Siba Gas Field Development Plan: Subsurface Uncertainties And Economic Criteria
By Muhammed Mazeel al-Aboudi
Dr Mazeel is a former Prime Ministerial Adviser and former Director General of the state-owned Iraqi Drilling Company and Oil Products Distribution Company.
Introduction
I have calculated and analysed the field development plan for Siba field in southern Iraq on the basis of existing data. I will develop estimation methods to simulate the gap in the existing geological and geophysical data as well as to simulate some issues related to well testing and recoverable reserves calculations. For this project I developed estimates for the field development plan (FDP), oil in place, gas in place, recovery factor, production profile and central plant facility (CPF), while taking into consideration the existing facilities, capital expenditure (capex), operational expenditure (opex) and calculating the commerciality under the technical service contract (TSC) fiscal regime.
Field Overview
The Siba-1 discovery well was drilled in 1969. The Yamama reservoirs were found to contain gas and condensate and the shallower Zubair formations to hold oil. The basis for the well location and prognosis was 2D seismic data which was acquired and processed in 1968-69. In 1979, supplementary seismic measurements were carried out. These measurements were processed in 1993. There is also more recent data available, which has only recently been processed. Additionally, there were two appraisal wells drilled, Siba-2 in 1974 and Siba-3 in 1992.
The Siba field has usually provided poor quality data. The seismic data, well tests and log data are especially uncertain. This is due to the seismic lines over the Siba-2 area, which do not allow for reliable mapping. As a result of the poor well tests from Siba-2 and the equivocal structural definition, this analysis will only consider the commercial development as well as the remodelling of seismic and well tests in Siba-1. The likelihood of recovering gas and condensate resources in the Yamama formation in the Siba area has been estimated by the Society of Petroleum Engineering (SPE). The results can be seen in Table 1 and Table 2.
Table 1 – Gas Recoverable Resources In Yamama Formation (Siba-1 Area)
Layers Name | 1C (Bcf) | 2C (Bcf) | 3C (Bcf) | Mean (Bcf) |
Yamama-A | 20 | 200 | 320 | 180 |
Yamama-B | 10 | 120 | 200 | 110 |
Yamama-C | 230 | 410 | 730 | 450 |
Yamama-D | 240 | 420 | 880 | 500 |
Total | 500 | 1,150 | 2,130 | 1,240 |
Table 2 – Condensate Recoverable Resources In Yamama Formation (Siba-1 Area)
Layers Name | 1C (Mn Bbls) | 2C (Mn Bbls) | 3C (Mn Bbls) | Mean (Mn Bbls) |
Yamama-A | 2 | 13 | 21 | 12 |
Yamama-B | 1 | 8 | 13 | 7 |
Yamama-C | 15 | 27 | 48 | 2 |
Yamama-D | 16 | 27 | 58 | 33 |
Total | 34 | 75 | 140 | 54 |
Table 3 – Oil Recoverable Resources In Zubair Formation (Siba-1 Area)
1C (Mn Bbls) | 2C (Mn Bbls) | 3C (Mn Bbls) | Mean (Mn Bbls) |
19 | 45 | 79 | 48 |
It was not possible to obtain a real state exploration strategy or geo-support data banking and the estimates given above were not calculated based on best data acquisition. The data, geology, geophysics, drilling-completion types, drilling fluids, water-oil/gas contact, aquifer type and characteristics were inconclusive.
Figure 1: Location Of The Siba Field
Geology
The Zubair formation can be partitioned into three sandstone reservoir units based on the description in the Final Geological Report on Siba-2. According to the report, all three zones in Siba-1 bear oil. Nonetheless, only unit II of Siba-1 yielded 1,099 b/d of 33° API gravity oil when tested.
The reservoirs with the most potential in the Yamama units are A, B, C, D, F and G. At Siba-1, it is conceivable that all of these units have produced hydrocarbons. However, only A, D, F and G are possible at Siba-2 because C and D are impermeable. Taken together, these results imply a hydrocarbon column, assuming discreet units, larger than 90ms.
