Oil and Gas Reserve Estimation PDF

OIL AND GAS RESERVE ESTIMATION Prof. T. Kumar Dept. of Petroleum Engg. IIT (ISM), Dhanbad-826004 Introduction: Calculation of hydrocarbon reserves and prediction of future recoveries are important aspects of the evaluation....

OIL AND GAS RESERVE ESTIMATION Prof. T. Kumar Dept. of Petroleum Engg. IIT (ISM), Dhanbad-826004 Introduction: Calculation of hydrocarbon reserves and prediction of future recoveries are important aspects of the evaluation. Reserves indicate value of an oil/gas property, while the rate of production determines the economics. Reserves usually indicate the oil and/or gas, which may be recovered at economic rates using only the natural reservoir forces (primary recovery). Reserves resulting from secondary recovery, usually denoted as secondary reserves are normally considered separately. Time of the Evaluation Reserve is a fluid thing and should be determined periodically. Their accuracy depends on the quality and quantity of data available. Since more information necessarily accumulates during the life of a property, the reserve estimates become correspondingly more accurate. Different stages of exploration and exploitation during which reserves are determined, may be shown as: 1) Prior to drilling and development 2) Just after drilling and completion 3) After at least one year’s production data are available, the well or lease still producing its allowable. 4) When the property in question cannot produce it’s allowable and production is declining. 5) At depletion. 1  Even at depletion, where the maximum production data are available, the reserves are only relative, for they reflect only those reserves obtained from the producing methods used. During the production life of the property a change in production method will often change the reserve picture. The following basic methods are available for estimation of reserves: (A) Volumetric calculation (B) Material balance (C) Production decline Curves (D) Comparison of the reserves with those of similar and /or offset properties having similar geological and other reservoir conditions. (E) Comparison of the data from the same formation in other fields, usually expressed in barrels per acre foot. In cubic meters per hectare-meter (India). Methods (D) and (E) are known as comparative methods. Table 1 Methods for Analyzing oil reserves Time period % of Primary Reasonable Reserves methods range of produced of estimate error Prior to drilling 0 D and E 10-100 percent After 0 A,D and E 5-50 percent completion During 1-10 A,B,D and E 5-30 percent production 2 During 10-30 A,B and C 5-20 percent production During 30 – 60 B&C 5-10 percent production 60 & higher C about 5 percent Definitions and classification of Reserves & Ultimate Recovery The estimated ultimate recovery or ‘ultimate’ which a given property is expected to produce during its life time is usually determined by volumetric methods. Cumulative Recovery The cumulative production on a given date is usually referred to as ‘cumulative’. Remaining Reserves Estimates made during the ‘performance period’ usually by decline curves, yield the estimated remaining reserves or ‘reserves’ for a given date. Before performance data or decline curves are available the remaining reserves for a given date may be obtained by subtracting the cumulative production on that date from the ultimate recovery estimated by volumetric methods. ‘Reserves’ = ‘Ultimate’ – ‘Cumulative’. 3 SPE/WPC CLASSIFICATION OF RESERVES (JPT, MAY 1997) RESERVES: Reserves are estimated volumes of crude oil, condensate, natural gas, natural gas liquids, and associated substances anticipated to be commercially recoverable from known accumulations from a given date forward, under existing economic conditions, by established operating practices, and under current government regulations. Reserve estimates are based on interpretation of geologic and/or engineering data available at the time of the estimate. PROVED RESERVES: Proved reserves can be estimated with reasonable certainty to be recoverable under current economic conditions. Current economic conditions include prices and costs prevailing at the time of the estimate. Proved reserves may be developed or undeveloped. In general, reserves are considered proved if commercial producibility of the reservoir is supported by actual production or formation tests. UNPROVED RESERVES: Unproved reserves are based on geologic and/or engineering data similar to that used in estimates of proved reserves. But technical, contractual, economic or regulatory uncertainties preclude such reserves being classified as proved. They may be estimated assuming future economic conditions different from those prevailing at the time of the estimate. 4 UNPROVED RESERVES DEFINITIONS Unproved reserves may be divided into two sub classifications: probable and possible. PROBABLE RESERVES: Probable reserves are less certain than proved reserves and can be estimated with a degree of certainty sufficient to indicate that they are more likely to be recovered than not. POSSIBLE RESERVES: Possible reserves are less certain than probable reserves and can be estimated with a low degree of certainty, insufficient to indicate whether they are more likely to be recovered than not. RESERVE STATUS CATEGORIES Reserve status categories define the development and producing status of wells and/or reservoirs. DEVELOPED: Developed reserves are expected to be recovered from existing wells. Improved recovery reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Developed reserves may be subcategorized as producing or nonproducing. 