Sufficient production and fracture mapping evidence across North America is now available to clearly demonstrate that pairs of delineation and development wells often underperform when there is substantial production time (months or years) between the completions of the two wells. The relative degree of impact on hydrocarbon extraction per acre varies from one play or formation to another, but the phenomena is generally attributed to asymmetric induced fracturing from the development (child) well into the previously partially drained and lower static pressure delineation (parent) well reservoir volume. This paper briefly discusses two solutions that have been employed to minimize the negative fiscal ramifications and improve recovery. Rigorous 3D unstructured grid reservoir modeling can assist in the quantification of the phenomena; however, options for mitigating the problem for cases where the impact is extreme are typically limited. Synthetic history matching and forward modeling were performed with a grid-based numerical simulator that mimicked a series of asymmetric oblique fractures interacting with a drained reservoir volume, comparing acceleration of reserve recovery and total recovered reserves with a similar case involving symmetric fracturing. Two scenarios for preventing extreme asymmetric fracturing are discussed. These included dramatic shortening of the time between completions, and performing pressure sink mitigation (PSM) via refracturing of the delineation wellbore. It is shown that the asymmetric fracturing into drained volumes can materially impact reserves and rate of recovery if the acreage position of a given project is substantial. It is demonstrated that the overall stimulated reservoir system permeability, the degree of permeability contrast between reservoir layers, and the degree of asymmetry are all factors that have an impact on the degree to which the long-term time between completions affects recovery of hydrocarbons over and above simple volumetric depletion. Integration of rigorous 3D reservoir modeling and far-field fracture mapping have established that the negative ramifications of extreme induced fracture asymmetry can be overcome with careful application of drilling and completion (D&C) timing and offset drainage pressure management process.

Horizontal wells in liquids-rich shale plays are now being drilled such that lateral and vertical distances between adjacent wells are significantly reduced. In multistacked reservoirs, fracture height and orientation from geomechanical effects coupled with natural fractures create additional complications; therefore, predicting well performance using numerical simulation becomes challenging. This paper describes numerical simulation results from a three-well pad in a stacked liquids-rich reservoir (containing gas condensates) to understand the interaction between wells and production behavior. This paper discusses the use of an unstructured grid-based numerical simulator that incorporates complicated geometries of both hydraulic and natural fractures. It can handle compositional simulation to better model gas condensates with special focus on timing of third well placement and the loss of conductivity effects on production from these wells. A base case was created with a stacked shale play containing three parallel wells but with staggered elevations. Variables used in this study include matrix permeability, condensate-to-gas ratio (CGR), fracture length, well staggering, time of well placement, conductivity degradation, and presence of natural fractures. Simulation runs were conducted for a five-year duration.More than 20 compositional simulation runs were conducted. For the base case, staggering resulted in a slight decrease in both cumulative oil and gas production compared to a case without staggering. Matrix permeability had the most dominant effect on both oil and gas production. Fracture and matrix conductivity losses were more detrimental to cumulative gas production than oil production. For the limited cases studied, placement of the third well one year after the first two wells began producing resulted in a spike in both oil and gas production from the pad. This produced cumulative oil and gas amount was close to that of three wells producing simultaneously, especially if fracture half-lengths for the third well were the same as the first two. However, cumulative oil and gas production reduced significantly if fracture half-lengths were smaller than the other two wells. When all wells experienced significant conductivity loss, gas production was affected more than oil production when the third well was placed one year after the first two wells began producing. In all cases, placing the third well between the other wells was helpful in increasing overall production from this pad. Natural fractures increased both oil and gas production in the cases studied.This paper addresses important issues associated with a liquids-rich unconventional play. It demonstrates successful use of unstructured grid-based reservoir simulation modeling to address well placement timing, well staggering, conductivity damage effects, natural fractures, hydraulic fractures not perpendicular to the wellbores, and several other important issues for which little is known so far. Results from this study type can be used to make impor...

