School of EngineeringCOURSEWORK SUBMISSION SHEET

All sections except the LATE DATE section must be completed and the declaration signed, for the submission to be accepted.Any request for a coursework extension must be submitted on the appropriate form (please refer to http://www.rgu.ac.uk/academicaffairs/quality_assurance/page.cfm?pge=44250), prior to the due date.

Due DateDate SubmittedFor official use only

23rd December 2013

23rd December 2013

LATE DATE

MATRIC No1310182

SURNAMEParikh

FIRST NAME(S)Nilay

COURSE & STAGE

MSc Oil & Gas Engineering

MODULE NUMBER & TITLEENM202 Facilities

ASSIGNMENT TITLEField Development Report

LECTURER ISSUING COURSEWORKMike Robinson

I confirm:(a)That the work undertaken for this assignment is entirely my own and that I have not made use of any unauthorised assistance.(b)That the sources of all reference material have been properly acknowledged.[NB: For information on Academic Misconduct, refer to http://www.rgu.ac.uk/academicaffairs/assessment/page.cfm?pge=7088]

SignedNilay Parikh............................... Date ...23-12-2013...............................

Markers Comments

Marker

Grade

18

Gazelle Offshore Field Development Plan for Water Injection

Table of Contents1.Executive Summary42.Introduction52.1.Present Configuration52.2.Gazelle Reservoir Formation62.3.Production Forecast62.4.Environment and Legal Policies62.5.Other Development Activity63.Assumptions74.Development Options84.1.Option 184.2.Option 284.3.Option 385.Flow Schemes96.Economic Evaluation127.Flow assurance issues178.Critical Analysis188.1.Economic Analysis188.2.Platform Stability188.3.Transportation and Flow Assurance198.4.Decommissioning198.5.Selecting recommended option199.Decommissioning2010.Conclusion2211.References23

1. Executive Summary

This report evaluates the offshore field development options for the Gazelle field to drill water injection and disposal wells. Three options were identified and categorised based on development cost. Development plan was selected after considering technical and economic analysis. Report also includes decommissioning of the recommended option. The option selected for water injection consists of using Floating Production Storage and Offloading for oil and water handling with the Capital investment of $ 902 mm with a return of $ 16937 mm at the end of 12 years.

2. Introduction

Gazelle Offshore oil field is producing oil for six years and the production has shift off-plateau with increasing water-cut. Plan is to drill water injection wells to shift the oil production to present plateau rate. Development plan includes drilling of six injection and four disposal wells. Produced Oil from Gazelle field is transported to refinery Fort Thompson located approximated 200 km south west of the field. Plan is to re-inject some produced water into an upper horizon within the field.According to the present configuration all the gross production is routed through floating storage unit (FSU) from where oil is transported to refinery via shuttle tankers. Present field configuration was designed for no water production and current FSU is nearing its life after three years, thus requires re-development of the field. From the following information, options for Gazelle offshore oil field development plan for developing water injection and handling system is laid out. Selection of the recommended plan is based on Capital Expenditure (CAPEX), Operating Expenditure (OPEX) and the flow assurance issues. 2.1. Present ConfigurationCurrently there are two 50% trains each with 2 stages of 2-phase separation on steel jacket in 100 m water depth and oil de-hydration process depends on surge vessel to meet and tanker specifications. Oil is metered prior to offloading. Gas from the High Pressure separator and Low Pressure separators is compressed and conditioned for use as fuel gas, gas from the surge vessel plus any excess is flared. Produced water is allowed to settle in the FSU tanks prior to overboard discharge.

