Lab report on flowing material balance in unconventional reservoir

Abstract

The material balance is an essential tool used by reservoir engineers in the oil and gas industry. It can provide an estimate of initial hydrocarbon in place independent of geological interpretation and serve the purpose of verifying volumetric estimates. The critical requirement is to accurately estimate the average reservoir pressure at the required time intervals. The standard practice assesses the moderate reservoir pressure from a pressure buildup test conducted on individual wells in a reservoir. Pressure buildup tests require shutting off production for some time, and it is not conducted on a regular interval due to the demand-supply situation prevailing in the country. Material Balance Method has been modified by different researchers to bypass the strict requirement of the average reservoir pressure as an input parameter. Instead, these techniques use static bottom hole pressure (SBHP) estimated from shut-in wellhead pressure, shut-in wellhead pressure (SWHP), flowing bottom hole pressure (FBHP) of the well and flowing wellhead pressure (FWHP). Current study has been conducted for a certain gas well producing from the Lower Bokabil Sand in Surma Basin. Due to the unavailability of required reservoir pressure data, this paper presents the results from applying the alternate methods mentioned above. Data for SBHP and SWHP methods were recorded during occasional shut-ins due to some production problems or any other reasons.

Gas initially in place (GIIP) values estimated by using the static bottom hole pressure, shut-in wellhead pressure, flowing bottom hole pressure and flowing wellhead pressure approaches are 27 BCF, 28 BCF, 24 BCF and 21 BCF respectively. The conventional material balance estimated 26.95BCF with very limited reservoir pressure data.

Introduction

The determination of gas reserves is a fundamental calculation in reservoir engineering. Material balance is an important and generally accepted method for estimating original hydrocarbon in place and the evaluation of the reservoir driving mechanisms. This information is vital for the development of a production strategy, design of facilities, contracts and valuation of the reserves. Volumetrically determined reserves can be very imprecise, because the method depends upon detailed knowledge of many reservoir characteristics that are often unknown such as the areal extent of the pool. The material balance method uses actual reservoir performance data and therefore gives an idea of the hydrocarbon in place that will actually flow, thus a more reliable estimate of recoverable reserves can be made. Once determined, the original gas-in-place can be used to reliably forecast the recoverable raw gas reserves under various operating scenarios¹.

The important requirement is to accurately estimate the average reservoir pressure at different time intervals. The correct method to estimate the average reservoir pressure is to conduct pressure buildup test on individual wells in a reservoir. Pressure buildup test require shutting off production for some time. Oil and gas companies are often reluctant to conduct pressure build up test on a regular basis because of the lost production. It is even more so in Bangladesh where the supply-demand scenarios are often quite restrictive. Material Balance Method has been modified by different researchers to bypass the strict requirement of the average reservoir pressure as an input parameter. Instead, these techniques use static bottom hole pressure (SBHP) estimated from shut-in wellhead pressure, shut-in wellhead pressure (SWHP), flowing bottom hole pressure (FBHP) of the well and flowing wellhead pressure (FWHP).

In this paper effort has been made to study a certain gas well producing from the Lower Bokabil Sand in Surma Basin applying conventional material balance analysis as well as the other approaches mentioned above to estimate the initial gas in place and recoverable reserves.

Figure 1: Stratigraphy of Surma Basin

Gas Material Balance Equation in Unconventional reservoir

Material balance has long been used in reservoir engineering practice as a simple yet powerful tool to determine the Original-Gas-In-Place (G). The conventional format of the gas material balance equation is the simple straight line plot of p/Z versus cumulative gas production (Gp) which can be extrapolated to zero p/Z to obtain G. The method was developed for a volumetric gas reservoir. It assumes a constant pore volume of gas and accounts for the energy of gas expansion, but it ignores other sources of energy such as the effects of formation compressibility, residual fluids expansion and aquifer support.

Gas material balance is a simplified version of the general material balance equation. When the general equation is reduced to its simplest form containing only gas terms, it appears as shown below:

In this equation, it is assumed that gas expansion is the only driving force causing production. This form is commonly used because the expansion of gas often dominates over the expansion of oil, water, and rock. B_g is the ratio of gas volume at reservoir conditions to gas volume at standard conditions. This is expanded using the real gas law.

The reservoir temperature is considered to remain constant. The compressibility factor (Z) for standard conditions is assumed to be 1. The number of moles of gas do not change from reservoir to surface. Standard temperature and pressure are known constants. When Bg is replaced and the constants are canceled out, the gas material balance equation then simplifies to:

The attempt to find a material balance equation for unconventional gas reservoirs started when these resources became more popular. Jensen and Smith proposed a simplified material balance equation for unconventional gas reservoirs by assuming that the stored free gas is negligible and consequently omitted the effect of water saturation completely.

