avoid fracturing treatment scenarios that will have an adverse effect on the well productivity. In this work, a three-dimensional hydraulic fracture extension simulator is coupled with a reservoir production simulator to screen for the reservoir candidates and fracturing treatment scenarios that can lead to enhancing fracture complexity, conductivity, and connectivity and positive well production performance. Furthermore, scenarios are identified under which excessive fracture complexity (due to excessive induced stresses or stress shadowing) results in poor well completion performance. The results indicate that fracture complexity can be enhanced under the following treatment scenarios: (1) low-viscosity slickwater with smaller proppant sizes under high treatment rates, (2) hybrid fracture treatment (low-viscosity slickwater containing smaller proppants and low proppant concentrations with high treatment rates followed by viscous treatment fluids containing larger proppants and higher proppant concentrations), (3) simultaneous fracturing of multiple intervals at close spacing, and, (4) out-of-sequence pinpoint fracturing (fracturing Stage 1 and then Stage 3 followed by placing Stage 2 between the previously fractured Stages 1 and 3). It is also revealed that the success of each of the above treatment scenarios is very sensitive to rock brittleness (combination of Young's modulus and Poisson's ratio), magnitude of stress anisotropy, matrix permeability, process zone stress/net extension pressure, fracture gradients, and treatment fluid viscosity and rate.
In this study, a hydro-geomechanical coalbed methane reservoir characterization workflow was applied to multiple multilateral wellbore stability cases from the same coalseam formation. The data from core studies and borehole geophysical logging was integrated to create a full field hydro-mechanical earth model. The models were then used for uncoupled reservoir geomechanical simulation. The uncoupled simulations results were history matched against observed gas and water production rates. The initial and evolved stress tensor from the simulation was used to provide insight into observed horizontal CBM wellbore stability issues including borehole: initial failure, fines generation, and failure during depletion.
Coalbed methane (CBM) in the Western Canadian Basin in Alberta has been identified as a major resource that can add to Canada's energy economy by filling part of the gap left by declining conventional gas reserves. In Alberta, the CBM industry has gone from relatively little activity prior to 2003 (less than 100 wells drilled per year), to more than 18 000 total wells as of 2012 being drilled for CBM, with some wells are comingled gas wells .
In the Mannville coal formations, production rates in vertical wells are typically less than 3000 m3/day. However, some successful horizontal wells have gas production rates greater than 12,000 m3/day. Based on historic data, economic viability of methane extraction from the Mannville formation is believed to be possible only through the drilling of horizontal wells, which provide greater connectivity to the coal reservoir surface . Horizontal wells have been used extensively in the United States for CBM development, but transfer of technologies from the USA to the Mannville formation in the Western Canadian Basin has not been as successful as originally expected.
Several reasons for the limited success of horizontal wells production have been postulated, with geomechanical effects being included. The list of geomechanical effects includes: high stress fields, high stress anisotropy, weak coal, and coal natural fracture (cleat) closure
Fracturing through coiled tubing has progressed considerably since the first job done in 1993. In southeastern Alberta large numbers of wells are being selectively fractured through coiled tubing with mechanical isolation tools. Conventional fracturing techniques may result in small lenses that have the potential to contribute to production being either bypassed, or ineffectively treated. By utilizing coiled tubing and selective fracturing, all contributing zones can be fractured and the full potential of the well realized. Up to eight zones are being treated per well.
This paper will discuss work currently being undertaken with Carbon Dioxide and Nitrogen energized water based fracturing fluids. A summary of work done to date and case histories will be presented. Current and future developments in isolation tools and fracturing fluids will be discussed and the issues regarding geographical technology transfer examined.
The results of pumping fluids containing abrasive particulates at high pump rates through the coiled tubing are discussed with emphasis on abrasion of the pipe, fatigue and pressure limitations. Specific additional safety considerations are outlined and discussed.
As of year end 1999 approximately 700 wells1 have been fractured industry wide using coiled tubing as a conduit. The number of zones per well varies from 1 to 8 and the total number of fracture treatments performed on these 700 wells is over 5,100. This technology has been predominantly limited to the shallow gas fields of southeastern Alberta.
It is difficult to ascertain when the first coiled tubing fracture treatment took place but a job was carried out in south-eastern Alberta2 in February, 1993 where a 25 tonne treatment was pumped through 73.0 mm (2-7/8 inch) coiled tubing at 3.0 m3/ minute (18.9 bbl/min). The procedure was similar to that performed today with the exception that the coiled tubing was stung into a permanent packer.
While the operational feasibility of fracturing through coiled tubing had been proven the commercial viability of the technique was still questionable and further development shelved. In 1997 the technique was refined for multi-zone fracturing3 which significantly impacted the commercial viability.
The work described in this paper has been performed on gas wells and carried out with the well live. Standard practice is to fracture from the bottom zone up. Initially only one well was fractured per day (up to 8 zones) but this has progressed to two wells per day and the feasibility of three wells per day is being evaluated. Coiled tubing is an excellent medium for the operation as a rig would have to strip out of the hole with the well live. After fracturing the wells are cleaned out periodically with a shallow coiled tubing unit until sand production stops. Indications are that utilizing coiled tubing fracturing over conventional methods may halve the number of cleanouts in certain circumstances.
Other driving forces for fracturing through coiled tubing are the desire to protect old (and/or corroded) casing and completion jewelry from the high pressures and potential erosion associated with the treatment.
For the work evaluated in this study cross-linked water based fracturing fluids are predominantly used in the operation. In general, between five and twenty metric tons of sand is placed at concentrations up to 1800 kg/m3. The fluid is energized with liquid CO2 or gaseous Nitrogen to aid in flowback after the treatment. Liquid CO2 was used in over 95% of the fracture treatments reviewed. Forced closure has been used on some of the treatments, thus, requiring immediate flowback. Pump rates of between 1.2 and 2.5 m3/minute (7.55 to 15.73 bbl/min) are standard.
Thus the solution is independent of the exact position, magnetization, and depth. Magnetization is obtained from the ratio of the profile and model curve variances at the solution point. As mentioned previously, a knowledge of the orthogonality at different points in parameter space is necessary in order to satisfactorily define the range of possible sources for a given solution. Figure 2 demonstrates the degree of dependence between the angle of two opposing contacts for two different values of the depth extent as the width is varied, Clearly the two parameters can be considered independent over a large range for sources with shallow depth extent. These should be spaced in such a way that the sensitivity (the percentage change in the measured values) is approximately constant.