Summary. Extensive field development of a new fracturing system incorporating a temperature-delayed crosslinker was undertaken over a 15-month period in south Texas. Treatments performed at depths from 7,500 to 17,100 ft [2290 to 5210 m] revealed that the new fluid has properties superior to those of high-temperature systems that use conventional organometallic crosslinkers. Treated formations include the Wilcox, Frio, and Vicksburg. The use of this new fluid has resulted in lower and more consistent friction pressures. Average sand concentrations have been increased. A significant decline in the occurrence of screenouts has been observed. Introduction The sensitivity of fracturing fluids to degradation by exposure to various shear conditions has been under intensive study for several years. The use of the API RP39 method for determining rheological properties does not adequately simulate environmental conditions that properties does not adequately simulate environmental conditions that a particular fluid may actually encounter during a fracturing treatment. Equipment and methodology were developed that more consistently approximated a particular set of downhole shear and temperature conditions. Fluids could be subjected to the high shear rates generally associated with pumping through small tubular goods, then subsequently placed in a lower shear-rate condition that was thought to approximate flow through a fracture. Investigations with the new equipment and methodology revealed several points that have had significant impact on the design and implementation of actual treatments performed in the south Texas area.Exposure of conventionally crosslinked high-temperature fracturing fluids to conditions of high shear rate and/or moderate shear for extended periods of time (approximating tubular residence time) tended to reduce the overall stability of the fluid.Fluids that incorporated delayed crosslinking mechanisms tended to be more rheologically stable.Overall performance of a fluid depended on which crosslinker was used, as well as whether the system was delayed. On the basis of these findings, an intensive program was undertaken in the south Texas gulf coast area (Table 1) to design, pump, and monitor fracturing treatments with a temperature-delayed-type crosslinker that performed well on the new laboratory apparatus. In the 15-month period following initiation of the project, 56 treatments were performed in the 10-county test area. Because no screenouts occurred on initial treatments, job designs were altered over a period of time as a result of the apparent increased efficiency of the new fluid. Average proppant concentrations were increased from about 2.8 to 4.3 lbm/gal [335 to 515 kg/m3] during the development period. Maximum concentrations, either designed or pumped, went from 5 to 10 Ibm/gal [600 to 1200 kg/m3]. In some pumped, went from 5 to 10 Ibm/gal [600 to 1200 kg/m3]. In some cases, the polymer loading for a given bottomhole static temperature (BHST) decreased. Historically, the south Texas gulf coast area exhibits abnormally high localized pore pressures, necessitating the use of tubing in completions for well control. Consequently, treatment rate is generally limited by the burst rating of tubular goods. The new temperature-delayed crosslinked fluid has exhibited significantly lower friction pressures, resulting in either lower hydraulic horsepower or increased pump rate. Real-time evaluation of fracture parameters during a particular treatment is more reliable because friction pressures are more consistent. Fluid Description All treatments used a conventional low-residue hydroxypropyl guar (HPG) as the base polymer. The polymer loadings were dependent on maximum BHST, from a low of 40 Ibm/1,000 gal for 200F [4.8 kg/m3 for 93C] to a high of 60 lbm/1,000 gal for 420F [7.2 kg/m3 for 216C]. Where necessary, a high-temperature stabilizer was used to achieve additional fluid stability and better proppant transport over extended periods of time. The base HPG was proppant transport over extended periods of time. The base HPG was batch mixed in 500-bbl [80-m3] fracturing tanks on all treatments and the new crosslinker metered at the blender "on the fly." The crosslinking mechanism is more temperature-dependent than time-dependent. Crosslinking proceeds very slowly from the time of crosslinker addition until the fluid reaches 90 to 110F [32 to 43C]. At about 90 to 110F [32 to 43C], the rate of apparent viscosity development begins to rise. From about 110 to 130F [43 to 54C], reaction rate is very rapid. On-location verification of "crosslink time" is physically difficult because the crosslinking mechanism is more temperature-dependent than time-dependent. Precise flowmetering equipment must be used to ensure a constant ratio of crosslinker to available hydroxypropyl groups. Friction Pressure Friction-pressure curves were developed for various tubular goods with a combination of actual field friction data obtained from initial treatments and previously published friction-pressure curves for linear water-based gels. In the majority of treatments, an instantaneous shut-in pressure (ISIP) was obtained and recorded after a moderate volume of linear-based gel prepad was pumped at the designed fracturing rate. From this ISIP, both perforation friction and fracture gradient were calculated. Friction pressures for the crosslinked pad fluids that followed the prepad were then calculated based on these assumptions:bottomhole fracturing pressure remained relatively constant throughout the prepad and pad; pressure remained relatively constant throughout the prepad and pad;perforation friction (if any) did not increase or decrease throughout the prepad and pad; andthe crosslinked fluid was actually pumped as designed and exhibited rheological properties as expected. Although this method was suitable for generating a few scattered points, it was desired to develop curves for various rates and pipe points, it was desired to develop curves for various rates and pipe diameters to facilitate future job design. A scaleup prediction by the Bowen method was used to generate friction pressures in various tubular goods. The resulting curves were then fitted onto existing known data points for the fluid in question (see Fig. 1). It became apparent during initial field trials that friction pressure of the crosslinked fluid was lower than the friction of the pressure of the crosslinked fluid was lower than the friction of the corresponding linear-based gel. A unique opportunity was afforded early in 1983 to verify this observation. SPEPE P. 187