5 PRODUCING: Producing reserves are expected to be recovered from completion intervals open at the time of the estimate and producing. Improved recovery reserves are considered to be producing only after an improved recovery project is in operation. NON-PRODUCING: Non-producing reserves include shut -in & behind-pipe reserves. Shut-in reserves are expected to be recovered from completion intervals open at the time of the estimate, but which had not started producing, or were shut-in for market conditions or pipeline connection, or were not capable of production for mechanical reasons, and the time when sales will start is uncertain. Behind-pipe reserves are expected to be recovered from zones behind casing in existing wells, which will require additional completion work or a future recompletion prior to the start of production. UNDEVELOPED: Undeveloped reserves are expected to be recovered : (1) from new wells on undrilled acreage, (2) from deepening existing wells to a different reservoir, or (3) where a relatively large expenditure is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects. SPE/WPC/AAPG Petroleum Resources Management System 2007 The 2007 system builds on previous industry efforts to provide sufficient guidance to achieve a high level of consistency in estimating resource quantities; it incorporates best practices identified in other international petroleum and minerals classification systems. It recommends a rigorous approach based on applying a series of defined projects to hydrocarbon-bearing reservoirs. 6 SPE-RMS Classification and Categorization Guidelines In order to promote consistency in petroleum resources evaluations, results reporting and portfolio management, the SPE-RMS slightly modified the prior basic classification framework and presented the modified concept of Resource Management System shown in the figure below. Within this two dimensional framework, projects are “classified” according to their commercial certainty (the chance of being developed through to producing status) and estimates of recoverable quantities associated with each project are “categorized” based on recovery certainty. 7 Types of Reservoir Fluids: Reservoirs may be generally subdivided in accordance with the type of fluid produced. There are three common categories: (1) oil, (2) gas and gas-condensate, and (3) volatile oil. Several such reservoirs may be encountered and produced by a given well. Volatile oil is normally referred for the oil produced from deep reservoirs, which occur in the reservoir as liquid and exhibit a large degree of shrinkage when brought to the surface. It is usually characterized by gravities greater than 45oAPI, formation volume factors above 2 and high solution gas-oil ratios. Condensate is normally the light fluid produced primarily by retrograde condensation, from a reservoir consisting of a gaseous fluid at or above the critical. The word condensate (or distillate) is also sometimes used for any fluid of high API gravity having no appreciable color. Black oil might best be described as any liquid other than those listed above. The distinction between oil and volatile oil is particularly important, since some of the estimation methods which are applied to the former are very unsatisfactory for the later. The volumetric method, for example, is less satisfactory in the estimation of volatile oil reserves than with black oil. COMPUTATION OF RESERVOIR VOLUME BY VOLUMETRIC METHOD: One of the necessary steps in solving the volumetric equations is the determination of the number of acre-feet (hectare-meter in India) of reservoir containing hydrocarbons. When sufficient subsurface control is available, the oil or gas-bearing net pay volume for a reservoir may be computed in several different ways. 8  From subsurface data a geological map is prepared, (Appendix Fig. 1) contoured on the subsea depth of the top of the sand (solid lines), and on the subsea depth of the base of the sand (dashed lines). The total area enclosed by each contour is then planimetered and plotted as abscissa on an acre-feet diagram against the corresponding subsea depth as the ordinate. Gas-oil and oil-water contacts as determined from core, log, or test data are shown as horizontal lines. After connecting the observed points the combined gross volume of oil and gas-bearing sand may be: A. Planimeterd from the acre-feet diagram 9 B. If the number of contour intervals is even, computed by Simpson’s rule. Volume = 1/3h (ao + 4a1 + 2a2 + 4a3 + …… +2an-2 + an) + tn an Where h=contour intervals (feet) ao= area enclosed by zero contour (at oil-water contact - acres). a1= area enclosed by first contour (acres) a2= area enclosed by second contour (acres) an= area enclosed by nth contour tn= average formation thickness above the top contour. Note: Simpson’s rule is accurate for irregular curves C. With somewhat