In recent years, pressure transient behavior and inflow performance of horizontal wells have received considerable attention due to the increase in horizontal drilling. In this paper we develop an interpretation methodology for horizontal well pressure transient testing. This methodology is then applied to the interpretation of an actual horizontal well test performed in Prudhoe Bay. The complex geometry associated with horizontal wells makes interpretation of well tests a difficult task. Uniquely determining the system parameters from short time (typical times for vertical well testing) pressure tests is not possible. Combining drawdown and buildup tests, with downhole flowrate measurement is critical for proper interpretation. We also provide a solution for the Inflow Performance of a horizontal well completed in a rectangular drainage volume, where the well can be of arbitrary length and completed at any location within the drainage volume. Introduction Now forward solutions to the diffusivity equation for horizontal well geometry with varied boundary conditions are available in the literature. Moreover, Reiss and Sherrard presented performance and production data from several horizontal wells and mentioned interpretation of well test data. The interpretation of well test data from horizontal wells is a much more difficult task than its vertical counterpart. This difficulty stems from:the main search direction of the parameters usually does not coincide with the depositional environment,the three dimensional nature of the How geometry and lack of radial symmetry, andmore parameters (information) to be obtained. In addition to these difficulties, zonal variation of vertical permeability and shale distribution will make interpretation intricate. A well-defined flow period comparable to that of the infinite acting radial How period (free from storage and boundary effects) of a vertical well is not apparent for horizontal wells. This is largely due to the fact that most horizontal wells will exhibit partial penetration effects, even when they are fully perforated. This fact has already been observed by many authors, and specific methods have been proposed to identify How regimes and their durations under ideal conditions. However, it has not been shown how to extend the identification of How regimes and their usage to the interpretation of real pressure transient tests.

Summary. Horizontal wells have been shown to increase productivity, to reduce coning tendencies, and to improve recovery. Given the potential applications in the Prudhoe Bay field, a project was initiated in 1984 to evaluate benefits and to drill and test three trial wells. This paper reviews production and reservoir engineering aspects of the trial program. It includes the objectives of the test program, the planning and drilling of three wells, the forecasting of production rates and recoveries, and the testing and analysis of actual well performance. In summary, the three wells have been successfully drilled and completed, with each well costing less than its predecessor. The wells have exhibited productivities two to four times that of conventional comparison wells, and increased oil recovery is anticipated. Horizontal wells can improve production rates and recoveries by a variety of mechanisms. At their most basic, the long wellbores allow longer completed intervals and therefore increased production rates. In reservoirs overlying an aquifer or located under a gas cap, the increased standoff from the fluid contacts can improve the production rates without causing coning. Additionally, the longer wellbore length serves to reduce the drawdown for a given production rate and thus further reduces coning tendencies. Fractured reservoirs can also benefit from horizontal wells. Long wellbores are likely to intersect more fractures and hence improve both production rate and ultimate recovery. Furthermore, the application of horizontal wells early in a project may allow development with fewer wells because of the larger drainage area of each well. In some fields, the advantages of horizontal drilling may allow development where conventional techniques would be uneconomical. The development of the Prudhoe Bay oil field, on the North Slope of Alaska, has been extensively reviewed in published literature. For reference, a field outline showing waterflood and non-waterflood area (Fig. 1) and a gamma ray log section depicting the various zones (Fig. 2) are included. Two areas of the field offer some of the potential advantages of horizontal drilling previously outlined.1. The midfield area generally contains a thick remaining oil column overlain by an expanding gas cap. Because Prudhoe Bay production will become constrained in the near future by the ability to compress and to reinject produced gas, rather than by oil productivity, immediate field production rate increases will result from reducing gas coning.2. The extreme downstructure part of the Prudhoe reservoir is undeveloped. The thin oil column and potential problems caused by water coning from the underlying aquifer have made development relatively unattractive to date. Horizontal wells offer the possibility of reduced coning and increased production rates, perhaps increasing the attractiveness of development. Projected remaining oil at abandonment for the entire field is about 12 billion