Utilisation of Reservoir Pressure

In the development of a hydrocarbon reservoir, the energy stored up within the compressed state of the reservoir fluids has in the case of natural flow, to provide the total pressure loss in the producing system. Based upon a fixed operating pressure for the separator, we can formulate the pressure loss distribution as follows:-

P_RES = ∆P_RES + ∆P_BHC + ∆P_VL+ ∆P_SURF + ∆P_CHOKE + P_SEP (7) where

P_RES is the initial or average pressure within that wellbore drainage area of the reservoir. (refer to Ch 3)

∆P_RES is the pressure loss caused by the flow of fluid within the reservoir to the wellbore.

∆P_BHC is the total pressure loss generated by the design of the fluid entry into the wellbore, ie, the bottom hole completion configuration.

∆P_VL is the vertical lift pressure loss caused by fluid flowing up the production tubing string.

where

Figure 13

The flow system from wellbore to separator

2

2

Reservoir Production Concepts

∆P_VL = ∆P_FRICT + ∆P_HHD + ∆_KE (8)

∆P_FRICT is the frictional pressure drop ∆P_HHD is the hydrostatic head pressure drop ∆P_KE is the kinetic energy pressure drop

∆P_SURF is the pressure loss generated in exiting the Xmas tree and surface flowlines.

∆P_CHOKE is the pressure loss across the choke.

P_SEP is the required operating pressure for the separator. Rearranging equation 7 to give

(P_RES - P_SEP) = Available pressure drop for the system=∆P_TOT

= ∆P_RES + ∆P_BHC + ∆P_VL + ∆P_SURF + ∆P_CHOKE (9) All the pressure drop terms in equation 9 are rate dependent, hence

Total system pressure drop

∆P_TOT = [∆P_RES + ∆P_BHC + ∆P_VL + ∆P_SURF + ∆P_CHOKE]_Q (10) Thus, each of the pressure drops can be minimised either individually or collectively to produce a maximum attainable production rate for the available pressure drop. This is known as production system optimisation.

It is essential to consider how each of these pressure drops can be minimised to provide a maximum potential production rate.

(i) To reduce the pressure loss due to flow in the reservoir, it is necessary to reduce the resistance to flow. This can be accomplished either by reducing the formation rock resistance, eg, increasing the permeability by acidisation or fracturing or by reducing the resistance to flow due to the fluid properties, eg, viscosity by utilising thermal recovery techniques. These alternatives may be costly, are not always applicable to all reservoirs and may involve considerable technical risk or uncertainty to be readily applied except in specific situations, eg, chalk reservoirs or very heavy crude oil reserves. (ii) The pressure loss due to the bottom hole completion method has to be specified

as part of the completion design and, as such, is a major area for production optimisation. It is likely that detailed consideration to some aspects in this area such as perforation shot density and length of perforated interval could be very beneficial in maximising the production capacity of the system.

1

(iii) Again, as with the bottom hole completion pressure loss, the vertical lift pressure loss is a major area for optimisation as not only does the engineer have to specify the length and diameter of all sections of the tubing string but also all the specific completion components such as nipples. Careful design in this area can provide significant optimisation of the productive capacity of the well. (iv) For most situations the surface flowline pressure loss is relatively less important in that, although the in situ phase velocities will be higher than in the production tubing, it is considerably shorter in length. Exceptions include some subsea wells and onshore wells drilled on a wide spacing. However, minimising pressure loss here, by selecting an increased diameter pipeline and restricting the severity and number of directional changes can yield significant improvement in field productivity in some situations. (v) Little flexibility exists to minimise choke size as it is required to give a specific

pressure drop for a known flowrate to provide stability to the separator.

2.2. Supplementing Reservoir Energy

In section 2.1.2, the effective utilisation of reservoir energy was discussed with respect to production system optimisation. From equations (7) and (10), the production rate from a well is directly proportional to the average pressure in the reservoir pore volume drained by a well. To maintain rates and hence cash flow, it would be desirable to maintain reservoir pressure. From the earlier discussions on material balance, it can be seen that for this to occur either the reservoir would have to display no pressure depletion due to either:-

(i) Reservoir size being infinite or

(ii) Volumetric replacement of produced fluids by either injection from an external source or movement from an adjacent fluid bearing portion of the reservoir, of gas, water or both fluids.

Clearly increased production rate could also be attained by either (a) increasing the reservoir pressure

or

(b) providing more energy for the vertical lift process.

Increasing the reservoir pressure above its initial value is difficult to conceive for two reasons:

(1) In any reservoir development, to achieve any noticeable increase in reservoir pressure decline would require fluid to be injected into the reservoir over a considerable period of time and this would normally preclude any significant production taking place in view of the consequent depletion of the hydrocarbon volume and pressure which would be associated with it.

2

2

Reservoir Production Concepts

(2) The volume of fluid to be injected into the reservoir to provide an increase in pressure would be dependent upon the overall compressibility of the reservoir rock and fluid system. For reservoirs of commercial size, the volume of fluid would be considerable and accordingly uneconomic compared with the alternative methods available to increase fluid production.

The concept of supporting fluid production by assisting the vertical lift process is defined as artificial lift. By this method the hydrostatic head pressure loss is either reduced by gas lift or the tubing pressure drop is offset by energy provided by a pump.

2.2.1 Fluid Injection into the Reservoir

The potential use of fluid injection to raise reservoir pressure above its initial level was largely discounted in the reasoning above. However, there are two aspects to the problem, the first being the absolute level of production rates achievable and, secondly, the duration for which these rates can be maintained and the schedule of declining production rates.

From the discussion of the material balance concept applied to hydrocarbon reservoirs, it is clear that unless fluid withdrawal from the reservoir can be compensated for by an equal volume of fluid flow into the reservoir from, say, a very large aquifer or another external source, then the reservoir pressure will fall. When the average pressure in the reservoir declines, then the available energy for production declines and as a result the oil production rate falls off.

Thus, the principal application of fluid injection into the reservoir is to try and balance the reservoir fluid volume withdrawn with that injected to thus maintain reservoir pressure. If this is accomplished, it will restrict the rate of production decline (Figure 14).

6000 5000 4000 3000 2000 1000 0 0 1 2 3 4 5 200,000 100,000 Qp B.O.P.D. Qwi B.W.P.D. p Qp Qwi Sustained Plateau Production Rate Maintenance of Average Reservior Pressure Time-Years Pressure P Figure 14

The benefits of fluid injection to sustain oil production

1

The decision as to whether water or gas should be injected is influenced by fluid availability and characteristics.

Water injection is of particular importance since water is usually available either as

produced water or sea water in an offshore situation. It also requires minimal repressurisation and treatment. Water is, however, only slightly compressible and as such is not an ideal fluid for compression energy storage but, alternatively as compression costs are low it is normally possible to treat and inject relatively large volumes of water.

Gas, however, for gas injection is more compressible and hence more suitable to maintain reservoir pressure however it also requires considerable compression to allow its injection into the reservoir. The supply of gas would be a predominant factor and in most cases its commercial value is of primary importance and this might preclude its use for reinjection unless no means of export is available whereby flaring would be the alternative recourse. The alternative of deferring gas sales due to its injection would bear an economic cost.