less accuracy, volume calculated by the trapezoidal rule. Volume = ½ h (ao + 2a1 + 2a2 + …. + 2an-1 + an) + tnan D. Computed by means of the somewhat more complicated pyramidal rule. V0- n = (1/3) h (Ao + An + √ Ao An) For best accuracy the pyramidal formula should be used. However, because of its simpler form, the trapezoidal formula is commonly used which introduces an error of < 2% when the ratio of successive area of contours is 0.5. If the ratio of areas of any two successive isopach lines is less than 0.5, the pyramidal formula is applied. Form a study of the individual well logs or core data it is then determined what fraction of the gross sand section is expected to carry and produce hydrocarbons. Estimating this net-pet fraction is often aided greatly when micro-or contact logs are available. In shaly sand sections, the area under the SP curve above the shale line is sometimes used as a yardstick for the net-pay fraction. Multiplication of this net- pay factor with the gross sand volume yields the net pay volume. 10 Volumetric Method of Reserve Estimation The volumetric calculation of oil or gas reserve consists primarily of determining the volume of rock holding hydrocarbons, the total voids in such rock, the volume percentage of the voids containing hydrocarbons, and percentage of these hydrocarbons economically recoverable in the stock tank. Reserves are normally expressed in stock tank barrels (STB) or stock tank cubic meter for liquid, or MMCF (million standard cubic feet) or MMSCM (million standard cubic meters) for gas, (a) Oil in Reservoir (no free gas present in oil-saturated portion) 7758 is the number of barrels per acre-foot & Ø is the porosity, Sw is the interstitial water saturation, Bo is the formation volume factor, Vo is net pay volume of the oil bearing portion of reservoir, acre-foot. (b) Free Gas in Gas Reservoir or Gas Cap (no residual oil present) Where 43,560 is the number of cubic feet per acre-foot, Vg = net pay volume of the free-gas bearing portion of a reservoir, acre-foot, Bg = gas formation volume factor. (c) Solution Gas in Oil Reservoir (no free gas present) 11 MATERIAL-BALANCE METHOD: The material balance is one of the basic means of predicting reserves, as well as future reservoir performance. Theoretically, it contains no errors, practically speaking, though, it is never exact because of errors in the data used and the assumptions necessary to express it in terms of measurable properties. Because of this latitude, many forms of balances have been proposed. Original oil in place, N is estimated from the following generalized Material Balance Equation in which production data, PVT data and other relevant data are required to be input. The numerator in the MBE represents the underground withdrawal term, whereas the denominator represents the sum of oil & gas expansion, gas cap expansion, pore volume reduction and connate water expansion. Symbols and units of the above equations: N = reservoir oil in place, STB Np = cumulative oil produced, STB m = ratio between initial reservoir free gas volume and initial reservoir oil volume Bt = two-phase formation volume factor for oil Bg = gas formation volume factor Bo = oil formation volume factor Rp = cumulative gas-oil ratio, SCF/STB Rs = gas-solubility factor We = cumulative water influx, bbl. Wp = cumulative water produced, bbl. Cf = compressibility factor for reservoir rock (Vol)/(Vol)(psi) Co = compressibility factor for reservoir oil Cw = compressibility factor for interstitial water Sw = interstitial water saturation 12 Equations (2) and (3) are solved for the constants C and C’ using existing production data, m has to be found by other means. The procedure involves writing equation (1) substituted for We. The balance then has only Np and the integral has unknowns. Substitution of production and pressure data for successive intervals enables us to calculate N and C (or C’) by the method of average least square. Determination of N The calculation of N is one of the basic uses of balances. The simplest, rough approach is to assume that m and We are zero. A more realistic approach is to determine m volumetrically. 13  The assumption that We equals zero initially is not bad, for no large amount of water influx should be expected, during the early stages of depletion. The validity of this assumption may be checked in two ways. One is to compare the N thus found with the volumetric value of N. Another is to calculate N over successive intervals. If N remains substantially constant, we may reasonably deduce that no water drive exists. Where a water drive does exist, values of N determined may be plotted against some time function such as Np. Extrapolation back to Np = 0 then yields a good probable value. Regardless of the method used the final value of N chosen should be one that is consistent with all date. In the very early stages of depletion, the volumetric method is usually the most accurate, whereas the material balance gains performance in the later stages of depletion. Unit-Recovery Formula: The unit recovery factor is the theoretically possible ultimate recovery in stock-tank barrels from a homogeneous unit volume of 1 acre-foot of pay produced by a given mechanism under ideal conditions. The unit-recovery factor for a saturated depletion type reservoir is equal to the stock-tank oil initially in place in barrels per acre-foot at pressure Pi - the residual stock-tank oil under abandonment pressure Pa. Oil Reservoirs with Water Drive (Volumetric Method) Natural –water influx into oil reservoirs is usually from the edge inward parallel to the bedding planes (edge-water drive) or upward from below (bottom-water drive). Bottom-water drive occurs only when the reservoir thickness exceeds thickness of the oil column, so that the oil-water interface underlies the entire oil reservoir. 