However, the King derived a comprehensive material balance equation for unconventional gas reservoir that accounts for the free and adsorbed gas water encroachment and water formation compressibility.

Moghadam et. al., (2009) in their research presented an overview on new format of the gas material balance equation which recaptures the simplicity of the straight line while accounting for all the drive mechanisms. It uses a p/Z** instead of p/Z. The effect of each of the mentioned drive mechanisms appears as an effective compressibility term in the new gas material balance equation. Also, the physical meaning of the effective compressibility’s are explained and compared with the concept of drive indices. Furthermore, the gas material balance is used to derive a generalized rigorous total compressibility in the presence of all the above-mentioned drive mechanisms, which is very important in calculating the pseudo-time used in rate transient analysis of production data. The advanced material balance equation for unconventional reservoirs is shown below along with the total Z** equation.

Han et. al., (2019) also discussed flowing material balance method for unconventional gas reservoirs based on the adsorbed phase volumes. As in the case of the unconventional gas reservoirs, such as coal bed methane reservoirs and shale gas reservoirs, the conventional method is inapplicable due to the gas adsorption on the organic pore surface. The authors simulated pseudo-gas reservoir and compared results with existing formulas. From comparison it is inferred that the proposed formulation can accurately get the geological reserves of adsorbed gas unconventional reservoirs.

Oil Material Balance Equation in Unconventional reservoir

As seen in the general material balance equation, there are many unknowns, and as a result, finding an exact or unique solution can be difficult. However, using other techniques to help determine some variables (for example, m or original gas-in-place from volumetrics or seismic), the equation can be simplified to yield a more useful answer. Various plots are available to conduct an oil material balance rather than calculating an answer from individual measurements of reservoir pressure.

The basis for the flowing material balance of oil comes from both the definition of compressibility and the steady state inflow equation. Similar to the interpretation of gas material balance, oil material balance uses plotting techniques. However, unlike the equation for single-phase gas expansion, the standard form of the material balance equation for oil reservoirs does not easily yield a linear relationship. The equation can be organized to show linear behavior. Based on the rearrangement below, the large combinations of terms are used as x and y, while G is the slope, and N is the intercept. This of course implies that water influx term for each data point is a known value, or the simpler scenario that there is no water influx.

Thus the change in pressure is the difference between the initial reservoir pressure and the average reservoir pressure, and the change in volume is the produced volume up to that point in time. Knowing that the initial volume is the total oil-in-place, these terms are applied to the compressibility equation.

Combining the relationships with the pseudo-steady equation, the flowing material balance equation is as follows:

When the flow becomes dominated by the boundaries, i.e. stabilized or “pseudo ­steady state” conditions are achieved, the pressure at every point in the reservoir declines at the same rate. Which shows that the pressure drop measured at the wellbore is the same as the pressure drop that would be observed anywhere in the reservoir, including the location which represents average reservoir pressure. The advantage of the pseudo-steady state formulation is that the average reservoir pressure is eliminated during the addition of pressure loss due to depletion and pressure loss due to inflow, and thus is not explicit in the equation. This is an obvious advantage, because the average reservoir pressure is an unknown. Since both terms (pressure loss due to depletion and pressure loss due to inflow) are functions of rate, we can simplify the pseudo-steady state equation as follows:

where:

So, it is inferred from discussion that it is possible to obtain the average reservoir pressure without shutting in a well. The flowing pressure can be converted to the average reservoir pressure existing at the time of the measurement using a very simple and direct procedure. The average reservoir pressure obtained from the Dynamic Material Balance method can be used anywhere it is traditionally used. There is need to do more simple method for flowing material balance in unconventional reservoir. The information obtained from material balance equations is vital for the development of a production strategy, design of facilities, contracts and valuation of the reserves. It is also noticed volumetrically determined reserves can be very imprecise, because the method depends upon detailed knowledge of many reservoir characteristics that are often unknown such as the areal extent of the pool. The material balance method uses actual reservoir performance data and therefore gives an idea of the hydrocarbon in place that will actually flow; thus, a more reliable estimate of recoverable reserves can be made. So, material balance is an important and generally accepted method for estimating original hydrocarbon in place and the evaluation of the reservoir driving mechanisms

Production from Lower Bokabil Sand

Current study conducted on only producing horizon of Lower Bokabil sand of a gas field under Surma Basin. After first work over, the well was producing from April 2005. The geology of Surma Basin² is given in the Figure -1. But in July 2008, production was suspended from the well z due to obstruction accumulation inside the tubing. The field again came in online after second work over in February 2010. Current analysis is conducted taking into consideration of production data^{2, 3& 5} with more or less uninterrupted production from April 2005 to June 2010 (Figure 2).

