Screening, Integrated Characterization and Simulation of Mississippian Carbonate Fields in Kansas to Select Candidates for Infill Horizontal Drilling 

Saibal Bhattacharya1, Alan P. Byrnes1, Martin K. Dubois1, and Paul Gerlach2 
(1) Kansas Geological Survey; (2) Charter Development Corp.

Introduction 

Mississippian carbonate reservoirs in Kansas have produced over 1 billion barrels of oil, and at present represent almost 40% (about 14 million barrels/year) of the state’s annual production. Small independent operators, 90% employing less than 20 employees, operate most of these Mississippian fields. Traditionally, these fields have been characterized by low recovery efficiencies - attributed to reservoir heterogeneity, compartmentalization, and strong bottom-water drives. Low recoveries have left behind an estimated ~7 billion barrels of residual reserves. This represents a significant target for additional recovery using modern cost-effective evaluation tools and field management practices. Producibility problems characterizing mid-continent Mississippian fields include limited log, core, and production data, inadequate reservoir characterization, and sub-optimal production practices. Low-cost tools, based on modern techniques and applicable with limited data, are being developed to facilitate multi-disciplinary reservoir characterization to aid in effective field management. At the Kansas Geological Survey, a major emphasis has been placed on field studies where university scientists and engineers collaborate with independent producers to develop tools and techniques necessary for integrated characterization and modeling of Mississippian carbonate fields. 

Horizontal wells have been successfully applied to exploit thin-bedded compartmentalized reservoirs, fractured reservoir systems, and reservoirs producing under strong water drives. The objective of this project is to demonstrate the application of a horizontal infill well to enhance recovery from a mature Mississippian shallow shelf carbonate field. Techniques that have been applied include: A) inexpensive screening of assets for selection of candidate reservoirs with potential for horizontal infill drilling, B) integrated characterization of candidate sites with limited data to construct 3D reservoir geomodels, and C) use of PC-based reservoir simulators to history match, validate volumetrics, map residual reserves, and predict performance of horizontal infills. 

General geology of carbonate reservoirs in the study area

The Mississippian carbonate fields described in this paper are located on the southwest flank of the Central Kansas Uplift. Strata in these fields represent shelf carbonates deposited on a gentle sloping ramp. Post-depositional regional uplift, subaerial exposure and differential erosion at the pre-Pennsylvanian unconformity resulted in paleotopographic highs that have been targets of exploration and sources of production.

In these Mississippian reservoirs, the nature and distribution of reservoir properties is determined by the lithofacies despite overprinting by sub-aerial exposure and diagenesis. For a given porosity, strata with mud supported primary textures (mudstones and wackestones) generally have lower permeability and higher S_wi than do strata having grain supported primary textures (packstones). Reservoirs typically consist of alternating thin layers (3-9 feet) of mud-wackestones (non-pay) and packstones (pay) stacked in a gross reservoir interval of 20-33 feet. Since lithofacies are generally laterally extensive, a single porosity-permeability-saturation transform may be applied to a single layer.

Compartmentalization by lateral facies heterogeneity, truncation of subcropping reservoir layers, and small- and large-scale karst features are typical of these reservoirs. Karst processes during prolonged exposure have contributed to large-scale compartmentalization through controls on terrain morphology (km to 10’s km) and, at a smaller scale, by impermeable shale-filled near-vertical solution enhanced fractures. Intervals interpreted by log as shale partings and vertical permeability barriers may be small-scale karst features that act as horizontal barriers to fluid flow.

Quick screening of assets using cost-effective techniques

One of the principal causes of failure for horizontal wells has been poor evaluation and selection of targets. The inability to identify appropriate candidates for horizontal well applications coupled with higher drilling costs have been the two major reasons why the horizontal drilling potential of Kansas Mississippian carbonates has not been fully exploited. In Kansas for a majority of horizontal wells drilled till date, comprehensive screening of target reservoirs was not undertaken resulting in many economic failures. Based on the area of interest (Township 16S Range 26W to Township 27S Range 20W) of the industry partner Mull Drilling Co. Inc. (MDCI), 29 Mississippian fields from Kansas were selected for primary screening in this study. Horizontal wells drilled in pressure-depleted reservoirs often prove unproductive. Final DST shut-in pressures in developmental and infill wells drilled in and around each candidate field were mapped to evaluate the extent of depletion of reservoir pressure. Based on the strength of reservoir pressure support, 13 fields were short-listed for comparative screening studies. Petrophysical logs from type well(s) were analyzed to estimate possible ranges of pay height, porosity and initial water saturation in each field. These ranges were used to compute minimum and maximum volumes of original-oil-in-place (OOIP). Cumulative oil production volumes were used to calculate ranges of recovery factor (R.F.) and remaining-oil-in-place (ROIP) per acre-ft for each field. Average drainage area in each field was estimated from the area of the field and number of producing wells. The gross pay thickness maps were used to estimate minimum and maximum pay thickness in the undrilled (interwell) areas. Screening criterion used include ranking the fields on the basis of maximum pay (gross) thickness in the undrilled areas, high average well spacing, low R.F., and high ROIP per gross acre-ft. 