STB [1.91 × 109 stock-tank m3], a significant target for any improved recovery scheme such as horizontal drilling. Given this potential target, well locations were screened for application as horizontal wells. A three-well program was selected to address both target areas and to develop a broad experience base. The selected well locations are shown in Fig. 3 and are discussed here. First Well Location (JX-2). This 80-acre [32-ha] infill location is in a structurally simple part of the field. Stepout from the gravel pad (from which all Prudhoe Bay wells are drilled) is less than 5,000 ft [1524 m], allowing a reasonable directional profile to the larger depth at 8,915 ft [2717 m]. The well is located at the base of the oil column to maximize standoff from the gas cap. Drilling technology and drainage area considerations limited the design completion length to 1,500 ft [457 m]. Second Well Location (B-30). The second midfield horizontal well was not spudded until after the initial well was tested. This second well increased drilling experience before the more difficult drilling associated with the Y-20 location. This experience factor and the additional reservoir performance data justified two horizontal wells in the midfield area. Third Well Location (Y-20). Y-20 was recommended as the third horizontal well and the first in the peripheral area. This would be an extended-reach well completed at the top of the reservoir to maximize standoff from the aquifer. The thin oil column in the periphery and longer stepout made this a more difficult, higher-risk well to drill. The stepout to the beginning of the horizontal section was approximately 8,300 ft [2530 m]. This exceeded the 5,000-ft [1524-m] stepout restriction placed on the first well. Information from the first two wells, however, was designed to permit a stepout of this magnitude. Because of the increased stepout, design length for this completion was limited to 1,000 ft [305 m]. Evaluation of Benefits Empirical, analytic, and numerical simulation methods were used to forecast the benefits of the horizontal wells planned for Prudhoe Bay. The benefits considered are productivity, critical coning rates, and recovery. Productivity. The productivity of a conventional well is proportional to the permeability-thickness product. Low productivities result from low values of permeability or formation thickness (or both). This can be compensated for in horizontal wells where the length of the horizontal section is not imposed by nature but chosen. The permeability-length product in horizontal wells plays a role similar to that of the permeability-thickness product of conventional wells. P. 1417^

Summary In recent years, pressure-transient behavior of horizontalpressure-transient behavior of horizontal wells has received considerableattention because of the increase in horizontal drilling. This paper presentsan interpretation method for presents an interpretation method forhorizontal-well pressure-transient testing that is applied to a buildup testfrom a horizontal well in the Prudhoe Bay field. The complex flow Prudhoe Bayfield. The complex flow geometry associated with horizontal wells makeswell-test interpretation difficult. Unique determination of the systemparameters from pressure data with a short testing time (typical test times forvertical wells) and/or production time is not possible. We production time isnot possible. We must run drawdown and buildup tests and acquire the downholeflow rate with pressure to estimate the reservoir parameters accurately. Introduction Interpretation of well tests from horizontal wells is much more difficultthan interpretation of those from vertical wells because of a considerablewellbore storage effect, the 3D nature of the flow geometry and lack of radialsymmetry, and strong correlations between certain parameters. Also, zonalvariations of vertical permeability and shale distribution complicateinterpretation. A well-defined flow period, comparable to that of the infinite-acting radialflow period (free from storage and boundary effects) period (free from storageand boundary effects) of a vertical well, is not apparent for horizontal wells, largely because most horizontal wells exhibit partial penetration effects evenwhen they are hilly perforated. Specific methods have been perforated. Specificmethods have been proposed to identify flow regimes and their proposed toidentify flow regimes and their durations under ideal conditions. AlthoughReiss and Sherrard et al. presented performance and production data fromperformance and production data from several horizontal wells and mentionedinterpretation of well-test data, they did not show how to extend theidentification and usage of flow regimes to the interpretation of realpressure-transient tests. This paper presents a method for the interpretation of wells data fromhorizontal wells and analyses of pseudosynthetic and real well-test data. Solutions With and Without Gas Cap or Aquifer In a horizontal well, there is usually considerable wellbore volume (50 to100 bbl) below the measurement point, even if the downhole flow rate ismeasured or a downhole shut-in device is used. The storage effect with thisadditional volume typically lasts longer than that in a vertical well in thesame formation because the anisotropy reduces the effective permeability atearly times to root of kHkV.