Geophysics
Discrepancies exist in the present seismic data. According to the field development plan, it is necessary to acquire, process and interpret a 3D seismic study for the Siba-1, Siba-2 and Siba-3 areas. This would facilitate the mapping and establish the locations for appraisal and development wells. Applying advanced processing could assist in finding the free water level/fluid contact and/or potential petroleum reserves.
Well Testing
In Siba-1, the Zubair formation oil flowed at 1,099 b/d with a gas-oil ratio of 593 cu ft/barrel. The Yamama formation was also tested and gas flowed at 4.8mn cfd, with 712 b/d of condensate (condensate-gas ratio 150 barrels/mn cu ft). It is presumed that Siba-2 bears oil across the Zubair and underlying Yamama formation, but not enough to be commercial. Across several intervals tested in Yamama A, C, D and E-F formations, weak or zero flow was reported. Tests in Siba-3 over four Yamama intervals showed no flow. This could be due to incorrect perforations and formation damage at the Siba-2 and 3 areas.
Formation Evaluation
There have been no clear fluid contacts observed in the Siba wells. An inferred oil water contact at 4,103ms in Yamama D was noted in the Siba-2 well report, but this has not been confirmed independently. It has not yet been determined whether the Zubair and Yamama formations will have a single free water level, if the levels will be independent or if there will be a fill to spill level with each unit acting alone. Water flowed from Siba-3 when the Zubair formation was being drilled and only minimal oil was obtained from the Yamama while it was being tested. It is assumed that Siba-3 lies outside of the closure seen on the structure maps of Zubair and Yamama. This provides strong evidence of the highest known water levels. According to analogue information, the Zubair units I, II and III should be considered stacked layer cake reservoirs. In Siba-2, oil was obtained at the lowest level and water in the highest. This is an additional indication that the Zubair units need to be considered independently as stacked pay filled to different amounts.
Neither logging nor testing took place at Siba-3 and reports attest that water flowed there during drilling. As a result, it is clear that Siba-3 denotes the maximum limit of oil accumulation. In Siba-1, only Zubair units I and II have had volumes defined, as unit III has effectively no porosity. Due to the results of the petrophysical analysis and the results of the well tests for Siba-2, we assume that a pay is not possible in the Yamama reservoir in the Siba-2 area. We also propose that more precise results are necessary to define the appropriate status for Zubair in Siba-2. As a result, the volumetric calculations are primarily related to the Siba-1 area and proposed Siba-2 and Siba-3. I have also assumed that the volumes in the Siba-1 area are calculated for Zubair units I and II units, as unit III is tight. Water saturations are a major uncertainty in this field. The range of water saturations in the analogue field was from P10 30% to P90 50%.
Reservoir Recovery
I have chosen to use the experience recovery factor from analogue formations. In the Yamama C and D units, which showed gas and condensate reservoirs in Siba-1, gas recovery factors of P90 30%, P50 45% and P10 75% have been employed. For the Yamama units which were not tested in Siba-1 (A and B), the equivalent range used was 10% to 75%. The estimated oil recovery factors for the Zubair are P90 25%, P50 35% and P10 45%.
Production Profile Forecast
These assumptions allow the initial unconstrained potential to be defined as around 20mn cfd. The rate of production decline after the plateau is affected by the low deliverability of the Yamama formation and produces a long production tail. The final economic results may be affected if the tail production exceeds economic thresholds or the duration of the contract.
Figure 2: Gas Production Profile
The Zubair well flowed 1,000 b/d of oil during the Siba-2 test. In spite of this, the well potential of the Siba-1 accumulation is expected to be 2,500 b/d with hydraulic fracturing. Oil production and water injection will ensue through the second string of dual completion or injectors. The requisite well deliverability will be ensured by a string of 3½-inch tubing. The Zubair oil forecast assumes a 9,000 b/d fluid capacity in the central production facility.