2.2.Gazelle Reservoir FormationGazelle field is located 45km from the nearest landfall to the North West.Field characteristicsGazelle UpperGazelle Deep

Reservoir depth10,000 ft12,000 ft

Oil water contact:10,200ft12,400 ft

Bubble-point:3,800 psia3,800 psia

Initial Gas oil ratio:450 scf/bbl500 scf/bbl

Initial pressure:5000 psia6100 psia

Light, sweet crude360 API.360 API

Expectation STOOIP300 mmbbl450 bbl

2.3. Production ForecastGas lift and two production-wells may be required in the future to enhance the productivity. Two injection wells may also be required.DeclineWater Injection

YearNet Oil kbpdWater Cut %Net Oil kbpdWater Cut %

175157515

25671.77614

34220.97416

43224.67018

52429.16921.8

61834.37026.4

71340.56331.9

81047.85738.6

9856.45146.7

10666.54656.5

11478.54168.4

12392.63782.7

2.4. Environment and Legal PoliciesGazelle field is now considered for standalone in economic and fiscal terms and no flaring of excess production gas is allowed. All the discharges must meet minimum accepted international standards of environmental discharge.2.5. Other Development ActivityOther operators have exploration license and are 50-75 km in the east of Gazelle field. Depending upon the success of exploration wells, operators are currently evaluating development plans.

3. Assumptions

Weather at the Gazelle field is favourable.

Subsea temperatures are moderately low.

Production wells and to be drilled injection wells are in the vicinity.

For cost estimation, inflation and royalties and are neglected.

Produced gas will be used up as fuel gas for turbines and utilities and there is enough power generation for run the facility.

All facilities are readily available in the market and when required are installed on the platforms.

All the legal permits are obtained for decommissioning.

Oil price will remain constant at $ 75/bbl for 12 years.

Fort Thompson has enough capacity for process increased production

All the required wells are drilled within one year and shuttle tanker is still in use till the pipeline is laid out.

4. Development Options4.1. Option 1Development plan includes refurbishment of existing FSU after 3 years. Subsea wells will be drilled and will tie-back to FSU by subsea manifolds. Oil and water treatment modules will be installed on FSU. Oil is exported to Fort Thompson by shuttle Tanker. Water injection module will also be placed on FSU and water will be injected through booster pumps.4.2. Option 2Development plan includes decommissioning of existing FSU and replacing it with Jack-up platform. Platform will be constructed with 12 slots, 6 for water injection wells, 4 for disposal wells and 2 for future production wells and the new jack-up platform will be bridged to the existing steel jacket. Dry wells will be drilled by renting a Jack-up rig. Oil treatment, water treatment and water injection modules will be installed on jack-up platform. 2-Phase separator is also replaced with 3-phase separator on steel jacket. Oil is exported to Fort Thompson by pipeline and water will be injected through booster pumps.4.3. Option 3Development plan includes decommissioning of existing FSU and replacing it with Floating Production Storage and Offloading (FPSO). FPSO will be constructed with 12 slots, 6 for water injection wells, 4 for disposal wells and 2 for future production wells. Subsea wells will be drilled and will tie-back to FPSO by subsea manifolds. 2-Phase separator will also be replaced with 3-phase separator on steel jacket. Oil treatment, water treatment and water injection modules will be installed on FPSO. Oil will be exported to Fort Thompson by shuttle Tanker via Single Buoyed Mooring (SBM) and water will be injected through booster pumps.

5. Flow SchemesMOL Pump

Effluent

OilBooster pumps

Disposal WellsWater InjectionHP &LP compStorageHP -2 Stage SeparatorLP -2 Stage SeparatorDesalter

Gravity segregation SegeSegraLiquidOil+WaterShuttleFluidsFortThompsonSTEEL JACKETFSUHydrocyclonesFuel and UtilitiesGasGasSand cyclone and cartridge filter

OilOilFigure 1 : Flow Diagram for Option 1

Oil

StorageHP -3 Stage SeparatorLP -3 Stage SeparatorCoalescerDesalter

Water InjectionDisposal WellsBooster pumpsPipelineMOL PumpHP &LP compFortThompsonSTEEL JACKETJACK-UP PLATFORMHydrocyclonesFuel and UtilitiesGasGasSand cyclone and cartridge filter

EffluentEffluentOilEffluent

OilOilFluidsFigure 2 : Flow Diagram for Option 2

Oil

StorageHP -3 Stage SeparatorLP -3 Stage SeparatorCoalescerDesalterShuttle via SBM

Booster pumpsDisposal WellsWater InjectionMOL PumpHP &LP compFluidsSTEEL JACKETFPSOHydrocyclonesFuel and UtilitiesGasGasSand cyclone and cartridge filter

