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Louis Mattar

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Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the CIPC/SPE Gas Technology Symposium 2008 Joint Conference, June 16–19, 2008

Paper Number: SPE-114991-MS

Abstract

Abstract Traditional ("Arps") decline analysis is the most common reservoir engineering tool used for production performance forecasting. It has several advantages over other techniques in that it is simple to use, requires minimal data and is well understood by the industry. Currently, however, these methods are being misused in unconventional applications, such as tight gas. Production performance from tight gas reservoirs is characterized by steep initial decline rates and long periods of transient flow. If decline analysis is performed using this transient production data, the main assumption of boundary dominated flow (BDF) is violated and inaccurate forecasts may result. The goal of this work is to understand the behaviour of tight gas reservoirs during transient flow so that the familiar Arps method may be applied. The effects of different tight gas production responses (bilinear, linear, pseudo-radial, boundary dominated) are investigated. Finally, a methodology for applying traditional decline curve analysis to tight gas, with reference to long term transient flow, is presented. Introduction The goal of this work is to outline a method of production forecasting for tight gas reservoirs without the use of complicated tools. The most accepted and well understood forecasting tool is traditional decline curve analysis and for this reason is the focus of this paper. The general, hyperbolic form of the Arps decline equation is shown as Equation 1 . This equation is used to predict the gas flowrate (q) as a function of time (t). The hyperbolic decline exponent (b) can be determined by matching past production performance to Equation 1 . For gas wells, hyperbolic decline exponents (0<b<0.5) are expected during BDF [Fetkovich (1) (1996), Okuszko (2007)]. However, decline exponents much greater than one ("superbolic") have been used to forecast tight gas production with limited success. Many authors [Maley (1985), Cox (2002), Cheng (2007), Rushing (2007)] have investigated the use of traditional decline curve analysis to forecast production from tight gas reservoirs. Some authors [Maley (1985), Robertson (1988)] suggest limiting a hyperbolic or superbolic decline curve to an exponential decline curve at a certain time or at a specific decline rate. Other authors suggest that decline curve analysis be avoided altogether during transient flow and instead recommend using modern decline analysis methods [Fetkovich (2) (1980), Palacio (1993), Agarwal (1998), Anderson (2005)] as they are applicable to both transient and BDF flow behaviour. However, these methods are complicated, dependent on a complete (pressure/rate) dataset and not always available to the practising engineer. Figure 1 shows the production history of a typical tight gas well in transient flow and outlines the common problems associated with tight gas decline analysis. The blue line is an exponential (b = 0) fit of the final portion of the production history. This extrapolation is likely conservative and underestimates recovery. Conversely, the red line is a superbolic best fit of the production history with a decline exponent of 2.0 and likely overestimates recovery from this well.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the CIPC/SPE Gas Technology Symposium 2008 Joint Conference, June 16–19, 2008

Paper Number: SPE-114998-MS

Abstract

Abstract This paper consists of two parts. The first part establishes the presence of turbulence in low pressure gas reservoirs even at relatively low rates. It is shown that it would be beneficial for these low pressure reservoirs to be tested using multiple rates to establish the level of turbulence. The second part describes a new type of flow test, which is a modified version of the traditional flow after flow test. The method of analysis of this proposed test requires the use of commonly available well testing software, and has been verified using synthetic data. Part 1 - Turbulence in Low Pressure Reservoirs Introduction Multi-rate well tests are seldom performed on low pressure reservoirs in Alberta. This is likely because these wells are expected to have relatively low rates of production. According to Alberta's Energy Resources Conservation Board (ERCB, 2006) , multi-rate tests are required to be performed whenever the anticipated AOF of the well is equal to or greater than 300 10 3 m 3 /d, or if turbulence is a factor. In this paper, it is demonstrated that turbulence can be a factor in low pressure reservoirs with high permeability. Accordingly, one of the aims of this paper is to establish the need for multi-rate testing in low pressure reservoirs. Turbulence in Low Pressure Reservoirs Actual multi-rate well test data from low pressure gas wells has been analyzed, resulting in n-values of less than one, which clearly indicates the presence of turbulence in these wells. A synthetic example is presented showing two reservoirs identical in every respect except for the pressure level; when these reservoirs flow at the same rates, the low pressure reservoir is shown to have a lower n-value (higher turbulence). It had been expected that turbulence would be more prevalent at lower pressure, because turbulence is directly related to velocity and, for a given rate, velocity increases with a lowering of pressure. However, although the effect of turbulence was more evident at low pressures, it was found that the reason for this was not the anticipated increase in velocity, but change in fluid properties with pressure.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Gas Technology Symposium, May 15–17, 2006

