Comparative Analysis of Water Drive , Gas Drive and Natural Drive Mechanism for Oil Production using Alwyn North Field as a Case Study

DOI: http://dx.doi.org/10.24018/ejers.2020.5.4.1892 479  Abstract—In-situ Crude oil can be produced through several drive mechanisms of which the choice of specific drive mechanism is dependent on several key performance tools. This study examines the Alwyn North field and presents a comparative analysis for producing crude oil using water drive, gas drive and natural drive or depletion drive. The Eclipse Simulator was used to simulate different scenarios of well placement and performance tools such as FOPR, FPR, FWCT, FGOR and FOE was used during simulation to compare the outcomes of the well placement. Economic analysis which is key in decision making was carried out using economic tools such as Gross Profit Margin (GPM), Net Present Value (NPV), Payback Period, Internal Rate Return (IRR) and Profitability Index (PI). The payback period for water injection was 2.1years and 1.99years for gas injection. IRR was 53% and 48% for water and gas injection development schemes respectively and Profitability Index for water injection was 1.73 and 1.36 for gas injection. These economic tools helped to arrive at a conclusion of best drive mechanism for the production of the field.


I. INTRODUCTION
The movement of reservoir fluids (gas, oil and water) from the reservoir to the wellbore is as a result of the driving mechanism. The reservoirs nature is understood better and effective predictions can be made by evaluating how these drive mechanisms control the fluid behavior in-situ. Producing these reservoir fluids by the natural energy of the reservoir is known as Primary recovery [9].
The Schlumberger oil field glossary [8] classified reservoir drive mechanism into four, which are; 1) Gravity drainage 2) Combination drive 3) Water drive (edge water drive and bottom water) 4) Gas drive (gas cap or solution gas drive) However, selection of recovery scheme to embark on during oil production is dependent on many factors of which economics is very important.
Gas drive mechanism: This can be analyzed in different forms, either by solution gas drive (or dissolved gas drive) or by the gas cap drive. Solution gas drive is when the dissolved gas in the oil expands and its energy is used to support the production of the reservoir fluid. In some cases, where the vertical permeability is high, the gas can migrate upwards to form a secondary gas cap. Most times primary, secondary and tertiary recovery mechanism using gas drive are confused by scholars. Primary recovery is the use of the typical reservoir energy to produce from the reservoir to the wellbore, so gaslift can be classified under primary recovery. Secondary recovery is aided by an artificial pressure which is done by injecting gas (immiscible) into the reservoir to use its expansion energy to produce the crude. The tertiary recovery is also an injection process but here the gas is miscible with the reservoir fluid. The gas cap drive occurs in a reservoir identified to contain a gas cap with little or no water drive. Production is enhanced by the expansion of the gas cap and these type of reservoirs are characterized with slow decline in reservoir pressure [10].
Water drive mechanism: Most times more than one drive mechanism occurs at the same time, however, in water drive the water advances to take the place of the oil, either through the edge water or bottom water [2]. It is so far seen as the most effective drive mechanism but differs from field to field depending on the economics and characteristics of the reservoir. Also water injection can be confusing in analogy by scholars on the basis of primary or secondary mechanism. However, water injection is said to be primary if its aim of injection into the aquifer is for pressure maintenance, but secondary if its injection is for area sweep towards the producing well.
Eclipse Simulator: This is a Schlumberger reservoir simulator used for black oil, thermal, compositional and streamline simulations. It is said to be a benchmark for commercial simulators for over 25years and give a close representation of the reservoir.

C. Water equation
Corresponds to the "water component" contained in the water phase [6].
The basics of Material Balance Equation, MBE is used for simulation:

II. AIMS AND OBJECTIVES
The aim of this study is to propose a development plan for the Brent East reservoir in the Alwyn Field.
The following are objectives of this work: 1) Perform a natural depletion study 2) Perform a water injection study 3) Perform a gas injection study 4) Recommend the strategy to maximize the total hydrocarbon production and minimize the development cost in $/bbl.

III. LITERATURE REVIEW
The Alwyn North Field was discovered in 1974 in the South Eastern part of the East Shetland Basin in the UK North Sea, about 140 km East of the near most Shetland Island and about 400 km North East of Aberdeen. The Alwyn field lies respectively 4 and 10 km south of Strathspey and Brent field, 7 km east of Ninian field, and 10 km north of Dunbar field. The water depth is around 130 m. The field is in the UKCS Block 3/9 and extends northward into the Block 3/4.
The structure of Alwyn Brent East Block is generally an eroded monoclinal, with Base Cretaceous Unconformity (BCU) setting east and south limit, Spinal Fault setting west limit (separating Brent east from north and central west blocks), and a fault with sometimes very small throw setting north limit.
East structure under BCU is quite complicated, and described under the generic term of slumps.
In the Brent East panel, the oil zone is in a stratigraphic trap, created by the erosion unconformity to the east, by a north-south fault to the west (between A-1 and A-2 wells) and by a transverse fault to the north. Mehdi identified three energies which aid the flow of oil into wells as initial pressure, water drive and gravity. From his analysis of water drive, gas drive and water alternating gas (WAG) injection, water drive using 5-spot pattern model proved to produce optimum [4].
Petrowiki was more elaborate on forms which gas injection could be done based on its source. The following was listed: 1) Reinjecting produced gas into existing gas cap 2) Injecting gas into oil reservoirs of separated produced gas to maintain pressure 3) Injection of gas to prevent oil migration to gas cap 4) Injection of gas into under saturated oil reservoirs to swell the oil and increase recovery 5) To enhance high shrinkage, volatile oil and gas cap reservoirs with retrograde gas condensate recovery. Which shows that making gas injection a choice of enhancement for oil recovery is dependent on many parameters such as source of gas, oil property, economics, etc. [7] Julius and Benson in their search for a way to reduce the water cut of a Niger Delta field with weak aquifer flooded since beginning of production. They simulated using gas injection, water alternating gas (WAG) injection and gas alternating water (GAW) injection and the gas injection proved to be the most economical and reduced the water cut. This research highlighted another reason for enhancing recovery using gas [3].
F. David Martin also confirmed that water injection could be done with the aim of either disposing brine water, pressure maintenance when gas cap and aquifer expansion is not sufficient or to water flood oil after primary recovery. His work explained that water injection is a dominant secondary recovery process accounting for about 50% of US current oil production [1].

IV. METHODOLOGY
The following appraisal wells were drilled: 1) 2 vertical wells (A2 and A4) 2) 2 deviated wells (N2 and N3) N3 characterized the northern part of the field where an important oil log was confirmed mainly in the Tarbert units.
N2 located to the West did not produce any oil and only encountered the aquifer, which does seem to be active. The water salinity in the reservoir is about 17,000 ppm. From the well test data, the reservoir was characterized.   The wells were placed at the following positions with respect to the constraints listed below during this study.
In the water injection case, the field was developed using 9 wells which includes the existing four wells and 5 new wells.    Using the following cost estimates, the economic analysis of this simulation was computed.

V. CONCLUSION
The following conclusion were drawn from the analysis of the Alwyn Field. 1) Water and Gas Injection cases are both economically feasible.
2) The water injection has a larger investment.
3) Water Injection maximizes recovery at 46%. 4) Based on economic analysis, the water injection case is a better development option for the Alwyn Field.