EffluentEffluentOilEffluent

FortThompsonOilOilFigure 3: Flow Diagram for Option 3

6. Economic EvaluationTable shows the cash flows for all the options and option 2 and 3 provides the most the return on investment. Cost to drill a barrel of oil for all the option is as follows:cum oil $mmcum CAPEX $mmcum OPEX$mm$/bbl

Decline Base Case106100103610.71

Option 1 : Refurbish GAZELLE & FSO2661013196211.18

Option2 : Replace GAZELLE complete and Pipeline2661283174811.39

Option 3 : Replace GAZELLE & FPSO 266902212211.36

Table 1 : Economic EvaluationFrom the following cash flow it clearly states that, there would be more return from the field if the water injection is carried out.

Table 2 : Economic Evaluation for Decline curve

Table 3 : Economic Evaluation for Option 1Table 3 : Economic Evaluation for Option 2

Table 5 : Economic Evaluation for Option 3

7. Flow assurance issuesFlow assurance issues should be properly planned and addressed because it may stop the production of oil and rectification and cleaning of pipeline and flow-lines may be require high cost. Pigging is carried out if the pipeline gets choked. Following table shows the possibility of flow assurances in the Gazelle field and their likely solutions. (Brown, L. 2002) (Pipelineandgasjournal.com. 2013)Flow Assurance ProblemsOption 1Option 2Option 3Mitigations

HydratesThere are chances of hydrate formation in the production flow-line near subsea valves when production is stopped.There are chances of hydrate formation in export pipelineMethanol injection from production wellhead and heat retention in export pipeline

ScalesDeposition of scales in the tubing, flow-lines, water treatment and vesselInjecting scale inhibiting chemicals during water handling and maintaining low PH. Inhibitors are injected from iindividual wellheads and Water outlet from each LP separator

SluggingIt can be found in the production tubingEmulsions can be broken by heating or demulsifying chemical injection. Drag reducing agent (DRA) will be used in the oil export lines

SandSand deposition can be found in water injection flow line.Apart from the flow-line, sand can also deposit in export pipelineSand Hydro cyclones will be used to remove sand content and sand settling is avoided by maintaining velocities above a minimum velocity in pipelines.

CorrosionCorrosion of production and water injection flow-linesIt is also found in export pipelineInhibitors and Corrosion Resistance Alloys and they are injected at suction of each MOL booster pump. Cathodic protection is also used to protect export pipelines

Table 6 : Flow Assurance Problems and Mitigation8. Critical Analysis8.1. Economic AnalysisEconomic analysis for each option is performed and analysis narrows down to Option 2 and 3. cum CAPEX ($mm)cum OPEX ($mm)Cum Cash flow (Revenue CAPEX - OPEX)

Decline Base Case10010366816

Option 1 : Refurbish GAZELLE & FSO1013196216725

Option 2 : Replace FSU with Jack-up1283174816930

Option 3 : Replace FSU with FPSO902212216937

Table 7 : Economic analysis for all optionsOption 2 has high CAPEX - low OPEX and vice versa for option 3 but both the options will gives same return over the period of 12 years and so the selection of the development choice will be based on the other factors.8.2. Platform StabilityIn Option 2, Jack-up platform is to be installed will have legs lowered to the sea beds and if the currents are faster than sand at the bottom could wash away and would cause collapse of the platform. Moreover collapse can also occur in the event of blowout and fire. So Jack-up platform can possess stability issue.On the other hand in Option 1 and Option 3, Platforms are floating system and are less prone to subsea activities and will not possess collapse issue as in option 1. Moreover in Floating structure, Turret and swivel allows vessel to orient according to weathervane. This analysis tends to be more towards floating Production System and based on economic evaluation, Option 3 is suited.8.3. Transportation and Flow AssuranceIn option 1, treated oil is exported by pipeline to Fort Thompson and it may impose flow assurance problems like scale and sand deposition, corrosion and hydrates formation.In option 1 and 3, treated oil is suggested to ship via shuttle tanker which reduces flow assurance problems found in pipeline. However any disruption in shuttle tanker services may affect the oil production due to oil storage problem.8.4. DecommissioningDecommissioning of floating platforms in option 1 and 3 are easier due to inherent buoyancy and mobility than compared to fixed platform which is suggested in option 2. Moreover the decommissioning cost of floating platform is less than fixed jacket and also the installation time of the floating platforms would also be less than fixed platforms.8.5. Selecting recommended optionEvaluation the above the criteria will narrow down the selection of the recommended option and it is shown in the below table:CriteriaOption 1Option 2Option 3

