Determination of Original Gas in Place in Ballycotton, Offshore Ireland
- Wei-Chun Chu (Marathon Oil Co.) | C.H. Fleming (Marathon Oil Co.) | K.M. Carroll (Marathon Intl. Petroleum Ireland Ltd.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- February 2001
- Document Type
- Journal Paper
- 11 - 15
- 2001. Society of Petroleum Engineers
- 5.7 Reserves Evaluation, 4.6 Natural Gas, 4.2 Pipelines, Flowlines and Risers, 5.5.8 History Matching, 4.1.2 Separation and Treating, 5.6.4 Drillstem/Well Testing, 4.1.4 Gas Processing, 5.7.1 Estimates of resource in place, 2 Well completion, 2.4.3 Sand/Solids Control, 5.5 Reservoir Simulation, 5.2.1 Phase Behavior and PVT Measurements, 4.1.5 Processing Equipment
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Early, accurate determination of original gas in place (OGIP) is highly desirable for planning the future of a gas field. This paper presents a case history of an offshore gas field, using a recently developed pressure-rate-time analysis technique to illustrate the effectiveness of the method. In addition, this paper demonstrates the great benefit of permanently installed pressure gauges in obtaining consistent pressure and flow-rate data for the effective use of the technique for subsea completed wells.
Early, accurate determination of OGIP is always desirable in a new gas field development, as this information is critical in decision making for reservoir management. For example, the optimum number of wells or the need for compression at the surface depends on OGIP. In addition, the operator is often required to project production rates in order to secure a gas sales contract. These decisions are typically made early in the life of a field, and erroneous estimates of OGIP can lead to poor decisions that may be costly or impossible to correct later in the field life.
Various reserve estimation methods have been published in the literature,1 ranging from basic material-balance calculation to decline-curve analysis. Recently, Agarwal et al.2 presented new production decline curves for analyzing well production data by combining type-curve and decline-curve analysis concepts.
In this report, we applied Agarwal et al.'s analysis techniques2 to pressure and rate measurements over a period of approximately 3,000 days at Ballycotton. Subsequent analysis of short-term performance data showed that an accurate estimate of OGIP was established from the first 6 months of production. The results were confirmed independently using reservoir simulation while examining the effects of water influx and production interference from Kinsale Head.
Geologic Setting and Field Description.
The Ballycotton gas field lies approximately 25 miles off the coast of Cork, Ireland in the North Celtic Sea basin. It was discovered in March 1989 and has been produced from Well 48/20-2 since July 1991 as a satellite field by means of a single subsea well completion and tieback to the Kinsale Head's Bravo platform. A location map is shown in Fig. 1.
The ‘A' Sand producing interval in Ballycotton and Kinsale Head is the focus of this paper. This sand extends from Kinsale Head gas field in the south to Ballycotton gas field in the north, thus connecting the two fields by a common aquifer. Ref. 3 gives a comprehensive geologic description of the region.
The Kinsale Head gas field was discovered in 1971 and was placed on production in October 1978. The existence of gas-processing facilities at Kinsale Head made it commercially feasible to produce Ballycotton, which at the time of discovery was thought to contain 80 Bcf from a volumetric study. About 760 Bcf of gas were produced from the ‘A' Sand of Kinsale Head by the time Ballycotton was placed on-line.
Immediately after Ballycotton was put on production in July 1991, an attempt was made to estimate OGIP from the initial production data. Assuming hydrostatic equilibrium between the two fields, the initial pressure at Ballycotton was estimated from 1978 pressures at Kinsale Head gas field. This pressure, compared to the Ballycotton pressure measured immediately before commercial production, shows a pressure loss of 50 psi, thus reflecting interference resulting from production at Kinsale Head. Pressure interference is transmitted through the common aquifer between Kinsale Head and Ballycotton. Because the complexities of water influx and interference cannot be easily accounted for in a gas/water system, it was difficult to provide an OGIP estimate from the simple material balance.
However, a numerical simulation study of a single well in an edge-waterdrive gas reservoir indicated that it was possible to estimate an OGIP from the drawdown data in the early life of a reservoir before the influence of water influx becomes dominant.4 Later, a full-field model was set up to examine the strength of water influx. This will be discussed in the simulation study section.
The Ballycotton completion was the first subsea development in the Celtic Sea. A permanent gauge was installed on the subsea tree in 285 ft of water to monitor wellhead pressure (WHP). From the corresponding gas rate and measured WHP, we calculated bottomhole pressure (BHP) with the Cullender and Smith method.5 Fig. 2 shows a graph of calculated flowing BHP and gas-flow rate between July 1991 and September 1999. Both pressure and rate are monotonically decreasing. Our goal was to determine the OGIP from the production-performance data with both flowing BHP and gas-flow rate.
Historical Development of Analysis Technique.
Analysis of the gas-production performance data involves nonlinear effects of gas physical properties and variable-rate production mode during boundary-dominated flow. Recognizing that the partial-differential equation governing the flow of gases is nonlinear, researchers have focused on correlating the gas-flow solutions with the appropriate liquid-flow solutions.6 Gradually, a new time function was developed to convert the production data of either constant rate or constant BHP into a form that could be analyzed with constant-rate liquid solutions. This section presents the historical development of these techniques.
To analyze monotonically declining rate and pressure data to estimate reserves, pseudosteady-state flow must be established in the long-term performance data. Using the principle of superposition, Blasingame and Lee7 showed that equivalent time, te, defined as cumulative production divided by the corresponding flow rate, could be applied to a liquid system in pseudosteady-state flow. This suggests that long-term performance data can be used to estimate pore volume by plotting the pressure difference (?=pi-pwf) normalized by the corresponding flow rate vs. te. The slope of the graph is used to calculate reserves for a slightly compressible liquid case.
Al-Hussainy et al.8 showed that during the boundary-dominated flow period there are considerable differences between the liquid and gas solutions. It is clear that nonlinear effects become dominant during the pseudosteady-state flow period, when the wellbore pressure depends on the physical properties of the produced gas and the flow rate.
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