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Abstract Material balance analysis is a fundamental technique for estimating gas-in-place. It can be achieved using:Static material balance, using static (shut-in) reservoir pressures, where a plot of static p/z versus cumulative gas production is created to estimate original-gas-in-place (OGIP) or Flowing material balance where gas rates and flowing pressures are used to estimate average reservoir pressure. The flowing material balance concept of Agarwal-Gardner (1999) was extended to dry coalbed methane (CBM) reservoirs by Clarkson et al. (2007a) and Gerami et al. (2007) and to 2-phase (gas and water) CBM wells by Clarkson et al. (2007b). The present study further enhances the flowing material balance for dry CBM reservoirs by presenting a p/z* implementation of the concept. This application, while accounting for the distinguishing characteristics of a CBM reservoir, uses the industry-standard practice of p/z material balance to calculate original-gas-in-place. As with the Agarwal-Gardner approach, the flowing p/z* method can be applied to variable gas rates and/or flowing pressures conditions. In the present work, the derivation and iterative procedure of calculations are explained. Several test cases based on dry/immobile water saturation using real and synthetic data were generated. The resulting estimates of OGIP calculated from implementation of flowing p/z* material balance show excellent agreement and the estimated OGIP's are reliable. Introduction Material balance is the application of mass balance to a producing reservoir. As gas is produced, the reservoir pressure declines. By monitoring the cumulative gas production and the average reservoir pressure, and using the PVT properties of gas, one can determine OGIP and the remaining gas-in-place. Material balance analysis, although simple and more reliable than volumetrics calculation, does suffer from a number of shortcomings and limitations. For example, to measure the average reservoir pressure the well has to be shut-in and that means loss of production. Among other complexities are:low permeabilities lead to poor pressure build-ups (long-buildup times required) pressure build-up can be masked in multiple coal seams reservoir can be recharged from aquifers CBM reservoirs have additional complexities. The gas storage mechanism as well as the compressibility of CBM reservoirs is dominated by adsorption. These and other CBM-specific characteristics have to be accounted for in any material balance calculations.

doi: 10.2118/114995-MS

SPE-114995-MS

application, average reservoir pressure, calculation, CBM reservoir, coal bed methane, coal seam gas, coalbed methane, complex reservoir, compressibility, Compressibility Factor, cumulative gas production, cumulative production, Drillstem Testing, drillstem/well testing, dry coalbed-methane reservoir, equation, estimates of resource in place, Material Balance, Petroleum Engineer, production control, production monitoring, pseudo-pressure, reserves evaluation, reservoir simulation, Reservoir Surveillance, resource in place estimate, spe 114995, Upstream Oil & Gas, volumetric calculation

Country:

- North America > Canada (0.48)
- North America > United States (0.47)

SPE Disciplines:

