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Using DAKS™ to Evaluate Field Development
The Amal Field is situated in the eastern part of the Sirt Basin, Libya. It was discovered in 1959 and began producing in 1966. The field has an estimated STOIIP of 5 billion barrels, a very large productive area of 156,00 acres, and produces from a tight sandstone reservoir with an average permeability of one millidarcy. After more than 45 years of production, it has only recovered 18% of STOIIP (Figure 1).
The DAKS™ Analogue Workflow (Figure 2) was used to review the Amal Field and benchmark its recovery factor against applicable global analogues to identify best practices from fields with more efficient recovery.
Given the production challenge of low reservoir permeability the key questions of this study are:
Based on public domain data sources, both text and numeric parameters have been standardised and classified using the consistent rules defined by C&C Reservoir’s comprehensive classification scheme. This standardisation ensures that accurate comparisons can be drawn from directly comparable analogues contained within the DAKS™ knowledge base.
The following selection criteria (Table 1) has been used to identify appropriate analogues:
21 applicable global analogues were selected using the search criteria relevant to the Amal redevelopment challenges (Figure 3).
Analysis of recovery efficiency using the Empirical Recovery Chart, which describes the relationship between ultimate recovery, recovery to date and water-cut (cf. Tong, 1988), indicates an ultimate recovery factor of 40% should be possible for the Amal Field (Figure 4).
Benchmarking of Amal Field’s geologic and engineering parameters against applicable global analogues makes clear additional potential upside in recovery that can be realised with appropriate development techniques (Figure 5). Fields highlighted by the orange box will be analysed further to identify best practices that could be applied to Amal.
Data from analogue fields with more than 30% ultimate recovery suggests several successful secondary methods (Table 2). These include continuous water injection, hydrocarbon gas injection and water-alternating gas (WAG) immiscible injection, and conformance improvement techniques, such as modifying injection pattern, profile modification and zonal injection. WAG miscible flood and CO2 miscible flood have also been successfully applied to several fields that have achieved higher recovery, such as Alpine, North Ward-Estes and Rangely fields. Reservoir management best practices from those fields with more than 30% ultimate recovery include horizontal wells, infill drilling, hydraulic fracturing, matrix acidisation, artificial lift, production optimisation and well treatment.
The poor reservoir quality and weak natural energy drive documented in the analogous reservoirs reinforces the need for improved recovery techniques and adoption of good reservoir management practices are critical to optimise the ultimate recovery of the low-permeability sandstone reservoirs. Analogue-based analysis allows the operator to evaluate the cost of improved recovery programs against the value of the potential remaining recoverable reserves. This gives the operator of Amal an accurate way to determine and contextualise the economic viability of any re-development opportunity.
Tong, X.Z., 1988, Statistical rules of natural and artificial water drive reservoirs, in Tong, X.Z. (editor) Analysis of Oil Well Production Performance and Reservoir Behavior: Publishing House of Documentation for Science and Technology (First Edition), Beijing, Chapter IV, p. 56-92.
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