Heavy oil waterfloods have been operating in the petroleum industry for more than fifty years. Over this time, many researchers have tried to identify flood management practices that would optimize recovery from these waterfloods. This multidisciplinary work ties simulation with the evaluation of field statistical results to determine the best operating practices for heavy oil reservoirs that have high permeability thief zones. The particular type of thief zone of concern in Alaskan heavy oil waterfloods is called a Matrix Bypass Event, or MBE. An MBE is a dramatic water breakthrough event in the form of a direct connection between the injector and producer whereby the waterflood process ceases and the injection water cycles directly to the producer without sweeping the matrix. This study evaluates operating strategies for reservoirs where MBEs have developed, taking into account the effects and interdependencies of pre-production, Voidage Replacement Ratio (VRR), and oil viscosity.Evaluation of production from 30 Canadian heavy oil waterfloods indicated that oscillation of the VRR resulted in more oil recovery than a reservoir operated at a constant VRR~1.0. This finding laid the foundation showing that an operational practice called Cyclic Injection/Production would be beneficial, especially for heavy oil waterfloods. Cyclic Injection/Production alternates active injection while production is shut in, followed by active production while injection is shut in. Simulation was performed with a 3-D compositional finite difference reservoir model based on a heavy oil reservoir in Alaska's North Slope. The simulation confirmed that optimal waterflooding practices for heavy oils are significantly different from optimal practices for light oil waterfloods. The best practices also varied according to whether the waterflood had developed an MBE. As long as no MBEs are present and the producers are not bottomhole pressure limited, VRR of less than 1.0 and continuous injection are recommended. For heavy waterfloods that have high perm thief zones, however, Cyclic Injection/Production and a VRR of less than 1.0 improve recovery.

A statistical study of 166 western Canadian waterfloods recovering heavy and medium gravity oils revealed new findings about best operating practices for heavy oil waterflooding. In classical light oil waterflooding, operators are advised to start waterflooding early and maintain the voidage replacement ratio (VRR) at 1. The study, however, produced surprising results for 2 parameters − among the 120 reservoir and operating parameters investigated − that ran counter to the recommended practices of classical light waterflooding. Delaying the start of waterflooding until a certain fraction of the original oil in place was recovered was found to be beneficial. Secondly, varying the VRR was shown to correlate with increased ultimate recovery ─ periods of underinjection are needed, although a cumulative VRR of 1 should be maintained.Ultimate recovery was correlated with the primary recovery factor at the start of the waterflood. No trends appeared when the full set of 166 waterfloods was inspected. However, when the dataset is analyzed by ranges of API, a "sweet spot" of improved ultimate recovery was observed in a very narrow window of oil recovery factor prior to the start of waterflooding. Graphs of each category showed this "sweet spot" window where improved recovery occurred. These categories were API ranges; as well as ranges of permeability*height/viscosity (kh/μ); and pattern development.Also increases in ultimate recovery were observable when we examined graphs of ultimate recovery versus the fraction of injection volume that was underinjected ─ but again, only when the data was analyzed by the ranges. A certain period of injection when the VRR was less than 0.95 resulted in increased ultimate recoveries. However, it is important that this period of VRR < 0.95 be offset with periods of increased VRR so that the cumulative VRR cycles around 1.0. Again, each range manifested a narrow "sweet spot" for where this increase in ultimate recovery occurred.