Oil field development

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Due Date Date Submitted For official use only04/01/2011 04/01/2011 LATE DATE

MATRIC No. 1112841

SURNAME EBHOHIMEN

FIRST NAME(S) OSEMEKHIAN

COURSE & STAGEEg MSc Oil & Gas Engineering MSc Drilling & Well Engineering MSC OIL AND GAS ENGINEERING

MODULE NUMBER & TITLE ENM 203

ASSIGNMENT TITLE FACILITIES ENGINEERING COURSEWORK

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OSEMEKHIAN EBHOHIMEN 1112841

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ALPHA OIL COMPANY

TANTALUM FIELD DEVELOPMENT PROGRAMME

Prepared by: OSEMEKHIAN EBHOHIMEN

Reviewed by

Approved by

Revision record

Revision Date Comment


TABLE OF CONTENTS_________________________ 3

i. SUMMARY____________________________ 4ii. INTRODUCTION ______________________ 4iii. Alpha Oil Companyiv. Tantalum Oil Fieldv. Tantalum Field Datavi. Tantalum Petroleum Characteristicsvii. Tantalum Field Estimated Production Forecastviii. Tantalum Production License legal and Fiscal

Requirementsix. Nearby Fields Available Datax. DISCUSSION_________________________ 81. DEVELOPMENT CONCEPTS____________________ 8

1.1 Selected Development Theme2. STANDALONE OPTION________________________ 14

2.1 Fastest Development Theme2.1.1 Hydrocarbon production and Processing2.1.2 Wells2.1.3 Production Platform and Storage2.1.4 Separators2.1.5 Flow Scheme Architecture2.1.6 Gas Processing2.1.7 Gas Lift2.1.8 Produced Water Processing2.1.9 Waste Treatment2.1.10 Hydrocarbon Metering and Export2.1.11 Flow Assurance2.1.12 Decommissioning2.1.13 Commercial Analysis

3. EXISTING FACILITIES OPTION________________ 233.1 Minimum Capital Expenditure (CAPEX) Theme

3.1.1 Technical Analysis3.1.2 Flow Scheme Architecture3.1.3 Wells3.1.4 Production Platform and Storage3.1.5 Separators3.1.6 Flow Scheme Architecture3.1.7 Gas Processing3.1.8 Gas Lift3.1.9 Produced Water Processing3.1.10 Waste Treatment3.1.11 Hydrocarbon Metering and Export3.1.12 Flow Assurance3.1.13 Decommissioning3.1.14 Hydrocarbon Allocation


3.1.15 Commercial Analysis4. DEVELOPMENT OPTIONS ADVANTAGES AND

DISADVANTAGES___________________________ 29 5. DEVELOPMENT OPTION OF CHOICE_____________ 30

6. CONCLUSION___________________________ 30

7. REFERENCES___________________________ 31

8. BIBLIOGRAPHY_________________________ 31

i. SUMMARY

This report analyses the field development options for the Tantalum field. Seven options were identified and ranked in ascending order based on cost of development. Development options were narrowed down to two options based on cost and investment risk analysis. The Fastest Development Theme was selected after extensive technical and commercial analysis.

ii. INTRODUCTION

An oil field development plan is about justifying the business case for a chosen option of development. To be able to do this, all legal, political and technically viable options and their constituent parts and considerations must be examined and compared on an equal basis. Various aspects of each development proposal such as technical feasibility, capital expenditure (CAPEX), operating expenditure (OPEX), environmental impact and assessment, risk assessment, legal requirements, decommissioning costs and issues, profitability (considering lease costs, taxes and royalties, cash flow and sensitivity analysis), lead time to first oil and company objectives in terms of the field’s development theme, need to be considered.

Another major consideration that plays a part in the development route chosen for an oilfield is whether the field can be considered as a marginal field or not. Marginal fields are typically developed under a minimum CAPEX /OPEX development theme, subject to favourable operating conditions. There are many definitions of what a marginal field is (Milton 1980). For the purpose of this development plan, a marginal field is defined as a field where the minimum capital expenditure outlay from well appraisal to first oil is considered too high to justify the investment risk of a full scale development platform (Milton 1980).