Paper Number: SPE-100563-MS

Abstract

Abstract Modern computing power has enabled very high accuracy and efficiency in complex calculations. Thus, it follows that reservoir engineering formulations need not be approximate solutions, as was sometimes historically the case. Being one of the most widely used techniques in reservoir engineering, the material balance equation (MBE) for gas is an excellent example of this. The MBE is used not only for estimating the original gas-in-place (OGIP), but also for calculating the decline in average reservoir pressure with depletion. In the majority of cases, the conventional p/Z formulation of the gas material balance is satisfactory. However, certain circumstances, which are sometimes unpredictable, demand formulations with greater accuracy. Although modifications to the standard approach have been presented, to the authors' knowledge, there is no published gas material balance formulation that is completely rigorous. This study presents a new, rigorous MBE for gas flow in the presence of a compressible formation and residual fluid saturation. Examples will be presented to highlight the capabilities of the new MBE. Introduction There has been a demand in the petroleum industry to plot the p/Z (or a similar plotting function) vs. cumulative gas production ( Gp ), as accurately as possible, so that the extrapolated line can point to the correct amount of OGIP. The primary value of this approach is to calculate the average reservoir pressures from the MBE. This has been one of the most powerful tools in reservoir engineering. Conventional MBE[1] for gas flow from a "volumetric" reservoir assumes the available pore volume to gas is constant by disregarding the effect of formation compressibility and the expansion of residual fluid during the productive life of the reservoir. Such assumptions may not be acceptable where the rock compressibility is of the same order of magnitude as residual fluid or gas. Ramagost and Farshad[2] modified the classical material balance equation and proposed a new plotting function as [( p/Z ) (1- ce ?p )] vs. Gp, based on an improved version of the conventional MBE. On a number of occasions with certain combinations of compressibility and saturation values, it has been observed that the Ramagost and Farshad MBE should have been more accurate in predicting the average reservoir pressure. We have examined how this MBE was derived. As will be shown later, the contributions of the shrinkage of the pore volume and of the expansion of residual fluid saturation were approximated in this approach. With the advent of computer power now-a-days, the accuracies of reservoir engineering calculations are warranted. The material balance equation (MBE) for gas flow has been used not only for estimating the OGIP, but also for estimating the average reservoir pressure. In addition, accuracies of MBE have to keep pace with the results from sophisticated reservoir simulations (both analytical and numerical). The following are the major applications of an MBE: To estimate average pressure for a given cumulative gas production. To estimate the cumulative gas production for a given average reservoir pressure. To estimate the OGIP from a given history of static pressure vs. cumulative production. To calculate pseudo-time[3] when using analytical solutions developed for liquids for modeling gas reservoirs. This study presents a new, rigorous MBE for gas flow in a compressible formation with residual fluid saturation. A new dimensionless parameter in the MBE will be identified and explained how this can predict the behavior the MBE. Examples will be presented to highlight the capabilities of the new MBE. The principal assumptions remain identical to those of Ramagost and Farshad[2] as compressibilities of rock and residual fluid are constant. Presentation of New MBE In the following sub-sections, we present the new, rigorous MBE, its implications and an explanation of the methodology of calculating the average reservoir pressure from it.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Gas Technology Symposium, May 15–17, 2006

