Gregory R. King

Material-Balance Techniques for Coal-Seam and Devonian Shale Gas Reservoirs With Limited Water Influx

This paper presents the development of two material-balance methods for unconventional gas reservoirs. One method is appropriate for estimating original gas in place; the second is appropriate for making reservoir predictions. These techniques differ from the material-balance methods for conventional gas reservoirs in that the effects of adsorbed gas are included. For estimating original gas in place, the assumption of equilibrium between the free- and adsorbed-gas phases is required. No additional assumptions are required for reservoir predictions

A parametric study of the effects of coal seam properties on gas drainage efficiency

A mathematical model which simulates the flow of methane and water through a coal seam was developed. Partial differential equations governing the flow of methane and brine were derived from mass balances applied to an elemental volume of the reservoir. A two-dimensional cartesian coordinate system was superimposed on the coal seam and was utilized to transform the continuous flow equations to discrete form by application of finite differences.

State-of-the-Art Modeling for Unconventional Gas Recovery

In this paper a series of mathematical and numerical developments that simulate the unsteady-state behavior of unconventional gas reservoirs is reviewed. Five major modules, considered to be unique to the simulation of gas reservoirs, are identified. The inclusion of these models into gas reservoir simulators is discussed in mathematical detail with accompanying assumptions.

Reservoir Modeling To Characterize Dual Porosity, Tengiz Field, Republic Of Kazakhstan

Tengiz Field is the world’s deepest developed supergiant oil field, with an oil column height of nearly 1600 meters. The reservoir consists of Devonian and Carboniferous platform/slope carbonates, divided into three stratigraphically-defined producing units. Production of more than 500,000 BOPD is mainly from the upper unit. A significant portion of this production is controlled by natural fractures. A new reservoir model has been constructed to support a future growth project, including miscible gas injection, and to provide input to reservoir management strategies, development planning, and oil-in-place estimation.

State-of-the-Art Modeling for Unconventional Gas Recovery, Part II:Recent Developments

In, 1989, a survey of mathematical models which describe methane production from coal seams was presented at the SPE Joint Rocky Mountain Regional/Low Permeability Reservoirs Symposium in Denver, Colorado. This paper was later published in SPE Formation Evaluation Journal March 1991 issue. In this survey, 37 distinct models for coalbed methane production were reviewed in mathematical detail. Since that time, 15 additional mathematical approaches to forecasting reservoir performance, each with its own assumptions and limitations, have been developed. The objective of this paper is to discuss each of these recent models and to compare the assumptions, features, and limitations of these models with each other and with the original 37 models. Recommendations are also presented on the use of each model.

Numbi Field: Adapting a Reservoir Management Strategy to Changing Reservoir Conditions

The Numbi Field is located approximately 20 miles offshore of the Angolan enclave of Cabinda. Put on production in 1987, the Numbi 57-05 Vermelha reservoir has been a prolific oil producer. After water injection commenced in 1991 into 14 peripheral injectors, the 49 production wells had a peak production of over 85,000 barrels of oil per day (BOPD). However, after reaching peak production in 1992, the reservoir experienced a rapid production decline. In order to minimize the decline and thus maximize recovery, interim and long term strategic reservoir management changes were required. Interim solutions to problems have included running through-tubing bridge plugs, adding through-tubing perforations, performing selective completions with rig workovers, performing acid pre-pack gravel packs in injection wells, and shutting in high gas producing wells. The through-tubing work, intended to shut off excessive water or gas production and open unproduced intervals, has contributed 16,000 BOPD of incremental production. The selective completions have increased production by 14,000 BOPD. The wells that have been gravel packed have shown an initial 75% increase in injection and have not experienced further sanding problems. The short term changes have been effective in slowing the current production decline. Although the recent well work has slowed the production decline, it has not arrested the depletion of reservoir pressure. A new longer term strategy is required to address this issue. In order to develop a long term strategy, a detailed geological model was assembled. This model was then used as a basis for a finely detailed (25 layers, 102,000 cell) simulation model. The simulation model showed that particular layers and certain areas of the field were under-injected. The model also showed that large quantities of oil (approximately 30 MM barrels to date) have been displaced into the gas cap. An aggressive repressurization strategy is required to prevent further pressure depletion and to minimize the volume of oil displaced into the gas cap. Initiating injection into up-dip injectors that penetrate the gas cap is anticipated to result in incremental recovery of 35.1 MM barrels by the year 2010.