Abstract Oil production in Egypt is based on the development of mature fields with highly complex geological and reservoir characteristics; therefore, a great amount of creativity is required to operate these oil fields. One of the main elements for development of mature fields is to estimate the reserves and determine the amount and location of the remaining oil. Material balance equations have been used in petroleum engineering for many years to estimate the original hydrocarbon in place. This paper documents the ability of using the analysis of the material balance results in the reservoir characterization and determination of the remaining oil location. The applicability of this work is confirmed by actual field case study (Shukheir Bay Field) in Offshore Shukheir Oil Company (an international joint venture company in Egypt). Such study is an original contribution to the knowledge of the material balance results analysis. Introduction The material balance equation in the reservoir engineering is based on the principle of the conservation of mass (Mass of fluids originally in place = Fluids produced + Remaining fluids in place). The general form of the material balance equation was first presented by Schilthuis in 1941.1 In this equation; the cumulative withdrawal of reservoir fluids is equated to the combined effects of fluid expansion in the reservoir resulting from a finite pressure drop, pore volume compaction, and water influx. In 1963, Havlena and Odeh 2,3 presented techniques for interpreting the material balance equation as a straight line, which makes it easy to apply graphical techniques. In particular, extrapolation of a straight line allows the prediction of future reservoir performance, while the parameters of the line often are simply related to in-place volumes or water influx performance.4 The results of the material balance calculations are affected strongly by the selection of the PVT data. The gas liberation in the reservoir changes with the reservoir pressure. In the case of reservoir fluids above/at the bubble point, as the pressure decline due to withdrawals, the gas librated from oil does not flow to the well but accumulates until the critical gas saturation is reached. When the critical gas saturation is reached near the well bore, the gas may be moving more rapidly than the oil (differential liberation) whereas the remainder of the area the liberated gas remains in contact with the oil (flash liberation). Therefore, flash liberation data more closely represent the reservoir liberation process.5 Shukheir Bay Field Data used in this research was obtained from Shukheir Bay field (Offshore Shukheir Oil Company - OSOCO), which is located in the shallow water close to the western coast of the southern part of Gulf of Suez (about 20 km south of Gharib - Egypt- Fig. 1). The field has been developed by drilling four deviated wells from the shore line. Three wells (SHB-1, SHB-2 and SHB-4st) are completed in Lower Rudies Sands while the fourth well (SHB-3st) is completed in Karim formation. In December 1980, Well SHB-1 was completed on Lower Rudies Upper Sand (Pay I) and started production with 2200 BOPD and 0.8 MMSCF/D gas. The initial reservoir pressure is 2470 psi; however, the bubble point pressure of the produced oil is 2241 psig. Since December 1980 till now, the main reservoir (Lower Rudies Sands) has produced a cumulative of about 5 MMSTB of 34 API gravity oil from two pay zones (Pay I and Pay II) through two wells (Wells SHB-1 and SHB-4st). Well SHB-2 was completed in an isolated dry zone and Well SHB-3 was completed in another formation (Karim Formation). The production performance curve of Lower Rudies Upper Sands (Pay I and Pay II) is shown in Fig. 2. Currently, the main producing well (Well SHB-1) is on jet pumping producing about 700 BOPD with 70% water cut and estimated GOR of 680 SCF/B. The reservoir pressure declined to its current value of about 1800 psig. Recently, a complete reservoir study for the development of Shukheir Bay Field was performed. Material balance equation was used through the study to (1) estimate the original oil in place and the reservoir driving mechanisms, (2) identify the reservoir characteristics and provide more geological, engineering and structural understanding of the Lower Rudies reservoir, and (3) define the best location(s) of new producer(s) to be drilled in order to increase field production and enhance the recovery factor.7

doi: 10.2118/108648-MS

SPE-108648-MS

calculation, Drillstem Testing, drillstem/well testing, estimates of resource in place, Material Balance Equation, Mmstb, original oil in place, Pay II, Petroleum Engineer, petrophysical data, production data, PVT data, PVT measurement, reserves evaluation, reservoir, Reservoir Characterization, reservoir simulation, resource in place estimate, shb-1 pvt data, Shukheir Bay Field, Upstream Oil & Gas, volumetric calculation, well shb-1, well shb-4st

Country:

- Africa > Middle East > Egypt (0.74)
- North America > United States (0.46)

Oilfield Places: Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > Rudeis Formation (0.98)

SPE Disciplines:

- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)

Unsolicited. This document was submitted to SPE (or its predecessor organization) for consideration for publication in one of its technical journals. While not published, this paper has been included in the eLibrary with the permission of and transfer of copyright from the author.

Abstract

When fluids are withdrawn from a petroleum reservoir, the space left behind is filled partly by the expansion of the remaining fluids and rock and partly by the influx of water from a contiguous aquifer, if it exists. The partly by the influx of water from a contiguous aquifer, if it exists. The volumetric balance equation (VBE) is an expression of this same statement. Its simplified form is Eq. 1.

When sufficient historical data on X and Z are available, various functions for Y can be tried, and by the technique of least squares a set of values can be calculated for A and B.

It has been convenient to write the equation in the following form: Eq. 2.

The advantage of this form is that (1) it has only two variables, and least-square calculations are easier for it and (2) the values of Y/X and Z/X can be graphically plotted so that the linear trend can be visually examined. The disadvantage is that the equation has a low dissolving power and can produce erroneous answers. Nevertheless, in a literature survey carried out it was found that most authors used the form of Eq. 2.

Eq. 1 may be written in many different forms, all of which are algebraically equivalent with each other; however, when the method of least squares is applied to them, they will produce different results.

In this paper it is shown that the best forms of the VBE for calculation of the original active oil in place and water influx constant in the form of Eq. 1 and Eq. 3.

It is also shown that least-square calculation based on minimizing the sum of the squared deviations of the calculated oil pressures from the observed pressures is equivalent to carrying out the least-squares method on Eq. 1 pressures is equivalent to carrying out the least-squares method on Eq. 1 or Eq. 3.

