Well planning in mature fields can be challenging as the more marginal reserves are targeted. Hydraulic fracture stimulation is a key technology to access multiple reservoir layers and thereby maximize recovery. However, fracture propagation in low porosity carbonates may be strongly confined because of high tensile strengths in bounding layers. The strong confinement can impede vertical fracture propagation and the ability to access reservoir units adjacent to the initiation interval. Understanding vertical hydraulic fracture growth through low porosity layers improves the hydraulic fracture design, enhances reservoir deliverability potential and enables the identification of infill well potential and intervention opportunities.The South Arne field is located in the northern part of the Danish sector of the North Sea. The Tor and Ekofisk formations are high porosity/low permeability chalks with low to moderate natural fracturing. Porosities may reach 45%, but a hard low porosity interval of 10% or less at the bottom of the Ekofisk formation separates and partially compartmentalizes (horizontally) the two formations. A series of indirect tensile strength measurements on South Arne cores were conducted. The measurements verified a suspected exponential increase in tensile strength at low porosities, essentially causing the tensile strength to exceed 1,500 psi in some cases.Recent 4D seismic surveys have enabled separate sweep patterns for each reservoir unit to be mapped and indicate that the sweep is much less efficient in the Ekofisk. This supports that the hydraulic fracture stimulation treatments initiated in the Tor formation are not accessing the upper units to the degree previously assumed and it appears that connection is occurring via pre-existing faults and/or natural fractures. The hydraulic fractures propagate nearly longitudinal to the wellbore, guided by regional stresses, with limited height growth. However, production effects, specifically compaction induced by draw down, may perturb the stress field sufficiently so that the preferred alignment is not achieved, further reducing sweep efficiency. This is indicated by 3D coupled geomechanical modeling and is corroborated by 4D seismic observations.
Multi-stage/multi-cluster hydraulic fracturing in horizontal wellbores is a key technology driving the development of unconventional resources in North America. It has been observed that complex fracture behavior can result from hydraulic fracture stimulation in these unconventional horizontal wells. Given the rapid pace of development, many operators strive to standardize their completion program to drive consistency, and efficiency, in operations and well performance. Unfortunately, the hydraulic fracture treatments may not be properly designed to maximize well deliverability, but instead focus on maximizing contacted reservoir volume (CRV). Generating fracture complexity is important in unconventional reservoirs, but maximum reservoir contact does not necessarily translate to an effectively stimulated reservoir with conductive fracture paths back to the wellbore. Hydraulic fracture modeling in resource plays is challenging and often reduced to rules of thumb and design concepts taken from other shale plays. Key parameters that should be considered to maximize production in unconventional reservoirs are not dissimilar to the key parameters proven successful time and again in conventional completion designs and fracturing treatments. The need for improved proppant pack permeability and fracture conductivity in unconventional wells has been well documented. However, there are additional completion and design considerations for unconventional wells such as natural fracture saturation, mid-field fracture complexity (MFFC), mechanical fracture interaction and transverse fracture production interference. This paper summarizes a number of important considerations and key parameters that are necessary to design successful hydraulic fracture treatments and enhance productivity in unconventional wells. Application and considerations of these parameters will help provide the operator with a systematic, engineering based design method for optimizing multistage/multi-cluster hydraulic fracture treatments in horizontal wellbores.
This manuscript will outline the stimulation design criteria for wells in the Lobo Trend in south Texas and fracture design changes based on post fracture production analysis using commercial software. Production data will be modeled with the corresponding fracture geometry. Model results will be used as the benchmark to discuss fracture design changes and the effect on well performance. Case histories will focus on tight gas sands with reservoir quality ranging from 0.05 to 1.5 md with some pressure depletion. Multiphase flow effects in areas with higher water production will be investigated. Some discussion will focus on the details of calibrating fracture model inputs using open hole logs, radioactive surveys, sonic logs, production logging tools and mini-frac analysis. Results comparing post fracture well production, utilizing a pseudo 3D fracture design model and industry available production matching models, will show the effects of permeability, pressure depletion and multiphase flow effects on well performance. Understanding this information will allow the stimulation design engineer to better predict how geometry and fracture conductivity will alter well performance under varying reservoir conditions. With this knowledge, the engineer can better design ‘fit for purpose’ treatments, including those that may require extreme design changes in order to improve gas reserve recovery. Introduction The Wilcox (Lobo) trend in Webb and Zapata counties in south Texas is a series of geopressured, low permeability sands with an average depth from 5,000 to 12,000 ft. The Wilcox (Lobo) section consists of a sequence of stacked Paleocene age sands and shales overlain by the Lower Wilcox shale of Eocene Age. Extensive