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Results
Guidelines for the Design of Fracturing Treatments for Naturally Fractured Formations
van Batenburg, Diederik W. (Halliburton B.V.) | Hellman, Tom J. (BP Exploration Operating Co. Ltd.)
Abstract Natural fractures are present in many oil and gas producing reservoirs and largely contribute to the productivity of those reservoirs. Natural fractures, however, also complicate drilling, completion, and/or work-over operations. Hydraulic fracturing treatments are particularly sensitive for the presence of natural fractures as the hydraulic pressure may open the natural fracture system as well as the induced fractures resulting in additional (unexpected) fluid leak-off and consequently early screen-outs. Recent advances in pressure decline analyses of injection tests have provided the industry with a tool to recognize the presence of natural fractures. However, guidelines on how to design a hydraulic fracturing treatment once the natural fractures have been identified are lacking. The paper presents analysis of hydraulic fracturing treatments in naturally fractured reservoirs conducted in Algeria and Southern North Sea. The treatments analyzed include treatments that were completed as designed as well as treatments in which as little as 10% of the designed proppant amount was placed. Guidelines are proposed based on the commonalties that were found in these analyses. Introduction Hydraulic fracturing in fissured or naturally fractured reservoirs has been the topic of a significant number of SPE papers that have been presented since the 1980's. Most of these papers are related to fracturing wells in tight gas reservoirs in the USA as these reservoirs are the major source for the domestic US natural gas supply. However, hydraulic fracturing treatments in other geographical areas are also affected by the presence of natural fractures. The mineback experiments as described by Warpinski and Teufel probably provided the first insights into the complexity of hydraulic fracture geometries that can be created under real world conditions. This study made the industry realize that the symmetric two-wing fracture model may not always be applicable. In 1986, Shelley and McGowen proposed an empirical correlation to determine maximum recommended job size and critical proppant concentration for treatments in naturally fractured reservoirs. This method uses the injection of 10,000 gal of non-gelled fluid as "Minifrac analysis has not proven to be a practical technique in predicting proppant placement in naturally fractured reservoirs....". Other authors have approached the problems of leak-off in natural fractured systems starting from the G-function as defined by Nolte. Castillo and Mukherjee et al. proposed to use the first derivative of the pressure with respect to G-function to identify pressure dependent leak-off effects. Barree and Mukherjee provided a breakthrough in this area in a paper in which they introduced the "superposition" curve to the pressure versus G-function. With the help of the GOHFER hydraulic fracture simulator they were able to show that different leak-off mechanisms could provide characteristic shapes from which the leak-off mechanism could be identified. For natural fractures the "superposition" curve has the typical hump shown in Figure 1. In a subsequent paper Barree presents field examples for the use of this technique and concludes that a simulator that handles pressure dependent leak-off correctly is required to adequately use the results of these analyses. This paper presents analysis of pressure decline after injection tests and the subsequent main fracturing treatments for four different cases in naturally fractured reservoirs. Empirical design guidelines are proposed based on commonalties these analyses. Case Histories Generic well and reservoir data for each of the case histories that will be discussed are given in Table 1. Analyses results and data from injections test and main treatments for each of the cases are summarized in Table 2.
- North America > United States (1.00)
- Europe > Denmark > North Sea (0.66)
- Africa > Middle East > Algeria (0.49)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > P 033 > Rotliegendes Formation (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5604/29 > South Arne Field (0.99)
- Africa > Middle East > Algeria > Illizi Province > Illizi Basin > Tin Fouye Tabankort Field (0.99)
- (3 more...)
Application of Novel Upscaling Approaches to the Magnus and Andrew Reservoirs
King, M.J. (BP Exploration Operating Co. Ltd.) | MacDonald, D.G. (BP Exploration Operating Co. Ltd.) | Todd, S.P. (BP Exploration Operating Co. Ltd.) | Leung, H. (BP Exploration Operating Co. Ltd.)
