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PETROLEUM RESERVOIR SIMULATION

Lecture 2 - Drive mechanisms and reservesDr RICHARD WHEATONENG69229/09/2014211Hydrocarbons in Place22Hydrocarbons in place

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Hydrocarbon pore volumeHydrocarbon pore volume is determined from the geological and petrophysical input. Where we have limited data in early field life we will take single values for reservoir area and average values for net thickness, porosity and water saturation so that:V= 7758 A hv (1 Sw)

WhereV = HPV - RBA = area (average) -acreshv = net thickness = h . NTG - ft = porositySw= water saturationNTG = net to gross7758 is the conversion factor bbl/acre-ft

24Oil in PlaceUsing the above equation for hydrocarbon pore volume, Stock Tank Oil in place is given in field units by:N = 7758 A hv (1 Sw)/Boi

WhereN = Stock Tank Oil Initially In Place (STOIIP) -stb (stock tank barrels)A= area in acreshv = net thickness = h . NTG in feetBoi the initial oil formation volume factor in Rb/stb 7758 is the conversion factor bbl/acre-ft

25Gas in placeFor gas in place:G = 7758 A hv (1 Sw)/Bgi WhereG = Gas in Place (GIP) in scf A =area in acreshv = net thickness = h . NTG in feetBgi = the gas formation volume factor in Rb/Scf 7758 is the conversion factor bbl/acre-ft

Now standard conditions are pb = 14.7 psi and Zb = 1, T is in o Rankin (=60oF+460) so that

Bgi = 0.0283 T Z/p (res bbl/scf)

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Gas deviation factor27

ReservesReserves are simply the oil or gas in place times the recovery factor (RF) so that for an oil reservoir:R = 7758 A hv (1 Sw)/Boi .RF stb And for a gas reservoirR = 7758 A hv (1 Sw)/Bgi . RF scf

28Gas Fields29Drive mechanisms & Recovery Factors for various field types

Dry and Wet Gas reservoirs

Gas is highly compressible so that the drive mechanism here is gas expansion. The total recoverable reserves will depend on the initial pressure, reservoir properties, the final abandonment pressure and the PVT properties. Gas reservoirs have high recovery factors typically between 65 -95%

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Dry gas, wet gas and gas condensatesIn field unitsDry gas

Wet gas Ql = Qg /lgr (lgr = liquid/gas ratio)

Gas condensateQc = Qg/cgr (cgr = condensate/gas ratio = 1/ gas condensate GOR)211

Gas field developments212

12Gas well decline examples dry gas213

Factors in decline: permeability, formation thickness, viscosity, initial pressure, volume in place, bottom hole pressure

We are making considerable simplifications here and ignoring water ingressSpreadsheet : gas decline-svGas well decline - Wet gas214

Liquid production rate will follow gas rate since there is no liquid dropout in the reservoirFactors: as for dry gas + GOR inputGas well decline gas condensateThis is more difficult to model without a full numerical simulation, however an approximation is possible if we have a dew point and a GOR above the dew point and assume some linear gradient in GOR with decreasing reservoir pressure215

Gas condensate field developmentStraight depletion of gas condensate fields would not normally be considered a reasonable development option. Gas recycling would be a normal development. Here we attempt to keep the reservoir above the dew point pressure for as long as possible by re-injecting some or all of the dry gas following the separation process in the surface facilities Recovery factors are difficult to predict for gas condensate fields but liquid recovery of > 40% can be achieved and final blowdown may result in gas recovery of 70-80%.Because liquids are the more valuable product this liquid recovery is normally the most important figure.

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Problems with gas fields water advanceAn important factor in determining the recovery factor in gas fields is the possible 'watering out' of wells. This will depend on the presence of layered high permeability layers that result in what are called 'stringers' of water advancing ahead of the main aquifer advance as pressure decreases

A similar problem is water 'coning' where local pressure gradient around a producing well sucks up water from the aquifer. For this reason wells are normally completed well above the gas water contact.

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Oil Fields218Oil fields drive mechanisms and reservesMaterial balance enables us to predict oil field reserves as a function of pressure.

