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OPS OES Thailand provides G&G staff with vast experience in hydrocarbon volumetrics determination. Depending on the size of the reservoirs, they are able to execute either deterministic volumetric mapping, or, in case of smaller and more irregular reservoir distributions, they will produce stochastic reserves distribution defining the P10, P50, PSM and P90. This can be done with the Client’s in-house software or a common commercial software package.

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The project team will work together in the risking of the relevant geological elements of prospects. For this purpose, they will use an industry standard risking matrix, which is usually provided by the Client.


Deterministic Estimation of Hydrocarbon-in-place


Pre-Drill Estimate


Volumetrics is a static measurement based on a geologic model that uses geometry to describe the volume of hydrocarbons in the reservoir.


Volumetrics or volumetric estimation is the only way that is available to the geologist to assess the pre-drill hydrocarbons-in-place. The purpose of calculating a volumetric estimation is to evaluate a reservoir and calculate the potential reserves of the reservoir in question.  Pre-drill, the available seismic mapping and nearby wells are commonly being used in the estimation.


Post-Drill Update


Once one or more wells have been drilled, elementary factors such as net vertical pay, Vschale, porosity and water saturation can be obtained from the log evaluation and entered into the equation, together with the Gross Rock Volume from the available depth structure map. Available core data can be used for calibration purposes. Two methodologies can be followed. First, the development geologist can calculate the OIIP using the rock volume form the depth structure map. Conversion into BBLS of oil or BCF of gas at surface conditions uses the two most widely applied equations.




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Rock Volume (acre-feet) = A * h

A = Drainage Area, Units: Acres

h = Net Pay thickness, Units: Feet

∅ = Porosity which is the fraction of a rock volume that is void space that is available to store fluids.

Sw = Water Saturation which is the volume fraction of the porosity that is filled with interstitial water.

Boi = Oil formation volume factor, which is a factor for the change in the oil volume between the reservoir conditions and the standard conditions at the surface. Typically this is given with respect to a specific pressure. Units: pressure, bbl/STB

1/Boi = Shrinkage, which is the volume change that the oil undergoes when brought to the surface. This is due to solution gas that is escaping out of the oil.


Gross Reservoir Volume can be calculated by seismic software or by hand digitizing. The Net Reservoir Volume is obtained by the product of GRV and the net to gross ratio, whereby that part of the reservoir rock that does not meet the cutoff values for shale content or effective porosity is taken out.


Net pay is the portion of the reservoir from which hydrocarbons can be produced economically with respect to the determined production method. This is determined by applying cut-off values that are determined due to the interactions between porosity, permeability and water saturation, which are derived from well logs or offset well log information.


The oil or gas saturation is given by 1-Sw.


For Gas:

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Multiplication with the recovery factor gives the reserves estimate.



Rock Volume (acre-feet) = A * h

A = Drainage Area, Units: acres (1 acre = 43,560 sq.ft)

h = Net Pay thickness, Units: Feet

∅ = Porosity which is the fraction of a rock volume that is void space that is available to store fluids.

Sw = Water Saturation which is the volume fraction of the porosity that is filled with interstitial water.

The following 5 factors make up the Gas Expansion Factor.

Ts = Base Temperature at standard conditions which is °Rankine (460° + 60°F)

Ps = Base Pressure at standard conditions of 14.65 psia

Tf = Formation Temperature in °Rankine (460° + °F at the formation depth)

Pi = Initial Reservoir pressure, Units: psia

Zi = Compressibility at Pi and Ti


If a number of development wells are available to the geologist, He can calculate the hydro-carbon-pore feet of the reservoir in the well, which is equal to the net hydrocarbon thickness. These values can be contoured, and the digitized hydrocarbon-pore acre-feet maps give a net hydrocarbon volume, which can be easily converted into oil and gas volume at surface.



Stochastic Reserves Assessment on a “by platform“ basis


Deterministic hydrocarbon-in-place estimation can only be applied where sizeable reservoirs can be mapped with confidence. In places where reservoir distribution and correlation is uncertain due to small size, resource estimation must be done stochastically. Examples of these are Miocene and Pliocene/Pleistocene sands in the Pattani Trough in the Gulf of Thailand or offshore Myanmar in the Moattama Basin. Clients operating in such environments usually have their own in-house software or have purchased specific software. In general, the pre-drill estimations on a by-well basis are inaccurate, but a lot more reliable on a by-platform basis (12-16 wells). Evidently, results are better predictable in highly developed fields.



After Production Data is available


Once wells have been put on production, pressure and production data is collected giving a greater insight and accuracy of the recoverable reserves in the reservoir.  This requires a periodic, commonly annual, reserves assessment


Reserves Allocations


Where large hydrocarbon-bearing reservoirs cross block boundaries, unitization is required to allocate reserves to each different block, in particular where different partners with different working interests are present. This is a very delicate process, which generally requires the hiring of highly specialized consultants.


In the case of small reservoirs with uncertain distributions, where wells are crossing block boundaries, the actual pay count encountered by the well on each side of a block boundary, is the basis for the resource allocation. Where partners with different working interest percentages are resent, this also is taken into account in the so-called RAT, or Resource Allocation Table. These have successfully been used in the Gulf of Thailand, and are known to OPS OES geologists.



Pre-Drill Geological Risking


In frontier basins only about 10 to 15% of wells find hydrocarbons with less than 10% being commercial.


The five factors that determine if a well is a success or a dry hole must work in order to have a discovery; if a single element fails then we have a dry hole. The probabilities are estimated as a decimal where P =1.0 is certain and P =0 is not possible.


POS (Possibility of Success) = Source * Migration * Reservoir * Trap * Seal



This is illustrated in the figure below (see also in Geological Services).


In general, most Clients have their own in-house so-called risking matrix; alternatively, they can purchase and use a commercial package. Another option is that they outsource this process to consulting experts. If technical E&P teams work together on a specific project, it is rule that they do the risking themselves in a team effort. All individual POSes will then be added and averaged to one single well or prospect POS. The geologists we provide are familiar with this concept.

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