This paper discusses a relatively new acid-stimulation process that uses dynamic fluid energy to divert flow into a specific fracture point in the well that can initiate and accurately place a hydraulic fracture. These acid-stimulation methods often use two independent fluid streams: the acid phase down the treating string and other liquids or gases down the annulus. The annular fluid may simply serve as a wellbore pressurizing component, or with this process, two different fluids can be mixed downhole with high energy to form a homogenous mixture. Using variations of this process, treatments were performed in four openhole, horizontal wells in the same formation. The first well was acid-fractured with coiled tubing to place many small fractures along the open hole. The second well was acidfractured with coiled tubing, but downhole mixing concepts were also used to provide in-situ generation of CO2 foam where fewer, but larger, fractures were placed in this well. The third and fourth wells were treated with acid using blasting-type rotating or non-rotating jetting tools while mixing the acid with CO2 downhole. Numerous small, near-wellbore fractures were the expected result in these two wells. Experimental laboratory investigation of the physical mechanisms that contributed to these successful stimulations was considered important. Large-scale laboratory tests were performed to more closely examine the physical rock response to the jetting mechanism and conditions. The findings of these tests are presented in this paper. Introduction In an openhole lateral, successful production enhancement treatment depends on identifying the causes of the production deficiency for the specific well to be treated, properly understanding the remedial treatment options available, and evaluating the economics of available options. Assuming the problem is not inadequate reservoir size or recoverable reserves, production deficiencies can result from many factors in a horizontal openhole completion, including: wellbore debris, filter cake or other near-wellbore damage, deeper permeability damage, low formation permeability, or even wellbore location within the reservoir. If the production problem is caused by debris plugging along the lateral, the well can usually be cleaned with an effective hydrablasting and cleaning process. This service generally combines specialized fluid systems (often foams) and possibly a wash tool designed for the different mechanics associated with cleaning deviated or horizontal wellbores. Some processes incorporate computerized design software to properly plan the clean-out operation. If a solids filter-cake has caused near-wellbore damage that is responsible for the production deficiency, an acid wash might be the best solution. Coiled tubing (CT) applications can often allow more efficient washing of the entire lateral or of specific preselected zones. Using tools with jetting nozzles can enhance the effectiveness of acid washes, or even nonreactive fluids that provide the benefits of only mechanical-jetting effects. If deeper damage in the near-wellbore region is decreasing production, an operator may desire to place several small hydraulic fractures at many places along the lateral section to bypass the damage. Such small fractures can use relatively small volumes of acid to give a beneficial result similar to increasing the wellbore diameter, and do so without problems associated with excessive hole enlargement. If the wellbore is located in a poorly producing zone in the reservoir some reasonable distance from a better part of the reservoir, or if a vertical permeability barrier exists, the operator may need to create larger fractures that can communicate the wellbore with more productive zones.

Since 1968, the Vogel equation has been used extensively and successfully for analyzing the inflow performance relationship (IPR) of flowing oil wells under solution-gas drive. Oil well productivity can be rapidly estimated by using the Vogel IPR curve and well outflow performance. However, the Vogel curve was originally developed for conventional vertical wells and may not be valid for slanted and horizontal wells. The development of IPR's for slanted and horizontal wells by using a vertical/horizontal/slanted well reservoir simulator is presented. Several important results were observed. First, the IPR's for slanted and horizontal wells are similar to the parabolic behavior of the VogeilPR curve. Second, IPR data generated for slanted wells by using the Vogel curve can differ as much as 22% from that of the new IPR data and 27% for horizontal wells. Third, the right curvature shift of the Vogel curve for slanted and horizontal wells indicates that these wells are more efficient producers than vertical wells from a subsurface fluid flow viewpoint. Fourth, a minimum slant angle of 45 degrees is required to increase oil productivity by 50% over that of a vertical well. A slant angle of 60 degrees or greater can increase oil productivity more than two times that of a vertical well. The newly developed IPR data are compared with existing empirical and field data. Several application examples are presented to illustrate the use of these IPR's to predict slanted/horizontal well productivity.