However, production as a function of time is much more difficult to model by analytical methods. Numerical simulation is necessary even early on except for waterflooding of under-saturated reservoirs where methods discussed in a later lecture are valuable.This is mainly because of factors such as aquifer pressure support or gas cap pressure support for saturated reservoirs which cannot easily be included in analytical methods.219Under-saturated Oil Fields

Liquid expansion driveExpansion of original oil between initial pressure(pi) and p(bubble point) will provide a drive for production. Since the compressibility of liquids is small, recovery from oil expansion is normally very small (< 5%) and only if initial reservoir pressure is very much higher than bubble point pressure will significant recovery due to this drive be possible.Solution Gas driveThere are two components hereExpansion of original oil between pi and p Expansion of liberated gas, normally the major effectRecovery Factors from Solution Gas Drive may typically be around 25 - 35 %. 220

Under-saturated Oil Fields

It is important what happens to the released gas.

Gas evolved around the well as pressure drops can:Remain immobile close to wellMigrate into well and be producedTravel upwards to form or add to and existing gas capMigration into the well will reduce recovery (losing some of the gas expansion drive) and also disposal of unwanted gas can be a serious problem

We have a relationship of cumulative oil production to pressure, therefore to relate oil rate to time we have to have a relationship of pressure to time

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Water-flooding

Waterflooding is a major development method for oil reservoirs. Water is injected from some wells to maintain reservoir pressure as oil is produced from others. The aim is to position injection and production wells such that we 'sweep' the oil towards the producing wells. Recovery factors can be as high as 60% but will depend on sweep efficiency both, areal and 'locally' with respect to rock/fluid propertiesET = ER/F * EA where ET is total sweep efficiency

EA = areal efficiency depends on the extent of the contact of the advancing water front with the formation. It will depend on the level and type of heterogeneity in the reservoir. For example high permeability layers connected between injectors and producers will reduce EA as water preferentially flows through these layers and has a poorer sweep of the lower permeability areas.ER/F = rock/fluid dependent sweep efficiency. This will depend on wettabilities, relative permeabilities (particularly residual oil saturation) and fluid viscosities. It assumes a locally homogeneous type behaviour. Understanding of areal sweep efficiency only comes with detailed appraisal, analysis of production data and detailed numerical modelling.222Water-floodingVarious well layout patterns are used to maximise recovery, some examples are shown below:

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Water-floodingWater is normally injected at a rate that will maintain reservoir pressureWe therefore have a constant oil rate plateau until water breaks through to the production wells

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Saturated Oil FieldsThese are oil reservoirs with a gas cap. Issues are basically the same as for under-saturated oil fields but now we have an additional drive mechanism in the expansion of the gas cap potentially driving oil towards producing wells. There is however the possibility of gas coning down to the wells.

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Summary of Recovery factors226

Plateau production227

Enhanced oil recoveryGeneralRecovery factors in oil reservoirs can be between 20 - 60% , the higher figure normally depending on waterflooding (known as secondary recovery). Thus 40 - 80% of the oil in place can be left behind mainly due to high oil viscosities (heavier oils), high residual oil saturation (a function of oil-water-solid interfacial forces) and poor areal sweep efficiency. A number of enhanced recovery methods, known as tertiary recovery methods, can help to overcome these problems.Gas injectionInjected gas can be produced gas, either processed or unprocessed or gases such as CO2 or nitrogen or mixtures on produced gas and CO2.Gas injection or Water Alternating Gas (WAG) injection is the most widely used EOR method. Like water injection, gas injection keeps reservoir pressure higher, which will on its own increase deliverability. Sweep efficiency can be improved particularly in high relief reservoirs where gravity drainage can be significant (ie. with gas injected higher in the reservoir the gravity effect (oil heavier than gas) can help drive oil to lower production wells. WAG can give more control on sweep of oil towards producers. Swelling of the oil and vaporisation of oil components can both help recoveryGas injection is classified as either miscible or immiscible gas injection. Miscible gas injection (where the gas mixes or partially mixes with the oil) can reduve oil viscosity, reduce oil/gas interfacial tension and change wetting properties such that residual oil saturation is reduced.

228Enhanced Oil recoveryMiscible Solvents - surfactantsInjection of surfactants can reduce oil/water interfacial tension and thus reduce residual oil saturation and hence increase oil recovery.Thermal MethodsThere are two thermal enhance oil recovery methods, steam flooding and fire flooding.Steam flooding heats the oil, reducing its viscosity and vaporizing part of the oil and thus decreasing the mobility ratio.Fire flooding involves the injection of air with subsequent ignition and combustion. As the fire burns the fire front moves towards the production wells, heating the oil and reducing its viscosity.EconomicsAll of the above methods add to the costs of producing the oil and oil prices and the cost of injctants such as surfactants or CO2 will need to be taken into account when looking at the feasibility of any EOR project. Numerical simulators are available which cover all of the above methods.

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