Abstract Cases studies from three North Sea turbidite reservoirs will be presented, which together demonstrate our current understanding of permeability and relative permeability upscaling. The three formations, the Magnus, Magnus Sand Member (MSM), the Magnus, Lower Kimmeridge Clay Formation (LKCF), and the Andrew reservoir each provide distinct challenges for reservoir modelling, either because of reservoir complexity, the fluids in place, or the phase of field life. To meet these challenges, several novel upscaling approaches have been developed. Their use will be explored and current best practice delineated. This best practice differs significantly from previous definitions of "effective permeability" by placing more emphasis on extracting multiple properties from the fine scale geologic models. Distinct upscaling calculations are required to assess the quality of sands, the quality of barriers, and the tortuosity of flow around these barriers. Similarly, when constructing upscaled relative permeabilities, the "effective" curves are distinguished from the "pseudo" curves. The former describe the physical displacement of fluids, while the latter include the additional numerical dispersion corrections required when implementing the relative permeability functions within a coarsely gridded full field simulator. P. 133
- Europe > United Kingdom (1.00)
- North America > United States > Texas (0.93)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Deep Water Marine Environment (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.30)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- Europe > United Kingdom > Kimmeridge Formation > Lower Kimmeridge Clay Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/7a > Magnus Field > Kimmeridge Formation > Magnus Formation (0.96)
- (9 more...)
Integrated technologies exceed well placement challenge
Allan, D. (Baker Hughes Inteq) | Hess, M. (Schlumberger GeoQuest) | Todd, S.P. (BP Exploration Operating Co. Ltd.)
Abstract The challenge to place wells accurately within the thin oil column of the Andrew Field has been met through the integration of drilling and data acquisition technologies in the subsurface and well engineering teams. The requirement for accurate placement derives from the need to optimize cumulative oil from each of the horizontal oil producers in the field prior to the inevitable break through of gas and water from the gas cap and aquifer, respectively. This critical requirement was captured as a Minimum Performance Standard for the Andrew well engineering alliance, which provided a focus for the team. It was met through using the Gas-Oil Contact as a local datum to reduce depth uncertainty and downhole engineering including a steering assembly with near bit directional and formation evaluation sensors. At the same time it was also important that a full, comprehensive and quality dataset that could be used for future well and reservoir management decisions be acquired in the wells. This necessity was met through integrated acquisition of data in both LWD and wireline. The data acquisition and well placement challenges converged in the last of the pre-drilled wells, A04, in which geosteering was adopted to change the stand-off about halfway along the well. Introduction The Andrew Field, a Palaeocene deep sea sandstone reservoir containing some 112 mmbbls of recoverable oil was sanctioned for development in 1994. The sanction case for the field centered on the exclusive use of horizontal wells to reduce well numbers and increase oil rates. Horizontal wells were perceived as appropriate because the field has a thin (58 m True Vertical Depth, TVD) oil column overlain by a gas cap and a large active aquifer. Vertical wells in such a reservoir are incapable of producing at sufficiently high and sustained oil rates to be commercially viable. The support for the case came from a well flow test performed on well 16/28-16z, a horizontal appraisal well drilled in 1993. The test data from this well, particularly the relatively high flow rates at low drawdowns and the lack of pressure depletion during flow, indicated that the Andrew reservoir has a generally high Kv/Kh and is conducive to depletion by horizontal wells. This very successful appraisal well allowed the required well numbers to be more than halved from the previous development model which involved 24 conventional vertical wells. This breakthrough, together with the integration of preselected Alliance partners to optimize the facilities, and the use of a Reservoir Uncertainty Statement (RUS) to express openly the subsurface risks to the project value, allowed the project to be sanctioned. Andrew is now to be a development with 10 horizontal wells and one gas injector (Fig. 1). Four of these wells, including the horizontal appraisal well, have been pre-drilled through a template from September 1995 to January 1996. A well engineering alliance, involving BP, Baker Hughes INTEQ, Schlumberger Transocean and Santa Fe as the main members, was set