Technology Update A challenging commodity price environment has forced operators to seek methods for sharply lowering recovery cost per barrel of oil equivalent (BOE) in unconventional plays. Some reduced costs have resulted from the overcapacity of global services. Other reductions have resulted from declining industry activity, which has increased the availability of personnel and led to a renewed focus on maximizing drilling and completion (D&C) process efficiency. A portion of the recovery cost reduction has resulted directly from incremental technical innovations and process improvements that were difficult to achieve when operators and service companies were concerned chiefly with D&C execution. Older processes were designed to maximize early production, whereas a number of newer technologies focus on maximizing net present value (NPV). High NPV is most often achieved by reducing uncertainty and manipulating the cost portion of the NPV equation, especially when the commodity price and/or discount rate is uncontrollable. D&C portfolios have primarily contained a mix of delineation wells and development wells. Delineation wells have a higher cost per BOE but a higher potential for accelerating reserve recovery. Development wells have a lower cost per BOE but a lower potential for accelerating recovery. This mix of wells is appropriate for periods when margins are high enough to cover the associated D&C costs. However, the loss of such margins in a low-price environment has prompted adjustments to lower the average cost per BOE. One strategy for lowering that cost is to increase the percentage of refractured wells in a portfolio. Typically, the cost per BOE of refracturing is substantially lower than that of drilling and completing delineation or development wells. Recently, the development and implementation of effective stimulation diversion techniques and greater focus on candidate screening have narrowed the window of uncertainty in executing refracturing operations in horizontal wells. These improvements have reduced the economic risk of these operations and created further incentive to shift portfolio strategies toward refracturing. Taking advantage of refracturing opportunities in a portfolio involves four steps. Screen the best candidate properties, based on reservoir quality and the potential to exceed the original completion quality. Design the optimal refracture treatment to place new conductive fractures where desired and reconnect existing ones. Execute the refracture treatment for coverage of all selected lateral areas, using the latest processes, techniques, and materials. Diagnose the refracture performance and optimize the refracture design for analogous properties, using state-of-the- art diagnostic tools. This article primarily discusses the candidate selection process.

During the previous 14 years, North American unconventional reserve delineation activities have resulted in hundreds of billions of dollars in capital spending. Development of the accompanying defined reserves has generally been a recent occurrence; in most established plays, the typical wellbore has been associated with field development rather than delineation. Approximately 102,000 horizontal wells have been drilled and completed in North America since 1990, at an industry cost of approximately USD 750 billion. However, there is a clear trend toward continuous improvement in both process and production response. Much of the learning curve has been based on trial-and-error (T&E) activities, rather than the deliberate acceptance and integration of upfront measurements with the application of physical realities and rigorous peer-reviewed algorithms, concepts, and practices. During the early history of hydrocarbon extraction, operators experimented with various vertical well drilling and completion (D&C) processes to maximize production and optimize net present value (NPV). Given the steep learning curve that the North American industry has experienced and the significant D&C capital cost of a single unconventional well, it is no longer prudent for national oil companies (NOCs) outside North America to repeat the pattern of historical experimentation to achieve equivalent (or better) efficiencies and results. This paper offers a number of suggestions and concepts that can be applied to dramatically shorten the learning curve and minimize capital expenditures associated with efficient extraction of ultralow-permeability hydrocarbon reserves. North American parameters that have clearly impacted performance (parallel lateral spacing, fracture spacing along a lateral, total exposed conductive fracture surface area, decreasing proppant diameter, lateral length, etc.) are examined. The quantitative value of applying rigorous reservoir modeling, intensive study of historical practices, and upfront measurements, such as far-field fracture mapping, near-wellbore (NWB) production flow-splitting, and long-term diagnostic shut-in testing, is then estimated by examining the cost of error in delineating and developing a given acreage position.