Paper Number: SPE-100576-MS

Abstract

Abstract Advances in technology, strong energy prices and declining reserves in conventional gas reservoirs are encouraging oil and gas companies to consider the feasibility of exploiting large reserves trapped in tight (low permeability) gas reservoirs. Conventional well tests conducted on these low permeability gas formations, generally result in poor estimates of key reservoir parameters such as: initial reservoir pressure, permeability, effective fracture length, fracture conductivity, and deliverability potential. The objective of this paper is to review the different types of tests that are particularly applicable to tight gas formations, discuss why the traditional methods of testing and analysis rarely succeed, and identify appropriate test and analysis procedures for tight gas reservoirs. We will consider short-term tests where the primary objective is to obtain the initial reservoir pressure, with a secondary objective of determining permeability and skin. Perforation Inflow Tests, Fracture-Calibration Tests, and Formation Flow Tests will be considered. The applicability of these tests will be shown using synthetic and actual field cases. Introduction One of the primary goals of well testing is to obtain the initial reservoir pressure. For most reservoir engineering studies, this is a critical parameter to know accurately. Traditionally, the initial pressure is determined from a flow and buildup test, by extrapolating the shut-in data. Today, economics and environmental considerations encourage tests of short duration. Moreover, many of the reserves that are being exploited are contained within low permeability or tight gas reservoirs. The combination of these two factors can lead to tests that result in the wrong initial reservoir pressure, with drastic consequences for proper reservoir description such as defining reservoir continuity or calculating original-gas-in-place. This presentation is focused on initial well tests in "Tight Gas" reservoirs. Many segments of the industry define "Tight Gas" reservoirs as having permeability less than 0.1 mD. While this is a useful definition, it does not provide a clear distinction for well testing purposes, because what makes a test analyzable depends on many factors other than permeability; for example: Flow Capability is a function not only of permeability, but of k*h, the permeability-thickness product. Many tight gas wells are stimulated (hydraulically fractured) prior to testing. Therefore, a test can be influenced by: The size of the fracture The extent of frac cleanup (i.e. load fluid left to recover) The duration of the flow period. The duration of the build-up period. We will explore some of these effects and discuss ways of obtaining a reliable initial reservoir pressure. Industry Practice in Alberta, Canada For tight gas reservoirs, a common industry practice in Alberta is to hydraulically fracture the well, clean-up for 2 - 4 days, shut-in for 3 - 72 hours and then test. The test consists of flowing for 4 - 48 hours, and shut-in for 16+ hours. The examples below are typical tests, and illustrate the potential ambiguity of the results. Example 1: This reservoir has a permeability of 0.1 mD. Figures 1a, b, c, show that conventional analysis (Superposition, Derivative) and modeling work, and give consistent answers, in spite of a complex pre-flow sequence. This well was used to confirm that the reservoir pressure in that pool was 31,500 kPa. Note that the shut-in duration was 140 hours; however the same answers would have resulted even from a shorter shut-in of 24 hours because, as can be seen on the derivative, radial flow had been achieved within a few (5) hours. This well has been frac'd, but the derivative shows no evidence of linear flow. Note also, that there was a long shut-in after the frac clean-up, which means that, in effect, the flow period of the test started from near-static reservoir pressure. The final flow period was only 7.5 hours long.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Gas Technology Symposium, April 30–May 2, 2002