Alpha Oil Company

Assumptions: Alpha Oil Company is an independent oil producing company with 104 years of experience in offshore exploration and production. It has a worldwide staff level of 80,000 people with a high percentage of highly skilled and experienced workers. The company is a leading light in technological innovation and oilfield implementation of new technologies and has strong industry relationships with oil servicing companies, shipping and banking firms. Its average weighted average cost of capital (WACC) per oilfield is rated low by standard international banking institutions. As a result it is not inhibited from marginal field development.

iii. Tantalum Oil field

Assumptions

1.1 Tantalum oil field is located under moderate sea conditions at a water depth of 100 metres. The nearest landfall at a distance of 50km does not only have limited infrastructure, it is also a breeding ground for an existing nationalist organisation waging an independence struggle with the central government based at the main town 300km away. The organisation, is blatantly terrorist, and has been known to employ terrorist tactics in the past in its not too successful struggle with the central government.

1.2 The central government maintains a very active and strong naval presence in the continental shelf surrounding this landfall and has promised protection for Alpha Oil Company activities.

1.3 The price of oil (light sweet crude) will not fall below the base price of $65 used in this field development proposal. Current price of Brent blend as at 31/12/2011 is $107.21 (www.oil-price.net 2011)

1.4 All equipment, services and facilities required to develop any development option is readily available for immediate deployment and payment costs are not a problem.

1.5 Mean sea temperatures are moderately low.

iv. Tantalum Field Data


No Parameter Value

1 Reservoir depth 10000ft

2 Oil Water Contact 10200ft

3 Initial Pressure 5000psia

4 Bubble point 3800 psia

5 Initial Gas Oil ratio 450 scf/bbl

6 Crude Quality 36O API Light sweet crude

7 Stock Tank Oil Initially in Place (STOI IP)

300 MMBBLS

8 Recoverable Reserves 120MMBBLS

9 Location 20km from Landfall, 300km from Main Town Terminal

Table 1

Figure 1

v. Tantalum petroleum characteristics

With an initial Gas Oil ratio (GOR) of 450 scf/rb, Tantalum’s oil is classified is a black oil (Mason 2011). Hence gas production is not expected to be substantial.


vi. Tantalum Field Estimated Production forecast

Year Net Oil kbpd Water Cut %

1 10.0 5

2 25.6 15

3 50.9 20

4 50.1 30

5 49.8 40

6 40.5 52

7 30.1 58

8 23.9 62

9 20.0 67

10 17.2 71

11 15.0 73

12 13.0 75

Table 2

vii. Tantalum Production License legal and Fiscal Requirements

No Parameter Requirement

1 Gas No flaring

2 Environmental discharges Must meet minimum acceptable international standard

3 Revenue streams Must be metered

Table 3

viii. Nearby Fields available data


Palladium Field data

No Parameter Value

1 Platform type Steel J acket

2 Oil Export type Offloading buoy to shuttle tanker

3 Production rate 60kbpd , off Plateau

4 Production type Water injection, 30% water cut, rapidly increasing

5 Production Capacity 100,000 bopd, 100,000bpd gross liquids

6 Crude Quality 30O API

7 Oil Export Via SBM to shuttle tanker

8 Gas Used as fuel, excess flared

9 Water Overboard discharge, 40ppm maximum oil in produced water

10 Metering Oil metered to fiscal standards, 3 parallel trains + prover loop

11 Location 20 km south of Tantalum field

Other fields in Vicinity

1 Location of Successful exploration wells under appraisal.

100-150km south of Tantalum

Table 4

ix. DISCUSSION

1. DEVELOPMENT CONCEPTS

A number of development themes are available as options for the development of the Tantalum oil field. Itemised in the table below are the options possible.


Theme Well

Configuration

Platform Oil transport to terminal

Produced gas disposal

Produced water disposal

Drill Cuttings disposal

Fastest

Development

Subsea template

FDPSO Offloading buoy to shuttle tanker

Reinjection Sea disposal

Reinjection

Minimum CAPEX

Wellheads Subsea tieback

Offloading buoy to shuttle tanker


Reinjection

Maximum Production 1

Platform wellhead

Converted J ack-up rig

300 km undersea pipeline


Reinjection


Platform wellhead

Converted J ack-up rig.

