Flowing Material Balance; Simplicity & Power

Dynamic or Flowing Material Balance (FMB), as a branch of the production data analysis (PDA), basically means the use of production date (flow rates & flowing pressure) to perform some analyses or diagnostics aiming to have information about the reservoir characteristics, reserve volume, hydrocarbons initially in-place, etc.

PDA has been developing through time starting from the explicit concept of:

• PA (Production Analysis),
• PTA (Pressure Transient Analysis),
• RTA (Rate Transient Analysis), and
• FMB (Flowing Material Balance).

The introduction of FMB mainly converted the constant bottom-hole flowing pressure (BHFP) production scenario into constant flowing rate production conditions. Determination of hydrocarbons initially in-place (HIIP) and reserve is a fundamental process for Reservoir Engineering and the Subsurface Team. The reservoir estimation techniques can be classified into two basic groups volumetric (initial) calculation which is commonly applied in the early stages of oilfield development. Then, when sufficient production data is available, the second group (Performance-Based estimates) can be applied. Where the traditional or static material balance  (MB) method uses actual reservoir performance data, therefore it’s generally accepted as the most accurate procedure for estimating HIIP due to the involved assumptions that the MB can only VIEW the reservoir connected volume.

To generate a traditional MB analysis, the wells are needed to be shut-in regularly several times throughout their production life to obtain accurate estimation for the average reservoir pressure. However, this is usually impractical in the actual oilfield operations due to production losses, and the duration of the shut-in is often not long enough to obtain pressure equilibrium or stabilized pressure measurements specially in tight reservoirs. Which considered the main limitations or pitfalls in performing traditional MB analysis. FMB, on the other hand, uses the concept of boundary-dominated flow (BDF) or pseudo-steady state (PSS) flow, to handle this scenario. The reservoir pressure distribution will typically follow the transient flow period then the stabilized conditions or BDF period which means the reservoir boundaries have been reached. That actually the interest of reservoir volume determination and reserve calculations. In BDF condition, the reservoir pressure will decline throughout the entire reservoir at the same rate (Figure-1). Therefore, the pressure drop recorded at the well at certain time will represent the pressure drop in the reservoir at the same time.

The procedure of FMB is simply involving conversion of well flowing pressure to the equivalent average reservoir pressure which facilities the application of MB while the wells are producing (no shut-ins are required). FMB analysis plots a normalized-rate versus normalized cumulative production, on a linear scale to get STOIIP (N), where no type-curves are plotted. FMB methodology utilizes the concepts of material balance time (MBT; te) to convert variable rate/variable pressure production scenarios into equivalent constant rate production scenario. MBT, by definition, is the time needed to produce this cumulative production amount with the instantaneous flow rate value (Figure-2). In gas reservoir, where the gas properties are highly dependent on pressure, MBT will be defined as material balance pseudo-time.

MBT;

From definition isothermal compressibility of oil,

Where the initial volume is N (STOIIP), and net change in volume will be the cumulative production (Np). Incorporating this definition with PSS flow equation, we will get;

 In the previous equation, two different pressure losses; pressure loss due to depletion (pi-pr) and pressure loss due to inflow (pr-pwf). For simplicity, the second term will be replaced by PSS constant (bpss) and substitution for MBT;

 Therefore, by plotting rate-normalized pressure (dp/q) vs. MBT (te); the resultant straight line will has an intercept of bpss (Figure-3). Then, the average reservoir pressure will be estimated as;

For determination of STOIIP (N), the equation will be re-arranged as;

Applying the previous equation as shown in Figure-4, X-axis intercept will be the value of N.

Fig-1: Typical reservoir pressure distribution

  Fig-2: Concept of material balance time (MBT)

 Fig-3: Estimation of bpss from BDF period

 Fig-4: Estimation of N by FMB procedure

 Field application of an oil well with production data for about 10 days (reservoir limit test) is shown in Figure-5.

Fig-5: Production data for oil well; flowing pressure and flow rate

Therefore, by applying the previous procedure of FMB on that well, the results showed very high agreement between the estimated STOIIP by FMB for ONLY 10 days with results of traditional MB for about 2 years of production!

 Finally, application of FMB is following a very simple procedure with a reliable results;

• No shut-in is required for wells; only production data is needed.
• Accurate estimate for STOIIP is achieved with very short production periods.
• STOIIP estimation from FMB is considered one the powerful performance-based techniques, where the connected volume is only considered.
• Early and accurate determination of well’s productivity index (PI) is easily determinated from the reciprocal of PSS constant (bpss)

Thanks,