Multiwell, Multilayer Model To Evaluate Infill-Drilling Potential in the Oklahoma Hugoton Field
- M.J. Fetkovich (Phillips Petroleum Co.) | D.J. Ebbs Jr. (Phillips Petroleum Co.) | J.J. Voelker (Phillips Petroleum Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- August 1994
- Document Type
- Journal Paper
- 162 - 168
- 1994. Society of Petroleum Engineers
- 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.5 Reservoir Simulation, 4.6 Natural Gas, 5.5.8 History Matching, 4.1.2 Separation and Treating, 1.6.11 Plugging and Abandonment, 5.6.3 Pressure Transient Testing, 1.6 Drilling Operations, 5.6.1 Open hole/cased hole log analysis, 5.6.4 Drillstem/Well Testing, 2.2.2 Perforating, 5.7.5 Economic Evaluations, 4.1.5 Processing Equipment
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A 3D simulation was conducted on a portion of the Oklahoma Hugoton gas field to evaluate infill-drilling potential. The importance of understanding the behavior of layered, no-crossflow reservoirs is emphasized by matching detailed performance histories. Further insight into this long-lived field is obtained by forecasting performance, both for continued current operations and for infill drilling on each proration unit.
On April 25, 1986, the Kansas Corp. Commission (KCC) issued an order1 that allowed infill drilling in the Kansas portion of the giant Hugoton gas field. The order allows producers to drill a second gas well on each of the 4,163 proration units (nominally 640 acres). On the basis of geologic and engineering testimony, the KCC ruled that 3.5 to 5 Tscf of additional reserves could be recovered by drilling an infill well on most of the current 640-acre proration units. Initial and remaining gas in place (GIP) in the Kansas Hugoton field, indicated from pressure/cumulative production data presented at the hearing, were 30 and 12 Tscf, respectively.
In view of the infill-drilling order in Kansas, the Oklahoma Corp. Commission (OCC) initiated a proceeding to determine whether it should develop a plan to authorize drilling of increased-density wells in the Oklahoma portion of the Hugoton gas field. A Jan. 30, 1987, OCC notice of inquiry requested all interested parties to submit answers to questions related to infill-drilling potential on the present 640-acre spacing pattern. There are currently 1,340 active wells in the Oklahoma Hugoton field. Cumulative production to March 1, 1989, was 5.0 Tscf, with an indicated 1.5 Tscf of remaining recoverable reserves.
Phillips Petroleum Co.'s investigation of the effect of infill drilling on gas production and the potential of recovering additional reserves from the Oklahoma Hugoton field included four different studies.2-5 One of the more comprehensive studies was a reservoir simulation study that is the subject of this paper. A three-layer, no-crossflow, 3D reservoir model was developed to simulate the performance of original and infill wells in a 12-section study area of Phillips' Oklahoma Hugoton acreage in the southern portion of the Oklahoma Hugoton gas field. We demonstrate how a unique history-match of performance data of the original wells was obtained with virtually no adjustment to the log-calculated input variables that determine original GIP and model performance. Any volumetric GIP adjustment would, of course, be crucial to the evaluation of infill-drilling potential. The performance data that were history-matched in our model study included (1) >40 years of official state test annual wellhead shut-in pressure with cumulative production data, (2) official state test annual 72-hour deliverability test rate and flowing pressure data, (3) individual layer pressure data obtained from an expendable well drilled in the 12-section study area, and (4) pressure/cumulative production and deliverability test performance data of a replacement well in the 12-section study area.
The history-matched model was used (1) to calculate the study area's total recoverable reserves and individual layer reserves, with and without infill wells, and (2) to forecast production rates for the study area, with and without infill waells, at current market demand and with all wells produced wide open. Study results show that a second well on a proration unit does not improve drainage or recovery compared with that of the current 640-acre spacing pattern and that the long life (108 years) associated with the Oklahoma Hugoton field is to be expected because of its layered, no-crossflow nature.
Cyclical sedimentation in the Hugoton basin produced a Lower Permian section composed of successive cycles of laterally continuous and mappable, shallow marine carbonate intervals (Florence, Towanda, Ft. Riley, Winfield, Krider, and Herington limestones), each capped by reddish-brown terrigenous siltstones, mudstones, and shale intervals (Oketa, Holmesville, Gage, Odell, and Paddock shales).6 Dolomitization of the carbonates has produced a continuous intercrystalline pore system that promotes good areal continuity of reservoir porosity and permeability in each carbonate interval. This areal reservoir continuity is supported by our various studies. Because of their low permeability and high threshold entry pressures, the intervening argillaceous units act as barriers to vertical flow between the carbonate units. Different pressures measured in individual layers by various operators confirm vertical heterogeneity or the layered, no-crossflow nature of the reservoir. Fig. 1 illustrates north-south and east-west cross sections through the 12-section study area showing the basic layering and layer continuity.
In the southern part of the Oklahoma Hugoton field where the study area is located, the principal producing reservoirs are the Herington, Krider, and Winfield members. They constitute three no-crossflow gas producing layers in our reservoir simulation model. All geologic layers below the Winfield and the lower portion of the Winfield in this part of the field are wet.
Ref. 6 gives an in-depth discussion of the geology of the study area and the rest of the Oklahoma Hugoton field. A description of the geology and a similar Lower Permian layering within the Kansas Hugoton field are in the testimony and exhibits presented in the Kansas Hugoton hearing.1
Model Study Area
In selecting a study area, we looked for a location that was central to our block of acreage in the Oklahoma Hugoton field with a high number of more recently drilled wells penetrating through the formations of interest. A further consideration was to select an area whose outer boundaries reasonably coincided with no-flow boundaries as determined by proportioning offset-well producing rates. A model area of 12 sections surrounded by 18 additional sections was selected, and all the sections had at least one deep well. The deep wells were drilled in the early 1960's and logged with a suite of modern logs. Layer correlations and reservoir parameters f, k, h, and Sw were ultimately developed from log analysis calibrated to core data for input into the reservoir simulation model. The 12-section study area also includes one section where a replacement well was drilled 2,259 ft from the original well in the extreme southwest quarter of its 640-acre section. Performance history-matching of a previously drilled replacement well with several years of production should verify the ability of our model to predict the performance of any infill wells drilled on a 640-acre section in our study area.
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