up to construct and manage the wells. Each oil production well is expected on average to recover about 1 mmbbls and hence represents an asset in itself. The wells will be produced at rates higher than the critical rate which induces gas and/or water coning. Therefore the value of each well is strongly influenced by how much oil can be produced before breakthrough of gas and/or water. The challenge therefore for the development team in the template phase of drilling in 1995/6 before first production was to place the wells in the optimum position given the current level of reservoir understanding. Moreover, adequate data sets needed to be gathered from these wells to further reduce the uncertainty in the vision of the reservoir size and internal heterogeneities. This paper describes the integration of well placement and data acquisition technologies to meet this challenge. Business Objectives Well placement. In the thin oil column gas and water are expected to cone into the horizontal wells within 12 months. Critical coning rates are estimated to vary from 800 to 7000 bopd, in contrast to the Andrew oil producers which must produce at average rates of 15,000 bopd to be commercial. Gas and water will break through from the gas cap and aquifer, respectively during the wells' lives. P. 405
- Europe > United Kingdom > North Sea > Northern North Sea (0.45)
- Europe > United Kingdom > North Sea > Central North Sea (0.45)
- North America > United States > Texas (0.28)
- Europe > United Kingdom > North Sea > North Sea > Northern North Sea > South Viking Graben > Block 16/28 > Andrew Field (0.99)
- Europe > United Kingdom > North Sea > North Sea > Northern North Sea > South Viking Graben > Block 16/27a > Andrew Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Northern North Sea > South Viking Graben > Block 16/28 > Andrew Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Northern North Sea > South Viking Graben > Block 16/27a > Andrew Field (0.99)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Use of High-Angle, Acid-Fractured Wells on the Machar Field Development
Gilchrist, J.M. (BP Exploration Operating Co. Ltd.) | Lietard, O.M.N. (Schlumberger Dowell)
SPE Members Abstract The Machar field, located in UKCS Block 23/26a, contains an estimated STOIIP of 290 MMSTB, predominately found in high porosity, low permeability chalk formations. Draped over the flanks of a salt diapir, the chalk formation exhibits a variable degree of natural fracturing depending upon its position on the structure. Following initial appraisal of the structure, it was clear that to optimise field development, a well designed to intersect with as many natural fractures as possible would offer high well rates while minimising drawdown to aid in reservoir management and recovery optimisation. This paper describes the use of a stratigraphically high angle well which was drilled to fulfill these requirements. Following discussion of the well's completion and stimulation design, the field implementation and evaluation will then be reviewed. The successful high rate damage removal / acid fracturing treatment has led to this appraisal/development well being placed on long term production as part of a pilot scale development of the reservoir. Introduction In 1992, a scheme to further appraise the dynamic behaviour of the Machar fractured chalk reservoir was initiated. This pilot scale development would use a stratigraphically high angle well as the primary producer in the initial appraisal phase. This paper discusses the planning and implementation of this high angle, acid fractured well. Focusing on the payzone drilling and completion aspects, the discussion will cover the rationale for the use of this well type, the engineering issues addressed during the detailed well design phase and a review of the field operations. A comprehensive stimulation analysis, based on review of the downhole treating pressures, radioactive tracer responses and pre- and post stimulation production logs will then be presented. BACKGROUND TO RESERVOIR The Machar reservoir is located in the Central North Sea (UKCS Block 23/26a). Draped over a salt diapir, reserves are found in a number of connected reservoirs; the Forties sandstone, the Ekofisk, Tor and Hod chalks and a Celestite zone (diagenetically altered anhydrite) immediately overlying the salt core. Volumes of oil-in-place have been estimated at 291 MMSTB. The bulk of this oil lies in tight chalk matrix rock with its production coming from natural fractures. Figure 1 illustrates the general cross section of the reservoir. key reservoir fluid and rock parameters (for the chalk) are listed below. P. 497^
- Geology > Structural Geology > Tectonics > Salt Tectonics (0.95)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.34)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 23/26a > Eastern Trough Area Project > Machar Field (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.94)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.94)
- (11 more...)