Economic AnalysisRecommendedRecommended

Platform StabilityRecommendedRecommended

Transportation and Flow AssuranceRecommendedRecommended

DecommissioningRecommendedRecommended

From the above evaluation Option 1 and 3 are recommended but Option 1 is ruled out from the economic point of view and moreover there would be a lapse in production for one year, so Option 3 is recommended which is replacing FSU with FPSO.

9. DecommissioningDecommissioning of the installation would be carried out at the end of 12 years. Decommissioning of steel jacket and FPSO will be carried out according to the following process with environmental regulations. FPSOSBM and FPSO would be towed to the shore and would be placed elsewhere, since it would remain in working condition. Well Plugging Before the well plugging, well tubings and any down-hole instruments are retrieved prior to plugging the well and residual oil is removed by brine. [Iyalla. I, 2013] Well plugging would be carried out by 3 cement plug. Plug 1- squeezed into the producing zones Plug 2- in the middle of the well, near a protective Casing shoe Plug 3- the surface plug typically 250 ft. below the mud-line Well heads and Dry Christmas tree would be removed and flow-lines will be flushed and abandoned in-situ. Conductor removalAfter the plugging of the wells, Conductors below the mudline are removed with the help jacks. Topside RemovalRemoval of the topside modules will be carried out in the reverse process of the installation and it would be transported to the shore. Steel JacketThe steel jacket will be cut at the legs and transported to shore where it will be refurbished or recycled. Diamond wire cutting system will be used to cut the jacket. UmbilicalUmbilical and control equipment would be retrieved.

Subsea installationsInstallationPlan

Subsea Christmas trees

The subsea trees will be removed to reuse

Subsea wellheadsWellheads will be left in place

Subsea manifolds.Manifolds will be flushed with water and abandoned in situ.

Figure 4 : Well plugging Scheme Source: (http://www.kosmosenergy.com/eias/Jubilee_Field_EIA_Chapter_8_23Nov09.pdf)10. ConclusionFrom the analysis performed, for Gazelle offshore field development Option 3 is the best suited which gives a profit of $ 16937 mm with the investment of $ 902 mm. So FPSO will be used to inject water for obtaining required pressure to produce oil. Oil will be exported to Fort Thompson by shuttle Tanker via SBM and water will be injected through booster pumps.

11. References

Iyalla. I, 2013. Class lectures, ENM 202.[Lecture notes]. Decommissioning Legislation. Facilities module, Robert Gordon University, Energy Centre, School of Engineering, .[Accessed 18 December 2013]. Brown, L. 2002. Flow Assurance: A 3 Discipline. http://subsites.bp.com. 2013. Azeri, Chirag & Gunashli Full Field Development Phase 3, Offshore Platform Production. [online] Available at: http://subsites.bp.com/caspian/ACG/Eng/Phase3_v2_nov_04/05%20Ch05_09-04/05%20Chapt%205%20PD%20Section%205.5%20Process_ENG_FINAL_Oct%2004.pdf [Accessed: 19 Dec 2013]. http://www.kosmosenergy.com. 2009. DECOMMISSIONING AND ABANDONMENT. [online] Available at: http://www.kosmosenergy.com/eias/Jubilee_Field_EIA_Chapter_8_23Nov09.pdf [Accessed: 20 Dec 2013]. Pipelineandgasjournal.com. 2013. Integrated Flow Assurance Solutions | Pipeline & Gas Journal. [online] Available at: http://www.pipelineandgasjournal.com/integrated-flow-assurance-solutions?page=show [Accessed: 19 Dec 2013].Bibliography Arnold, K. and Stewart, M. 2008. Surface production operations. Amsterdam: Elsevier.

12.