50 km undersea pipeline, land pipeline to main town


Reinjection


Platform wellhead

Converted J ack-up rig with concrete subsea storage

Shuttle tanker


Reinjection


Subsea template

FDPSO 300km Undersea pipeline


Reinjection


Subsea template

FDPSO 50 km undersea pipeline to land, pipeline to main town

Reinjection Sea Disposal

Reinjection

Table 5

Below is the computed cost of development of each option.


Table 6

Table 7


Table 8

Table 9


Table 10

Table 11


Table 12

Ranking the options by cost only gives the following table.

Development Theme Development Cost ($ million)

Rank

Minimum CAPEX 851 1st

Maximum Production 2 930 2nd

Maximum Production 5 989.25 3rd

Maximum Production 4 1057 4th

Fastest Development 1083 5th



Table 13

1.1 Selected Development Themes

The objective is to narrow down the options to two themes, one using a standalone platform, and the other using a subsea tieback.


From the foregoing, the Minimum CAPEX option is selected for further consideration as a tieback option.

Maximum Production options 2 and 5, the next two options selectable on a least cost basis, use a land pipeline through territories subject to potential terrorist activity. These are undesirable options due to political instability and terrorism risks.

Maximum Production option 4 uses a 300 km subsea pipeline to the main town. This is likely to be fraught with operational challenges, undue risk and high OPEX.

Fastest Development theme, the next option on the least cost ranking, offers a technically and politically viable option for further study as a standalone option. This is therefore chosen as Alpha Oil Company’s standalone option.

Table 14a

2. STANDALONE OPTION

2.1. Fastest Development ThemeTechnical analysis of this theme involves examination of the processes of hydrocarbon production and processing, storage, gas and produced water processing, flow assurance and decommissioning issues.

2.1.1. Hydrocarbon Production and Processing2.1.2. WellsA subsea template with a total of eight slots will be installed and the two appraisal wells recompleted to producing wells. The eight slot subsea template makes provision for four additional wells to be drilled initially, with room for additional two producing wells in the future. One slot will be used for a gas injection well. The producing wells would be connected to subsea manifold which is connected to the FDPSO using flexible risers.

2.1.3. Production Platform and StorageAn Enhanced Floating Drilling Production Storage and Offloading (FDPSO) unit will be built for the Tantalum field. This option is chosen because of high rig rates, the requirement of drilling in the future, additional wells while in production and the requirement of early production of first oil (Murray 2009). It will be the third such vessel in the world and consists of a modular rig that can be removed and used elsewhere. Apart from standard oil processing facilities, it would also include gas compression facilities for gas lift and injection, desalters and NGL recovery (Kawase 1998).

2.1.4. Separators


The FDPSO will have two trains of horizontal separators to separate the oil, gas and water phases. Each train will consist of a HP and LP three-phase separator connected in series. Gas from the separators would be piped to the vessel’s NGL recovery plant, while produced water will be piped to the water treatment plant. NGL’s extracted would be added to the crude oil which is then piped to storage. Oil separated will be of Reid vapour pressure (RVP) and basic sediment and water (BS&W) specifications for the shuttle tanker. Antifoam and de-emulsifier chemicals would be injected at the inlets to aid the separation process.

Figure 3: Horizontal 3 phase separator (Ted Mason 2011)

2.1.5. Flow Scheme Architecture


Figure 2: Flow scheme for Fastest Development Theme


Subsea Template

Recompleted wells

Subsea Manifold

2 Slots for

future well on

manifold

Test Separator

Produced Water Treatment system

Storage

tanks

Meter system

Shuttle tanker

NGLs

extractor

Fuel

gas

To Gas lift

Train1

Train2

Stage 2 LP Separator

LP Compressor HP Compressor

LP Separator

HP Separator Stage 2 HP Separator

To water

Reinjection Well

2.1.6. Gas ProcessingGas from the HP and LP separators will be dried of moisture in dehydration column using glycol before being piped to the NGL module. The lower hydrocarbon gaseous effluent from the NGL module is then compressed and used as fuel gas for power generation. Excess gas is injected through the gas injection well into the reservoir.2.1.7. Gas Lift: All the producing wells will have completion components (side pocket mandrel SPM) to support future gas lift operations. When this is needed, gas will be diverted from the gas re-injection pump to the production wells.