14  Units Recovery for a water drive reservoir is equal to the stock- tank oil originally in place in barrels per acre-foot minus the residual stock-tank oil at abandonment time. PRODUCTION-DECLINE CURVES Estimates of ultimate recovery by extrapolation of a performance trend fundamentally all follow the same platform. The two quantities one usually wishes to determine are either remaining oil reserves or remaining productive life. Cumulative production and time are therefore normally selected as independent variables and are plotted as abscissas. A varying characteristic of the well performance which can be easily measured and recorded is then selected as a variable to produce a trend curve. By plotting values of this continuously changing dependent variable as ordinates against the values of the independent variable (cumulative production or time) as abscissas, and graphically extrapolating the apparent trend until the known end point is reached, an estimate of the remaining reserves can be obtained. Amongst the many dependent variables which can be used in estimates based on performance trends, the rate of production is by far the most popular when production is not restricted. In that case one commonly refers to production decline curves. The two main types are rate-time and rate-cumulative curves for each of the two independent variables. Rate of oil production as the 15 dependent variable has the advantage always being readily available and accurately recorded. Gradual changes in the production rate of a well may be caused by: 1. Decreasing efficiency or effectiveness of the lifting equipment. 2. Reduction of productivity index, or completion factor, or increase in the skin effect due to physical changes in an around the wellbore such as deposition of wax, salt or asphaltenes from the produced fluids or the accumulation of loose sand, silt, mud, or caving. 3. Changes in bottom-hole pressure, gas-oil ratio, water percentage, or other reservoir conditions. Unless defective conditions of the wellbore are detected or cured, the reserve estimates obtained by decline-curve analysis will be limited to those recoverable under existing and sometimes only partially effective wellbore conditions. Normal and Effective Decline: There are two types of decline: The nominal decline rate D is defined as the negative slope of the curve representing the natural logarithm of the production rate q vs time t, or Normal decline, being a continuous function, is used mainly to facilitate the derivation of the various mathematical relationships. The effective decline rate De, being a stepwise function and therefore is better agreement with actual productive recording practices, is the rate more commonly used in practice. It is the drop in production 16 rate from qi to q1 over a period of time equal to unit (1 month of 1 year) divided by the production rate at the beginning of the period. The time period may be 1 month or 1 year for effective monthly or annual decline, respectively. Different types of Production-decline curves: Three types of production – decline curves are commonly recognized. (i) Constant-percentage decline (Exponential decline) with constant percentage decline, the nominal decline rate, which after integration leads to the rate-time relationship After integrating a second time, the cumulative production at time t is obtained as expressed by the rate-cumulative relationship From Eq. (2), the remaining life to abandonment time may be obtained as 17 Or by elimination of decline D with equation (4) In other words the future life under constant-percentage decline will be (r ln r)/(r-1) times as long as the life required to produce the same ultimate Npa at constant rate qi (ii) Hyperbolic Decline : With hyperbolic decline the nominal decline rate D is proportional to a fractional power n of the production rate, this power being between zero and 1 After a second integration the cumulative production at time t is obtained as expressed by the rate-cumulative equation For production obtained by gravity drainage, where the type of decline is such that the exponent n = ½ the remaining life to abandonment time for this special case of hyperbolic decline, 18 Or after elimination of initial decline Di by equation (5) is In other words, the future life under hyperbolic decline (n = ½) will be √r time as long as the life required to produce the same ultimate Npa at constant rate qi. (iii) Harmonic decline (n = 1) Relationship between Effective and Nominal Decline The effective decline rate is De (Dei for initial conditions) for the three types of production-decline curves is related to