Five fields were selected, in consultation with MDCI, for secondary screening studies. A single-phase closed tank homogenous model (RESMOD, Maurer Engineering Inc.) was used to history match vertical well performance in these selected fields to quantify the reservoir drive mechanism-scaling factor and to confirm drainage area estimates. These factors where then used to predict performances of possible horizontal infill wells in each of the short listed fields. Also, a detailed inventory of available data (core, wire line log, production, and reservoir pressure) for each of the five short listed fields was carried out to determine the viability of constructing a 3D reservoir model for simulation studies. Based on these results, 3 fields were selected for detailed characterization and simulation studies.

Modeling reservoir heterogeneity with limited hard-data

Recognition of facies is a characterization challenge in old fields having limited core and log petrophysical data like those in central and southern Kansas. Up to half of the wells are openhole completions and do not have wire line logs. Also, a majority of wells have only Radiation Guard logs where curves carry little direct information about lithofacies. Here, facies were recognized by fundamental pore geometry-S_wi-log response relationships. Intervals above the oil/water contact having relatively high porosity yet low resistivity have mud supported textures, and are characterized by high saturations of bound water. Conversely high porosity and resistivity are correlated with packstones having higher permeability and lower S_wi. Information about initial saturation distributions in the reservoir is critical to OOIP and ROIP volume calculations, and therefore indispensable to mapping remaining potential. Because resistivity logs were unavailable in many wells, an inverse process was employed to estimate the initial saturation distribution. The initial water saturation in the drainage area of a well was iteratively varied until the simulation output history matched both fluid production data from the well and limited reservoir pressure data. Good matches were obtained when this method was tested on wells with known initial water saturation (i.e. where resistivity logs were available). A regular survey of producing fluid columns is required to develop a flowing bottom hole pressure (P_wf) history for a well. In a simulator, pressure history is a necessary input required for history matching fluid production. Unfortunately, many Mississippian fields in the mid-continent have little (measured infrequently) or no P_wf data. Advanced spreadsheet-based decline curve analyses were applied on well-level oil production data to determine if producing conditions remained unchanged during most of the productive life of the well. Production peaks deviating from the well’s characteristic decline were indicative of well stimulations (resulting in changes in skin and/or P_wf). This technique of approximating P_wf histories proved useful in achieving realistic well history matches quickly. 

Petrophysical modeling in Mississippian reservoirs (rock catalog)

Mississippian shallow shelf carbonates exhibit a wide range of lithofacies with each lithofacies generally exhibiting characteristic petrophysical properties including distinct porosity-permeability relationships. Also, capillary pressure and relative permeability changed with porosity/permeability/lithofacies. To construct accurate reservoir models and to modify these models to match production history it is important to assign reservoir properties that are consistent. During simulation history matching, changes in basic properties, like porosity and permeability, were always accompanied by corresponding change in capillary pressure and relative permeability properties so that the modeled reservoir properties remained consistent with known petrophysical trends. Relative permeability curves for any given permeability were modeled using Corey-type equations where S_wi was obtained from P_c-k relations and the assigned average absolute permeability value. To provide capillary pressure curves for the reservoir simulation it was necessary to develop generalized curves that represented the specific permeabilities that might be assigned to a grid cell. Equations to construct generalized capillary pressure curves were constructed based on the relationships evident from the entry pressures and curve shapes in the air-mercury capillary pressure curves, and from the saturations evident in the air-brine capillary pressure analysis. In the mid-continent, often cores are unavailable for a field of interest. An online Mississippian rock catalog is being developed as a part of this project to provide analog petrophysical data in the absence of physical cores from a field. 

Simulation studies

The final step in selecting the most prospective candidate reservoir for field demonstration, i.e., drilling the horizontal infill well, was reservoir simulation. For each of the 3 selected fields, a PC-based simulation study was carried out using the respective 3D-reservoir geomodel - constructed by integrated characterization studies. In each case, well-level fluid production data was history matched. Matching simulator calculated average reservoir pressure distribution with (limited) available pressure data enabled validation of the geomodel construct along with assumptions about reservoir drive mechanisms. Upon completion of history matching, residual reserves in each field were mapped. The residual reserve map served as the basis to place different targeted horizontal infill trajectories and the simulator was used to predict the performance for each infill under different operating conditions. 

Conclusions

This paper demonstrates the use of different inexpensive techniques that enable independent producers with limited resources to screen their assets, Mississippian carbonate fields of the mid-continent, to identify potential candidates for horizontal infill applications. Application of these tools and techniques have been demonstrated in data constrained environments, and procedures have been outlined for building an integrated and consistent reservoir geo-model. History matching of well production followed by a material balance crosscheck of average reservoir pressures has resulted in the validation of these geo-models. Full-field simulations have enabled mapping of residual reserves and prediction of productive potential of different infill horizontal wells. It is anticipated that field demonstration of these techniques will help build confidence among independent operators to use cost-effective horizontal infill applications to exploit mature carbonate reservoirs.