2.1.8. Produced Water ProcessingThe produced water from the separators would then pass through hydrocyclone units to reduce the oil content to international standards of 30mg/L monthly average (Mason 2011). Effluents from the hydrocyclones would be passed through knock out drums to remove remaining gas. Oily water skimmed from the drums would be recycled to the separators. The treated water would then be pumped into the sea.

2.1.9. Waste treatmentDuring the drilling phases, waste cuttings will be pulverised into a slurry and re-injected into the subsurface. Sewage will be macerated and electro-chlorinated before discharge 20m below sea level.

2.1.10 Hydrocarbon Metering and ExportPeriodically calibrated turbine flow meter systems would be installed on the export line to the shuttle tanker for proper fiscal metering. Temperature, pressure, density and other oil sample data would be used to compute the net standard volume (NSV) of oil transferred.

2.1.11. Flow assuranceFlow assurance problems that are likely to occur are wax formation (due to black oil status of oil), hydrate formation (due to low temperatures subsea), scale deposition, sand erosion, loss of containment due to corrosion and slugging. As a result of these, an active regimen of hydrate inhibitors, oxygen scavengers, chemical de-waxing solvents, corrosion and scale inhibitors would be injected into the subsea wellheads, to arrest these problems from developing along the flow from wellhead through the flowlines, subsea manifold and flexible risers. In addition, the flexible risers would be of insulated type. Slugging would be addressed with installed slug catchers on the FDPSO. The table below illustrates the injected chemicals used in the production operation.


Chemical Dosage (ppmv) I njection point Fluid base

Corrosion inhibitor 30 Produced water pump suction

Produced water

Scale inhibitor 20 Wellheads Multiphase oil

Hydrate inhibitor (methanol)

60 Wellheads Multiphase oil

Oxygen scavenger (water utility)

150 Seawater suction for water utility lines

Seawater

Table 14b

2.1.12. DecommissioningAt the end of the field life of 12 years, the field installations would be decommissioned in line with the Oslo and Paris Convention for the protection of marine environments and The United Nations Convention on the Law of the Seas. The underlying philosophy would be to remove as much installations as possible from the sea floor. The decommissioning plan is as detailed in the table below.

No I tem Decommissioning Plan

1 FDPSO i. The FDPSO is expected to still be in very serviceable condition after the 12 year field life and would be hired out for service elsewhere.

2 Subsea wells i. Downhole tubing and equipment will be removed

ii. Residual hydrocarbons displaced with weighted brine.

iii. Wells will be plugged with cement to prevent fluid migration

3 Flowlines i. Flowlines will be flushed with water and abandoned in situ.

4 Flexible risers I . The flexible risers will be detached and reeled into a pipe lay vessel.

5 Umbilicals i. The umbilicals and control equipment would be retrieved.

6 Subsea wellheads, Christmas trees and manifolds

i. The subsea trees will be removed ii. Wellheads will be left in place, since they

pose no threat to navigational safety. iii. Manifolds will be flushed with water and

abandoned in situ.