the nominal decline rate D (Di for initial conditions) as follows: For constant – percentage decline, An analysis of a large number of actual production-decline curves by W. W. Cutler (USBM report 1924), indicates that most decline curves normally encountered are of the hyperbolic type, values of the exponent, n varying between 0 and 0.7, while the majority fall between 19 0.2 and 0.4. Gravity Drainage production under certain conditions have an exponent n = 0.5. The occurrence of harmonic decline (n=1) is rather rare. Loss-Ratio Method The inverse of the nominal decline rate q/ (dq/dt) is called the ‘loss ratio’ and may be used for extrapolation purposes and for identification of the type of decline. In constant-percentage decline, the loss ratio is constant, while in hyperbolic decline, the first derivative of the loss ratio is constant equal to n. In harmonic decline the first derivative of the ‘loss ratio’ is constant and equal to 1. Other performance curves: Another variable which is often substituted for the production rate in water drive fields, particularly, when the production of oil is restricted, is the oil percentage of the total fluid produced. Since projections of this oil percentage vs time are not often requires, the oil-percentage vs cumulative is plotted. The end point in this case is the lowest oil percentage which, combined with the total fluid-producing capacity of the lease, will just cover operating expenses. Cumulative Gas vs Cumulative Oil: It is a characteristic of most depletion-type oil reservoirs that only a fraction of the oil in place is recoverable by primary production methods. Gas on the other hand, moves much more freely through the reservoir, and it can generally be assumed that at abandonment time only the solution gas in the remaining oil at the then prevailing pressure, plus the free gas at that same pressure are left in the reservoir. In other words, even though it is not known exactly how much oil may be recovered, a much firmer idea is generally available of the amount of gas that will be produced during the primary production period. This provides us with the possibility of an end point to a performance curve. Cumulative oil production is plotted on the horizontal scale, 20 while the cumulative gas production is plotted on the vertical scale. As in normal depletion type fields, the trend of the curve appears to steepen with increasing gas-oil ratios. For depletion-type reservoirs, the gas-oil ratio is sometimes plotted on semi log paper against cumulative oil. Such a curve often shows a fairly good straight-line relation-ship, which may be needed to predict the trend of the cumulative gas-cumulative oil curve. Types of decline Curve (Summary) The 6 most common types of graphically showing production data are: 1. production rate vs time 2. production rate vs cumulative production 3. percentage water cut in production vs cumulative production 4. water level vs cumulative production 5. cumulative gas produced vs cumulative oil 6. pressure vs cumulative production. The first two types are most common and it is these that give the graphical approach its decline curve label. Type (6) is suitable for estimating gas reserves. The third (3) approach is used on leases where the ultimate production is limited by the percentage of water in oil rather than the more decline in the oil production itself. The actual cut off point at which the percentage water becomes uneconomic depends on the water disposal cost and the actual barrels of oil produced, but it usually occurs between 90 and 95 percent water. The fourth type, utilizing water level, is applicable in water drive fields. A line is drawn parallel to the abscissa representing the subsea elevation at the top of the producing sand. Periodic determinations of water level allow one to plot water level versus cumulative oil production. Extrapolation of this data to the horizontal line yields the ultimate reserves. 21 22 Material-Balance Method for Non-Associated Gas Reservoirs: The best performance variable in the case of free-gas reservoirs is the static formation pressure. This pressure is usually measured periodically by bottom-hole pressure bomb, or if there are no liquids present in the tubing, it may be calculated from observed shut-in tubing pressures. SCF gas originally = SCF gas produced + SCF gas remaining Where, Original reservoir volume, cu. ft = V SCF gas originally = V/Bgi = G, SCF gas produced = Gp SCF gas remaining = [Original reservoir volume – Remaining liquid volume)]/Bg = [V – (We-Wp)]/Bg Therefore, V/Bgi = Gp + [V – (We-Wp)]/Bg If there is no active water drive, then We-Wp =0 and the material balance equation reduces to V/Bgi = Gp + V/Bg and the same equation for a gas reservoir without active water drive (We = 0) and without significant water production (Wp = 0) read as: Writing Bgi and Bg in terms of 0.00504 ZT/P from gas law, we have, P/Z = Pi/Zi - Gp (0.00504Ti)/V It is convenient to plot P/Z on the vertical axis and G p on horizontal axis. The ultimate gas recovery at the abandonment pressure P a is then found by the intersection of the curve with the value Pa/Za at abandonment time where Za is the gas compressibility factor at abandonment time and pressure. 23 24