faulting, present in the Lobo section, has resulted in a slump complex of rotated fault blocks. The Lobo trend extends from Webb and Zapata counties to the south and west into Mexico. Permeability ranges from less than 0.1 md to 1.5 md. Figure 1 shows the location of the Lobo fields adjacent to the Mexico-USA border in south Texas.1 As an operator in this prolific gas producing area in south Texas, implementing effective hydraulic fracture treatments is a requirement in order for Conoco to economically produce the low permeability sands in the Lobo trend. This paper describes the engineering activities that were part of the development of a process to design and implement a pseudo three-dimensional (P3-D) fracture-modeling program in the Lobo trend in south Texas. The technique of hydraulically fracturing a formation to increase production rates and available reserves to commercial levels is a common practice within the petroleum industry. From industry surveys in the 1990's, approximately 56% of the wells drilled in the various geographic areas of the United States of America require fracture stimulation.2 The placement of a conductive fracture in the producing sands requires an optimal proppant fracture design process and proper field execution of the design. The engineering tools available for proppant fracture design have evolved during the past two decades. In the early 1980's, two primary mathematical models were developed and refined for modeling the complex hydraulic fracturing process. One model developed by Khristianovich and Zheltov3 incorporates the assumption of a rectangular shape in the vertical cross section of the fracture. A second model developed by Perkins and Kern4 and modified by Nordgren5 incorporates the assumption of an elliptical shape in the vertical cross section of the fracture. These two-dimensional (2-D) fracture models that assume a constant height vertical fracture have been widely used in the petroleum industry. Comparisons of these 2-D fracture models6 indicate that both models adequately agree with field data and that both models need to take into account changes in instantaneous shut-in pressure during treatments.
A method to convert multiple shot section open hole completions into cased hole completions has been developed and tested. This method provides zonal isolation between shot sections thus helping prevent injection fluid loss to non-pay intervals. The process, called "Puddle-Pack", involves formulating a permeable resin fill material and placing the material in the shot open hole to fill the large voids. The excess material is then drilled out and underreamed to allow a liner to be run and cemented in place. This paper details the necessity for the development of the process, design requirements, laboratory pretesting of the sand-resin mixture, remedial procedures, data demonstrating zonal isolation and profile improvement, and economic advantages of converting these wells to cased hole completions.
A significant reduction of drilling and completion costs in the Eumont and Jalmat Fields of Lea County, New Mexico has resulted in the continuation of Conoco's development program in a soft gas price environment. Average 1995 costs for drilling, completion and facilities have been reduced to $180,000 for single zone completion wells and $240,000 for two completion wells. This paper focused on the process and equipment changes that resulted in the cost improvements as well as the method used to identify the improvements. Introduction Conoco Inc. operates ninety-five (95) active gas wells in the Eumont and Jalmat Fields of Lea County, New Mexico shown in Figure 1. Combined oil and gas rates from the wells are 25 BOPD and 28,719 MCFPD. Gas production is from the Permian age Yates, Seven Rivers, and Queen formations. Over the past three years, Conoco has maintained an active development program yielding 10 MMBOE's of reserve additions illustrated in Figure 2. During the period from 1993 to 1995, Conoco Inc. drilled and/or recompleted 60 wells to the Eumont and Jalmat gas pools. As the more economically attractive projects were finished, cost containment became increasingly important to ensure profitability and ensure continuation of the program. Additionally, lower gas prices during 1995 intensified cost control requirements. Conoco Inc.'s Hobbs Operating Unit met the challenge by blending the robust skills of a multi-discipline team. As seen in Figure 3, the team identified completion processes and equipment specification changes that resulted in 37% and 27% well cost reductions for single and two zone wells, respectively. Reservoir Description The Yates, Seven Rivers, and Queen Formations are mostly dolomite with inter-bedded sandstone lenses at depths ranging from 2,600' to 3,600'. Recent development has primarily been in the gas productive inter-bedded sand lenses shown on the type log in Figure 4. These zones are from 250' to 500' thick with permeabilities and porosities ranging from 1 to 12 md and 4% to 18% respectively. Reservoir pressure of sand zones varies from 150 psia to 500 psia. Utilization of advanced technology in energized sand fracturing is required to enable these wells to produce at commercial rates of 200 to 2,000 MCFPD. Cost management is critical to keep the projects economical at the low end of the reserve range (<1 BCF). Team Approach Cost control became so critical during early 1995, the shallow gas program was halted. A special multi-discipline team was formed to identify cost saving proposals to get the gas well program "back on the tracks." Composition of the team included everyone involved in executing a shallow gas well completion from Land/Right of Way to the Production Operator. First, every step of the process listed below was thoroughly discussed:staking/building of surface locationdrillingloggingrunning casingcementingperforatingstimulatingrunning tubinginstalling wellheadinstalling facilities including artificial lift
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