Table 15


Figure 4 : How well will be plugged. (http://www.kosmosenergy.com/eias/Jubilee_Field_EIA_Chapter_8_23Nov09.pdf 2011)2.1.13. Commercial AnalysisOn the basis of assumptions and field specifications made earlier and an assumed inflation factor of 16% plus effective tax rate of 50% and capital allowance of 25% per year, the cash flow, cumulative cash flow and net present value (NPV) calculations for the life of the field are detailed below. The calculations and charts show a profitable operation with payback in 2nd year. In addition the sensitivity analysis shows that it will take a 78% drop in base oil price to $14.3 before the NPV falls below zero.


http://www.kosmosenergy.com/eias/Jubilee_Field_EIA_Chapter_8_23Nov09.pdf

Table 16 : NPV and Cash Flow

Table 17: Cash Flow at various Rates Table 18: Sensitivity Analysis


Figure 5: Net Present Value, Cumulative cash flow versus Time


Economic Limit

Payback in 2nd Year

Maximum Exposure

Figure 6: Sensitivity Analysis


3. EXISTING FACILITIES OPTION

3.1 Minimum Capital Expenditure (CAPEX) theme3.1.1. Technical analysis: Detailed below is the technical analysis of this theme.

3.1.2. Flow Scheme Architecture

Completed well

Future Well

Manifold

Figure 7: Flow scheme architecture of Minimum CAPEX Theme

3.1.3. WellsA semisubmersible offshore drilling rig would be hired to recomplete the two appraisal wells and drill eight more wells, six for production and one for water re-injection and one for gas re-injection. The producing wells would be drilled at individual locations and connected with flowlines to the central subsea manifold. The manifold would have additional space for the two future wells.

3.1.4. Production Platform and StorageDue to the heavily inadequate facilities at the Palladium platform (rising water cut, 100,000 bopd and 100,000bpd gross liquids, inadequate space for additional processing facilities) Tantalum production levels will be limited by Palladium’s facilities. Supply to the facility will use a valve to restrict supply to Palladiums capacity.

Assuming Palladium’s percentage water cut year on year rise is 20%, and rate of decline of oil production is 14% year on year, production rates from Tantalum and Palladium combined have been modelled, taking cognisance of the 100,000 bpd gross liquids restriction at Palladium. Palladium’s end of field life would occur at the end of the 9th year (92% water cut, 104bpd gross liquids) using this model. The chart below illustrates.


10” Bundle line with

Umbilicals and Gas lift

Palladium PlatformSubsea pump

Shuttle tanker

4” flowline tieback

Figure 8: Modelled flow rates of Tantalum and Palladium working together

The processed oil would be tied back to the Palladium platform 20 km south using a 4” multiphase flowline. A 10” bundle line would also be laid alongside to carry, control umbilicals and inhibitors to the wellheads and manifold. Oil would be metered to fiscal standards before being commingled at Palladium. The processing operation would be integrated with palladium’s for a fee in accordance with contract agreement.

3.1.5. SeparatorsThe Tantalum fluids, once commingled with Palladium’s will use Palladiums separators, regardless of its state, efficiency or design.

3.1.6. Gas ProcessingPalladium currently flares its excess gas. This would be a problem for the terms of Alpha Oil Company’s production license.Gas Lift: When gas lift is needed, gas will be pumped through the bundle line from Palladium to the wells. All the wells would have gas lift completions.

3.1.7. Produced Water Processing and Waste TreatmentThis would be restricted by Palladium’s specifications and would be done by palladiums facilities within capacity limits.

3.1.8. Flow assuranceThis would be the same as those faced by the Fastest Development theme discussed earlier. The flowline however, would be of insulated type. As dis cussed earlier, inhibitor injection would play a large role in maintaining flow assurance.3.1.9. DecommissioningThe applicable regulations and philosophy are as earlier discussed in the Fastest Development Theme. The decommissioning plan is as follows:


No I tem Decommissioning Plan 1 Subsea wells i. Downhole tubing and equipment will be

removed ii. Residual hydrocarbons displaced with

weighted brine. iii. Wells will be plugged with cement to

prevent fluid migration 2 Flowlines

And bundle lines

i. Flowlines and bundle lines will be flushed with water and abandoned in situ.

3 Subsea wellheads, Christmas trees and manifolds

i. The subsea trees will be removed ii. Wellheads will be left in place, since they

pose no threat to navigational safety. iii. Manifolds will be flushed with water and

abandoned in situ.