Figure 2: Production History²

MATERIAL BALANCE REVISIT

Traditional Material Balance

For a gas reservoir conventional material balance analysis relies on obtaining a straight line on P/z vs. cumulative production (G_p) plotted on Cartesian coordinate to estimate reserves and initial gas in place (GIIP). The accuracy is dependent upon the accuracy of the well’s production and pressure data. Unlike the volumetric method, the material balance accounts for reservoir heterogeneity and continuity variations, which occur within the reservoir. This method, however, can be applied only after a certain amount of depletion of the reservoir, and when there is a noticeable trend in the pressure decline. Therefore it cannot be applied in newly discovered fields.

The general form of material balance equation was first presented by Schilthius in 1941⁵. The detailed derivation is not presented in this paper. The final form for a gas reservoir with closed boundaries, takes the form of equation (1).

P/z = -pi/ (zi G) G_p + p/z         (1)

Where, G_p is cumulative production, pi is initial reservoir pressure and z is the gas deviation factor. Since pi, zi, and G are constants for a given reservoir, plotting p/ z vs. G_p would yield a straight line. If p/z is set equal to zero, which would represent the production of all the gas from a reservoir, than the corresponding G_p is equal to G, the initial gas in place. Deviations from this straight line indicate external recharge or offset drainage. In water drive reservoirs, the relation between G_p and p/z is not linear, because of the water influx, the pressure drops less rapidly than under volumetric control.

Material balance study of Lower Bokabil sand was conducted using MBAL^TM software. Because of unavailability, limited down hole data was used in this study. This study yielded a GIIP of 26.996 BCF (Figure 3). Using Hurst-Van-Everdingen-Modified aquifer model⁵, current study observed (Figure 4) that there is no aquifer support in the lower Bokabil sand.

Figure 3: P/z vs. Cumulative Production Plots

Figure 4: Model with Aquifer Influx

Alternative Methods of Material Balance

Four different approaches were taken to study the subject field. These were: (a) static bottom hole pressure (SBHP) estimated from shut-in wellhead pressure (b) shut-in wellhead pressure (SWHP) (c) flowing bottom hole pressure (FBHP) of the well (d) flowing wellhead pressure (FWHP). Data for approach (a) and (b) were recorded during occasional shut-ins due to some production problems or any other reasons.

Static Bottom hole Pressure Estimated from Shut-in Wellhead Pressure

Different wells of the field were shut-in from time to time because of production problems or any other reason and pressure build up data were recorded in these situations. The recorded shut-in wellhead pressure data was taken from monthly records of current Gas Field and corresponding bottom hole shut in pressure were calculated. The calculated static bottom hole pressure is, however, is not the same as the average reservoir pressure, which is used in the conventional material balance. Average reservoir pressure can only be obtained from a properly designed well test program.

Shut-in Wellhead Pressure

In this approach field recorded shut-in wellhead pressure are used to make a p/z vs. cumulative production plot, where p is now the shut in wellhead pressure instead of the average reservoir pressure. The z factor is also evaluated at this pressure. The approach is based on the assumption that there is no liquid in the wellbore. For the material balance study, P/ z term has been calculated by the means of calculating the z-factor using Hall and Yarborough⁵ correlation. Since static gas gradient is very small, the plots set out for p/z using the shut-in wellhead pressure vs. cumulative production for Lower Bokabil sands of current Gas Field, should provide quite similar results. This method will yield erroneous results if there is a liquid build up in the tubing.

Flowing Bottom hole Pressure of the Well

Theoretically it has been understood for many years that original gas in place can be estimated using measured gas volumes and flowing pressures. This method is based on the pseudo steady state pressure behavior, which requires that the rate of change of pressure at every location of the reservoir is constant. It can also be assumed that after the attainment of the pseudo steady state the rate of change of the average reservoir pressure is also constant as production continues. Mattar and McNeil (1998) illustrated that original gas in place can be determined from the flowing data (pressure and production). These authors have opined that it is possible to determine original gas in place with reasonable certainty when shut-in pressures are not available. This procedure requires the flowing sand face pressure at the wellbore to be measured for plotting p_wf/z vs. cumulative production. A straight line drawn through the flowing sand face pressure data and then a parallel line from the initial reservoir pressure gives the original gas in place. The method of calculating the reserves of medium and high permeability reservoirs, from flowing pressure data have the potential of preventing loss of valuable production, without having to shut-in the well. The method is especially suitable for current gas field as well as for other gas fields of Bangladesh where routine pressure testing cannot be conducted due to critical demand-supply situation.