Figure 3: Oil And Condensate Production Profile
Capex And Opex
Development well costs are based on approximately 45-55 days to complete drilling (3,500-4,000ms depth), a basic rig rate of $22,000-30,000/day and rig services rate of $14,000-20,000/day. Hydrogen sulfide (H2S) removal, dehydration and hydrocarbon dew point control prior to export are included in gas processing. The cost specifications comprise a 90km gas export pipeline, 30km oil export pipeline to Basra, 5% for drilling/completion and 15% for facility contingency. Abandonment costs have been calculated based on these figures: $0.2-0.3mn per well and facility abandonment cost of 5-6% of original capital cost.
Table 4: Cost Estimation ($Mn)
Activities | ($Mn) |
Appraisal/Exploration Phase | 55 |
Development Drilling $ Completion | 230 |
Central Facility Plant & Gathering | 280 |
Oil Export Pipeline | 13 |
Gas Export Pipeline | 80 |
Infrastructure | 15 |
Studies and FEED | 20 |
PMT, Owners Costs and Insurance | 24 |
General Administration Costs | 30 |
Total Development Costs | 747 |
Abandonment | 20 |
Total | 767 |
The oil price strongly affects the operating costs. The following calculations have been made for operating costs, assuming the oil price is approximately $70/B. Every four years a workover will be necessary and rig rates will be around $20,000/day. The annual fixed operating costs for the central processing facility will be $8.5-10mn. The gathering system’s fixed operating cost will be $1mn every four years. In addition, the fixed operating costs for pipelines will be $1mn, also for four years. Variable operating costs are $0.20-0.30/B of oil or condensate, and $0.045-0.075/mn cu ft.
Assuming a 20-year contract and based on the estimated capital and operating costs, the unit technical costs range from $1.40 per barrel oil equivalent (boe) to $2.20/boe.
Conclusion
It is necessary to acquire additional data, for example appraisal wells, fluid testing and 3D seismic surveys. This will decrease the level of uncertainty for investors and allow for prudent investment decisions. Regardless of the concept, it is advisable to acquire new data before proceeding. The new seismic interpretations are essential for the selection of new locations for up to three additional appraisal wells. It takes roughly 55 days to drill and test, if necessary. One year is likely necessary to complete the field development planning activities. The project schedule includes time for drilling and completion of 20-25 oil and gas production and injectors. All commercial aspects of the project will be completed in 15 months according to the plan. This includes reaching an agreement with the Ministry of Oil about the terms of the service contract and the closing of binding gas sales agreements. As it is difficult to predict the length of fiscal and commercial negotiations, this time frame is uncertain.
The top reservoir structure map, distribution of productive reservoir, fluid content of the various intervals, fluid contacts, connectivity within and between reservoir intervals, fractures contribution, reservoir properties and hydrocarbon saturation are the subsurface risk factors.
Furthermore, it is recommended to carry out an additional 3D seismic survey over the Siba-1 and Siba-3 structures in order to improve the mapping of closure and reduce volumetric risks. When mapping fluid contacts and areas of enhanced reservoir properties, advanced processing is necessary. The new seismic survey will also allow for ideal placement and development of the wells and it could reduce the number of wells necessary. It is probable that two or three additional appraisal wells will be required. The number of appraisal wells required is directly related to the size of the planned development.
Before large scale development can take place, a meticulous appraisal is required to ensure that there are sufficient economic resource volumes to support it. It is necessary to drill a crestal well near Siba-1 to confirm the distribution of productive reservoir, and one or two flank wells to extend to the lowest known hydrocarbons. The wells should be vertical to allow them to be used as production wells. As a result, it is critical to prolong the exploration/appraisal phase and to pre-stack and remodel the geophysical data. The economic figures have been calculated conservatively because of the safety and logistical problems which could confront the contractor.
Copyright MEES 2010.