Introduction

The Volumetric Balance Equation (VBE). The volumetric balance equation was first introduced in the general form by Schilthuis in 1935.1 In AIME notations it can be written as follows:

application, balance equation, calculation, case 1, case 5, deviation, Drillstem Testing, drillstem/well testing, equation, estimates of resource in place, History, influx constant, oil pressure, reserves evaluation, reservoir, resource in place estimate, simulation model, square deviation, Standard Deviation, Trans, Upstream Oil & Gas, vbe, volumetric balance equation, water influx, withdrawal

Oilfield Places:

SPE Disciplines:

Anjum, Muhammad Ghufran (Pakistan Petroleum Limited, Karachi Pakistan) | Khan, Muhammad Noman (Pakistan Petroleum Limited, Karachi Pakistan) | Rizwan, Muhammad (Pakistan Petroleum Limited, Karachi Pakistan) | Khan, Muhammad Wahjuddin (Pakistan Petroleum Limited, Karachi Pakistan)

Abstract Material balance P/Z method is widely applicable concept in reservoir engineering to estimate GIIP in volumetric dry gas reservoirs. The application of conventional P/Z method is based on constant pore volume assumption and reliable production of GIIP & PVT data. In newly drilled prospects there is always huge uncertainty in dynamic GIIP due to unavailability of significant production & pressure data [1] and uncertainty of drive mechanism. However, production tests (Reservoir Limit Test, Interference Test, etc.) for longer duration are usually designed to acquire reliable production and average reservoir pressure data to have indicative estimates of GIIP and drive mechanism in order to have development & appraisal program with more certainty. Low BTU gas with more than 50% inert in the gas cannot be allowed to be injected in the buyer's network. Commercial development of such discoveries for power generation needs firm commitments of gas supply which is based on GIIP estimates which usually have uncertainty due to lack of production and pressure data at the time of discovery. In this paper we will give a brief insight on the techniques to acquire reliable production data with longer production tests & their limitations, Pros & Cons of conventional P/Z approach for GIIP estimation in the newly drilled prospect. The case study will show how the limited pressure & production data may also be utilized with caution to have minimum GIIP estimates using P/Z method especially in case of overpressure reservoir where drive mechanism is most likely volumetric by designing simplified numerical modeling approach without conducting longer production tests. However, this technique has limitations in case of poroelastic nature of reservoir.

development strategy, discovery, Drillstem Testing, drillstem/well testing, drive mechanism, Engineer, estimates of resource in place, GIIP estimate, information, interference test, interpretation, numerical model, pressure data, pressure depletion, production control, production data, production monitoring, production test, reserves evaluation, reservoir, Reservoir Engineer, reservoir pressure, Reservoir Surveillance, resource in place estimate, Upstream Oil & Gas, volumetric giip estimate, well-a

Summary One of the most-important bases for field-development planning is the estimate of hydrocarbon initially in place (HIIP), which has been traditionally estimated either deterministically or by Monte Carlo simulation. The classical volumetric calculation is the most-common deterministic method, and it requires the use of the averages of the reservoir variables and thus does not model the correlations of the input variables. It is well-known that ignoring the correlations among the reservoir variables can lead to incorrect estimations of hydrocarbon volumetrics. The Monte Carlo method uses the input means in the volumetric equation for random simulation of hydrocarbon volumes, yet allows modeling of the correlation between the input parameters. However, using the means and modeling the correlation of the properties are theoretically conflicting. This paper presents new parametric equations for volumetric calculation using mathematical correlation. Unlike the classical volumetric calculation, these equations are the exact expressions of the rigorous hydrocarbon volumetric equation. We discuss how these new equations enable the quantification of inaccuracy in hydrocarbon volumetric estimation by the classical method. Our examples will further show that the magnitude of inaccuracy of the traditional volumetrics depends on the reservoir characteristics; the inaccuracy is generally more significant for heterogeneous, low-quality, and tight reservoirs than for relatively homogeneous high-quality reservoirs.

Artificial Intelligence, calculation, classical volumetric calculation, complex reservoir, correlation, equation, estimates of resource in place, geologic modeling, geological modeling, HIIP, hydrocarbon saturation, hydrocarbon volumetric, input variable, machine learning, means, october 2018, porosity, reserves evaluation, Reservoir Characterization, reservoir property, reservoir simulation, resource in place estimate, statistical parameter, statistics, Underestimation, Upstream Oil & Gas, volumetric calculation, volumetric equation

Thank you!