Paper Number: SPE-75703-MS

Abstract

Abstract The (semilog) derivative of pressure data from oil and gas wells is a widely accepted and highly useful tool for reservoir characterization. For buildup pressure data, this derivative is calculated with respect to equivalent time. It is generally assumed that since this derivative is obtained using equivalent time, it should be plotted on a coordinate axis that uses equivalent time. However, in the presence of boundaries, this style of plotting distorts the shape of the derivative during late-time, to the point where it bears very little resemblance to the original shape of the drawdown derivative. Moreover, the shape of the buildup derivative is strongly affected by the duration of the preceding drawdown. This paper investigates the shape of the equivalent-time-derivative when plotted against both equivalent time and real time (shut-in time) coordinates. Using computer generated models, it shows that a plot based on real time produces a buildup derivative response that is much closer in shape to the drawdown derivative, thus resulting in more accurate diagnosis of reservoir characteristics. This was true regardless of reservoir type, geometry or producing time. The advantages of using real time as a plotting coordinate are, a more readable diagnostic plot and a more easily recognized shape because of its similarity to the drawdown. Our research extends the work of Spivey (1999). This study investigated numerous reservoir types including homogeneous with boundaries, composite, fractured and dual porosity, and it also covered a wide practical range of producing times. Introduction A great deal of literature exists on the use of derivative typecurves for buildup tests. The general consensus in the literature is that a buildup pressure derivative, calculated with respect to equivalent time, should be plotted against equivalent time to give a shape that is similar to the drawdown derivative. This procedure works provided that the radial flow assumption is valid and producing time is sufficiently long. However, in cases where boundaries, heterogeneities, or fracture flow exist in conjunction with short production times, the opinions of some experts vary. Spivey et al (1999) suggest plotting the buildup pressure derivative calculated with respect to shut-in time against shut-in time for all reservoir cases 1 . Although this method allows the welltest analyst to develop a complete set of buildup type-curves that do not rely on the pre-assumption of radial flow, the resulting curves bear little resemblance to their drawdown counterpart for many reservoir configurations. More importantly, the shapes of these typecurves depend on producing time, thereby adding to the complexity of the diagnostic analysis. Onur and Satman (1998) suggest using the conventional plotting method (equivalent time derivative plotted against equivalent time) for all cases, except when producing time is short, in which case they propose to plot the equivalent time derivative against shut-in time 2 . Although this method provides buildup type curves that are similar in shape to drawdown type curves, it requires the analyst to decide what is a "short" producing time. Indeed, an experienced welltest analyst can usually identify the effects of a "too short" production time (or a significant rate change that occurs very close to shut-in) on a plot of equivalent time buildup derivative against equivalent time. Upon identification of these equivalent time effects, the analyst would then re-plot the equivalent time buildup derivative against real shut-in time. The method we propose eliminates the need for the analyst to be able to identify producing time effects from the diagnostic plot, but preserves a set of buildup typecurves that are very similar in shape to drawdown typecurves for a wide variety of reservoir configurations. The method is simple: always plot the equivalent time buildup derivative against shut-in time, regardless of the duration of the preceding drawdown period.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Gas Technology Symposium, June 28–30, 1993

Paper Number: SPE-26178-MS

Abstract

Abstract Those experienced in the natural gas industry know that tests conducted early in the life of a well, in a tight formation, tend to yield optimistic deliverability forecasts. It is not uncommon for producers to report to government agencies, or to purchasers, the results of such deliverability tests, and then to discover, after the well has been placed on production, that rates and pressures have declined continuously to as low as 10-20% of the initial test quantities. By understanding what controls this transient flow behavior, sometimes called "flush" production, and by collecting appropriate pressure data during the deliverability tests, we can make use of pressure transient analysis to accurately predict the "stabilized" gas rates that the well will eventually achieve. It is to the producers' advantage to make practical use of current deliverability testing regulations, and to apply the latest state of the art technology to Pressure Transient Analysis. From the pressure buildup data, and the informed use of ADVANCED well test analysis software, one can obtain completion and reservoir characteristics to accurately predict the well's long-term deliverability behavior. Unlike conventional reservoirs, production from tight formations must be forecast utilizing the "transient flow" equations rather than the "stabilized flow" equations. It is no longer necessary, nor is it acceptable, to use simplistic reservoir models. Realistic forecasts must take into account the reservoir characterization and model description derived from flow and buildup test analysis. The transient flow forecast in tight formations may control the economics of production, and must therefore be modelled rigorously. Introduction The majority of gas well testing regulations in North America require that the deliverability tests consist of several flow rates and durations with at least one of these being a STABILIZED point. The intent of the multi-point test is to define the reciprocal slope, n, of the back pressure plot and evaluate the extent of turbulence. The intent of the STABILIZED point is to locate the position of this "back-pressure" plot. The above procedures work well in high and medium permeability reservoirs. In low permeability, and particularly in tight gas formations, these tests are not only unnecessary but can lead to misleading results. The reason that they are unnecessary, is that, because of the relatively low flow rates, the turbulence term can be neglected. The reciprocal slope, n, value is 1.0. The reason that they can be misleading, is that it is impractical to flow the well until STABILIZATION is achieved, and so, in general, the operator will flow this well for an EXTENDED (but NOT STABILIZED) period usually 24-72 hours, and anchor the deliverability line (back pressure plot) through this 72-hour test point. P. 395^