Table 18

3.1.10 Hydrocarbon AllocationAs a result of the sour nature of Palladium field’s crude, the best allocation method to use for the commingled stream is the Gross Product Worth method. Both streams would be metered before commingling. Fiscal metering will also be done at shuttle tanker loading. The market values of distillation products of Tantalum crude oil and the market values of distillation products of palladium crude will be obtained after laboratory analyses of the crude samples. The fuel oil component will be adjusted for sulphur (sour) content and viscosity. The actual allocation will then be done in accordance with the following formula:

GPWx ($/te) = sum of [gas contentx x value ($/te) + naptha contentx x value ($/te) + gas oil contentx x value($/te) + fuel oil contentx x value($/te)] (Arul 2011)

Where x refers to Palladium or Tantalum crude. It is assumed that no other operator is commingling their product with palladium. This calculation would also be done for the blend, and by difference, actual values of each crude obtained.

3.1.11 Commercial Analysis

Using the same variables as for the Fastest Development theme, this option, though profitable on the basis of the flow rate assumptions made, does not compare with the fastest Development theme. This is evident form the charts and data below.


Table 19: Generation of Actual allowable Tantalum production at Palladium

Table 20: NCF at various discount factors Table 21: Oil and Tax sensitivity table


Figure 8: Net cash flow and Cumulative cash flow versus Years for Minimum CAPEX option


Figure 9: Sensitivity analysis of Minimum CAPEX option


4. DEVELOPMENT OPTIONS ADVANTAGES AND DISADVANTAGES

The advantages and disadvantages of the two options are detailed below.No Fastest Development Theme: Technical and Commercial

1 Advantages Disadvantages

2 Higher production rate achievable.

Expensive CAPEX on FDPSO.

3 Flow Assurance problems of long tie backs minimised.

Sea stability issues affecting separator retention time.

4 Flexible control of production process.

Long lead time for FDPSO procurement.

5 Modular concept favours reusability of FDPSO.

Heavy exposure to lost production time due to small holding capacity of FDPSO (50,000 bbls), and potential weather problems for shuttle tanker (Waiting on weather WOW).

6 Availability of temporary storage. Much higher OPEX due to shuttle tanker rental.

7 Easy to decommission.

8 Easy to do well workover operations.

9 Much more profitable operation than the tieback option.

10 Purity and consequently higher value of crude preserved

11 Higher Cumulative Net Present Value.

12 Lower sensitivity to changes in Oil price or tax rate.

Table 22


No Minimum CAPEX Theme: Technical and Commercial

1 Advantages Disadvantages

2 Much lower OPEX. Limited processing facilities at Palladium constrict production severely.

3 Cheapest route to first oil. No room for expansion of facilities at Palladium.

4 Easy to decommission. Purity of Tantalum crude lost due to sour nature of tantalum crude.

5 Operates on a stable platform. Gas flaring at Palladium violates the terms of Alpha Oil company’s production license.

6 Potential for disagreements on wording and execution of signed agreement with Palladium.

7 Inefficient well workover and maintenance.

8 Higher exposure to flow assurance and corrosion problems.

9 Personnel Exposure to Palladium sulphur risks.

Lower Cumulative Net Present Value.

Higher sensitivity to changes in Oil prices or tax rates.

Table 23

5. DEVELOPMENT OPTION OF CHOICE

From the foregoing analysis, the Fastest Development Theme offers better return on investment and lower capital risk. It is therefore selected for development of the Tantalum field.

CONCLUSIONThe field development option that best meets the existing constraints and objectives of Alpha Oil Company for the development of the Tantalum field is the Fastest Development theme. In addition, going our earlier definition of marginal fields, Tantalum cannot be said to be marginal because the sensitivity analysis of the chosen option shows that the investment is safe irrespective of a huge 78% reduction in Oil price.

REFERENCES


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[online]. Available from:

http://www.offshore-mag.com/index/article-display/24292/articles/offshore/

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Engineering, Room C47, 13 October.

ARULANANTHAM D., 2011. Class lectures, ENM 202.[Lecture notes].

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Centre, School of Engineering, Room C47, 17 November.

BIBLIOGRAPHYOFFSHORE FIELD DEVELOPMENT PROJECTS. [online]. Available from: www.subseaiq.com


http://www.subseaiq.com/

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