01a reservoir management

Upstream Process Engineering Course Prepared by Genesis Oil and Gas Consultants Ltd

Reservoir Management1

Upstream Process Engineering Course

1. Reservoir Management



Contents

• Definitions

• Reservoir Management

• Geology

• Inflow Performance Relation

• Gradient Curves

• Primary Recovery

• Artificial Lift



Definitions• STC - Stock Tank Conditions

– Standard temperature and pressure, usually 60 ºF and 14.7 psia

• STB - Stock Tank Barrel– One barrel of oil at stock tank conditions

• GOR - Gas/Oil Ratio– The volume of gas produced divided by the volume of oil produced measured at stock tank

conditions

• GLR - Gas/Liquid Ratio– The volume of gas produced divided by the total volume of liquid produced (oil and water)

• Bg - Gas Volume Factor– The volume in ft3 that one standard ft3 will occupy at a given pressure and temperature

• Bo - Oil Volume Factor– The volume in barrels (bbl) occupied by one STB of oil and it’s associated gas when

recombined to a single phase liquid at a given pressure and temperature

• Rs - Solution Gas/Oil Ratio– The volume of gas in a standard ft3 that will dissolve in one STB of oil at a given pressure and

temperature



Definitions• Productivity Index

– The volume flow into the well expressed as barrels per day per psi of drawdown

• Oil Recovery– Percentage of oil recovered to that originally in place

• API - American Petroleum Institute – Crude API ; specific gravity = 141.5/(131.5+oAPI)• TPR - Tubing Performance Relation

– The relation between the bottomhole flowing pressure and the surface oil flow rate for a given wellhead pressure

• IPR - Inflow Performance Relation– The relation between the wellbore flowing pressure and the surface oil rate

• STOIIP - Stock Tank Oil Initially In Place– A measure of the oil reserves in place at stock tank conditions

• Drawdown– Difference in pressure between the reservoir pressure and pressure at the bottom of the wellbore

• Drainage Radius– Production well will only drain a part of a reservoir - each well has a radial limit beyond which there is no influence

on reservoir depletion



Reservoir Management

• Reservoir Features– Porous rock

– Impermeable layer

– Permeability

• Reservoir Management– Pressure

– Gas-oil contact

– Oil-water contact

– Withdrawal rates

– Gas injection rates and composition

– Water injection rates

– Perforation intervals

– Prediction of oil rate, GOR, water cut and composition with time

The formation pressure will normally be determined by the water column to surface at the oil-water contact



Types of Reservoir Structures

other stratigraphic

anticlines faults salt diapirs unconformity reef

combinationtraps

stratigraphictraps

structuraltraps

Prevalent inMiddle East

Prevalent in UKCS



Inflow Performance Relation

• Wells are tested to determine what the surface flow will be if the backpressure at the wellhead varies

• An Inflow Performance Relation curve is produced by simultaneous measurement of surface production and bottomhole pressure

• A straight line IPR indicates an undersaturated reservoir, curvature in the line indicates a gas or two phase flow

• The Productivity Index of the oil well can be found from the gradient of the IPR curve

• The intersection of the IPR and TPR curves determines the rate of stable flow that can be expected from the particular well



Gradient Curves

• The pressure drop required to lift a fluid through the production tubing at a given flow rate is one of the main factors determining the deliverability of the well

• By fixing the wellhead or bottomhole flowing pressure given the rates of oil gas and water, the pressure drop along the production tubing can be calculated by charts or correlations

• If the wellhead pressure is specified then a gradient curve can be used to determine the wellbore flowing pressure at different oil rates

• The resulting relation between bottomhole flowing pressure and oil rate is called a tubing performance relation

• Gradient curves are useful rules of thumb, more often analysis is carried out utilising specialist software such as PROSPER



Gradient Curves

Surface Pressure Gas Liquid Ratio



Primary Recovery

• Primary recovery techniques yield a wide range in recovery factor; between 5-30%

• Solution Gas Drive– Oil is produced by the natural expansion of dissolved gas in the oil

• Natural Water Drive– The reservoir pressure reduces as oil is produced allowing the aquifer to expand and

flow into the reservoir

• Natural Gas Drive/Gravity Drainage– The reservoir pressure reduces as oil is produced allowing the gas cap to expand

and assist recovery



Oil Recovery

Miscible Gas InjectorOil Producers

OWC

Water Injectors

Oil Producers

OWC

DepletionRecovery 2 - 30%

Water DriveRecovery 30 - 60%

Miscible Gas Drive (EOR)Recovery up to 80%

Oil Producer

OWC



Reservoir Management

• Secondary Recovery

– Gas and/or water injection

– Artificial lift –

• Gas,

• Electric Submersible Pumps

• Hydraulic Pumps

• Sucker Rod Pumps

• Tertiary/Enhanced Oil Recovery

– Miscible gas – Hydrocarbon, CO2, N2

– Surfactants

– Polymers

– Microbial

– Thermal/steam flood



Magnus Miscible Gas EOR



Well Types

S - shapeTangent

Horizontal



Wytch Farm ERD



Artificial Lift

• Pressure losses in the production tubing due to friction and elevation can be overcome using artificial lift– Gas Lift

• Gas is injected into the lower part of the production tubing and mixed with reservoir fluids, reducing the pressure gradient and lowering the formation backpressure

– Downhole Pump• Installing a pump at the bottom of a tubing string creates an artificial lifting

capacity and increases the available pressure to flow up the tubing

• The pump adds a controlled amount of pressure to the IPR thereby sustaining flow at higher than the natural rate

• Pump types - Electric submersible, hydraulic - turbine and jet



Artificial Lift

• Gas lift is only used in wells that produce economically with relatively high flowing bottom hole pressures (typically high-productivity reservoirs)

• Gas lift is limited to a certain minimum wellbore flowing pressure, therefore the potential production rate may be considerably less for gas lift than for pump lift

• Few moving parts are required therefore gas lift is suitable for wells producing sand or other solids

• Sizing a gas lift system involves calculating the relationship between

– gas injection rate and pressure

– depth of gas injection valve

– production rate



Artificial Lift

Effect of a pump on well performance

• Both methods of artificial lift enhance production rate by lowering the wellbore flowing pressure

• A downhole pump can produce the well at very low wellbore flowing pressures and thus approach the maximum open flow potential of the well

• The most commonly used downhole pump is the centrifugal pump, driven by a downhole electric motor which can be operated at constant or variable speed

• Variable speed pumps allow for a much wider range of operating conditions for a given size of pump

01a reservoir management

Documents