The flowing bottom hole pressure is calculated from the monthly representative flowing wellhead pressure and the monthly average gas flow rate of different wells, using the PROSPER software.

Flowing Wellhead Pressure

In this approach daily average flowing wellhead pressure data are used. The z-factor for the  p/z term is calculated using the same methodology as in the shut-in wellhead pressure. The flowing wellhead pressure data was taken from daily records of current well. Mattar and McNeil¹ demonstrated in the “flowing” material balance method that the wellhead pressure also has a similar trend of decline as the sand-face pressure. This is true when single phase gas flows through the well and there is no liquid build up in the tubing. While studying the plots for p/z of FWHP vs. cumulative production, it has been observed that the apparent gas in place figure of the producing sand of Current Gas Field are lower than that of obtained from static bottom hole pressure and shut-in  wellhead pressure methods. This makes sense because flowing wellhead pressure decreases from the shut-in wellhead pressure because of frictional losses. The straight line drawn from the initial wellhead pressure in parallel to the flowing wellhead pressure data gives the original gas in place.

The p/z vs. cumulative production graphs of well for static bottom-hole pressure, shut-in wellhead pressure, flowing wellhead pressure and flowing bottom hole pressure appears in Figure 5, Figure 6, Figure 7 and Figure 8 respectively.

Gas in place values estimated from the plots of p/z vs. cumulative production using the static bottom hole pressure, shut-in wellhead pressure, flowing bottom hole pressure and flowing wellhead pressure approaches are 27 BCF, 28 BCF, 24 BCF and 21 BCF respectively.

As of July 2008, the cumulative production from well was 7.087 BCF. Assuming the gas in place value for the well as 24 BCF (using flowing bottom hole pressure approach), reserve at the abandonment p/z of 1000 psia is 16 BCF. Remaining reserve for this location is 8.0 BCF. The recovery factor of this sand till July 2008 is 66.67%.

Figure 5: P/z SIBHP vs. Cumulative Production

Figure 6: P/z SIWHP vs. Cumulative Production

Figure 7: P/z FWHP vs. Cumulative Production

Figure 8: P/z FBHP vs. Cumulative Production

Summary and Conclusion

Several methods are presented for estimating the original gas-in-place. The calculated values for this particular case are summarized in Table 1:

Table1: Summary of Material Balance Result

The cumulative production from the well is 7.087 BCF. Assuming the GIIP using FBHP approach as 24 BCF, reserve at the abandonment p/z of 1000 psia is 16 BCF. Remaining reserve for this sand is 8.913 BCF. The recovery factor is 66.67%.

The results obtained from different methods are not very different. However, the FBHP method can be considered most reliable, because in this method maximum data were available, and it considers Pseudo-steady flow regime prevailing in the reservoir. On the other hand, conventional material balance had the least amount of data points, therefore results are less reliable. Other two static pressure methods, although may have more data, do not conform to the requirement of the average reservoir pressure. These could be close approximations in case no other alternatives are available.

Recommendation

The procedure presented in this paper provides a very practical tool for estimating gas-in-place using data generally available in normal production operations. In addition, production losses can be minimized by not having to shut-in wells. It is possible to determine original gas-in-place with reasonable certainty when shut-in pressures are not available.

Uncertainties involved in reservoir pressure and draw down will be reduced by conducting periodic bottom hole pressure survey and that will help to accurately model the reservoir and analysis. Alternative methods of material can be applied with reasonable certainty where periodic bottom hole pressure survey normally is not conducted.

References

Mattar, L. and McNeil, R., “The ‘Flowing’ Gas Material Balance Procedure’’, Journal of Canadian Petroleum Technology, September 1997.

Bangladesh Gas Reserve Estimation (2003), Hydrocarbon Unit, Petrobangla.

Imam, B (2005), “Energy Resources of Bangladesh” University Grants Commission of Bangladesh

MIS Report 2010, Petrobangla

Dake,L.P.(1978),“Fundamental         Reservoir Engineering”, Developments in Petroleum Science,8 Elsevier Science Publishers B.V.,The Hague,Netharlands