The Canadian sedimentary basin has long been exploited using vertical well-completion techniques, sometimes producing from multiple formation zones. With recent advancements in horizontal drilling and multistage-completion techniques, horizontal wells are quickly replacing vertical completions as the completion method of choice in many unconventional oil and gas reservoirs. A popular completion method uses openhole isolation packers and ball-activated sliding sleeves to target specific intervals along the wellbore during fracture treatments. This allows multiple stages to be completed in short periods of time because fracture operations often do not have to be shut down to precede to the next stage, compared to the more traditional plug-and-perf completion technique.Microseismic mapping has proven effective in measuring fracture geometries, such as fracture half-length, height, azimuth, and stimulated reservoir volume. This paper outlines the workflow used in understanding and interpreting the created fracture geometry within individual openhole intervals of the openhole packer completion technique.The microseismic data proves that created fracture geometry can vary dramatically along the openhole section of a horizontal wellbore. Microseismic mapping also indicates that fractures do not always initiate across from the sliding sleeve port, but can in fact initiate anywhere along the openhole section, exhibiting, in some cases, multiple fracture initiation points. The microseismic-mapping results of this project were used to identify reservoir coverage along the horizontal wellbore as well as identify areas in the reservoir that were not sufficiently stimulated.By using information gained through microseismic monitoring, fracture models can be calibrated to match actual fracture geometry with modeled fracture geometry, resulting in a calibrated fracture model. Once defined, and using the well production history, the fracture model was used to forecast the future production of the well. Using the calibrated model can help operators optimize the number of stages, stage spacing, and fracture-treatment design to maximize reservoir contact and hydrocarbon recovery while minimizing completion costs.

Production from carbonate wells is often controlled by the degree of stratigraphic interconnectivity or lack thereof. Formation stratigraphy results in severely compartmentalized reservoirs. Effective methods for achieving hydraulic interconnectivity with such compartments are limited in horizontal openhole and long pay section in deviated wells. A new technology is emerging that incorporates solid acid capsules that function as both a fluid-diverting agent and a fracture conductivity enhancer. The degradable sized particulate system is incorporated into the acidizing fluid designed to enhance inflow from natural fracture swarms and to help enable propagation of hydraulic fractures that can breach or achieve wellbore communication with the stratigraphic compartments. This paper presents a case experimental project that involves a Canadian carbonate gas reservoir. Historically, horizontal wells drilled in low-permeability reservoirs with no natural fractures have shown poor production response. This successful production stimulation case demonstrates the potential to overcome the compartmentalization problem. In one of the first-use case wells reviewed in this paper, up to a 10-fold increase in reservoir pressure was observed in a short-term buildup test, and the well was converted into an economic producer. Image logs were used to provide location and distribution of mineralized natural fracture swarms targeted for stimulation. Production data, laboratory data and post-treatment productivity index (PI) are presented. This paper adds to the industry's technical knowledge base by:offering a practical, lower cost, high value solution to a significant emerging market;documenting the first use of a new technology application;presenting evidence of the technology's widespread global application to carbonate reservoirs and possibly sandstone reservoirs. Introduction Effective stimulation or production enhancement of long, openhole, horizontal, and deviated (directional) completions in reservoirs composed of multiple thrust sheets carbonate zones have been a long-standing challenge to operators. Numerous techniques have been attempted with varying degrees of technical and economic success.1–11 To develop effective solutions, the reservoir and geologic controls that constrain the technical solution should be described first. Carbonate reservoirs are heterogeneous by nature, especially in the context of distribution of natural fracture systems known as fracture swarms.12–15 Both horizontal and deviated wells are often drilled with the intent of intersecting as many natural fracture networks (swarms) as economically feasible. Often, predicting ahead of the bit the exact location and distribution of the natural fracture swarms that control production potential or reservoir access can be difficult or impractical. Further, performing diagnostic log evaluations on the horizontal sections after the well is drilled can be cost-prohibitive. After the drilling process, specific geologic information often is not known, such as specific distribution or location; whether the natural fractures are open, healed, or partially open, or damaged; and depth of reservoir access from the natural fracture conduits. Normally, in such tight, dual-porosity systems, performing extensive hydraulic fracturing treatments over such long intervals has a limited success and is cost-prohibitive, and if natural fracture swarms are absent where the hydraulic fractures are placed, the well likely will not meet economic expectations. The technical challenge presented and discussed in this paper involves the novel application of acidizing-encapsulated acid diversion designed to enhance reservoir communication with the wellbore using existing natural fracture conduits that are presumed to be open, partially healed, or mineralized.

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