indy oil field development plan

Field Development Plan

2008/2009

MSc Petroleum Engineering

Heriot-Watt University

Indy Oil Company

Team Z

Adnan Al-Dhahli

Nasser Alteer

Isam Elshibani

Sheriff Faye

Mathee Kiatsakulphan

Pascal Lim

Gabriel Talong

TABLE OF CONTENTS

2.4. WELL TEST ANALYSIS ... 14

2.5. RESERVOIR MODELLING APPROACH ... 15

2.6. ECONOMICS ... 19

2.7. DRILLING ... 20

2.8. WELL PERFORMANCE ... 20

2.9. PRODUCTION FACILITIES & ISSUES ... 21

2.10. FIELD DEVELOPMENT PLAN ... 22

2.11. ENVIRONMENTAL CONSIDERATIONS AND FIELD ABANDONMENT ... 23

3. FIELD DESCRIPTION ... 24

3.1. STRUCTURAL CONFIGURATION ... 24

3.2. GEOLOGY AND RESERVOIR DESCRIPTION ... 24

3.2.1. Depositional Environment ... 24

3.2.2. Stratigraphy ... 26

3.2.3. Source Rock ... 27

3.2.4. Trap and Seal ... 27

3.2.5. GEOSTATISTICAL DESCRIPTION OF CORE SAMPLES ... 27

3.3. PETROPHYSICS AND RESERVOIR FLUIDS ... 28

3.4.1. CORRECTIONS FOR BOREHOLE EFFECTS ... 29

3.4.2. RESERVOIR LITHOLOGY DESCRIPTION ... 29

3.4.3. WELL CORRELATION ... 30 3.4.4. WATER RESISTIVITY ... 30 3.4.5. POROSITY MODEL ... 30 3.4.6. DETERMINATION OF SW ... 30 3.4.7. PERMEABILITY LOG ... 31 3.4.8. MOVEABLE HYDROCARBONS ... 31 3.4.9. NET-TO-GROSS ... 31 3.4.10. FLUIDS-BEARING ZONES ... 32 3.5. RESERVOIR FLUIDS ... 32 3.5.1. PVT Analysis ... 32 3.5.2. Water Analysis ... 33 3.6. HYDROCARBONS IN PLACE ... 34

3.6.1. Uncertainties Associated with HCIIP Determination ... 34

3.7. WELL PERFORMANCE ... 36

3.7.1. APPRAISAL WELL TESTING ... 36

Extended Production test ... 36

Drill Stem Test ... 37

3.7.2. Well flowing design ... 39

3.7.2.1. WellFlo Analysis ... 39

3.7.3. Wellbore Completion ... 43

3.8. PRODUCTION ISSUES ... 44

3.8.1. Scaling Corrosion ... 44

3.8.2. Wax & Asphaltenes ... 45

3.8.4. Corrosion ... 45

3.9. RESERVOIR MODELLING APPROACH ... 46

3.9.1. Introduction ... 46

3.9.2. RESERVOIR MODELLING ... 46

3.9.2.1. BODY GEOMETRY AND STRUCTURE ... 47

3.9.2.2. PROPERTY MODELLING ... 47 3.9.2.3. UPSCALING ... 49 3.9.3. SIMULATION MODELS ... 49 3.9.3.1. INITIALIZATION ... 49 3.9.3.2. WELL MODEL ... 49 3.9.3.3. FAULT MODEL ... 50

3.10. SIMULATION RESULTS AND MAIN SENSITIVITIES ... 50

3.10.1. RECOVERY MECHANISM ... 50

3.10.2. DRAINAGE PLAN AND WELL LOCATION ... 52

3.10.3. SENSITIVITIES ... 54

3.11. ALTERNATIVE DEVELOPMENT PLANS CONSIDERED ... 56

4. DEVELOPMENT AND MANAGEMENT PLAN ... 59

4.1. ECONOMICS AND FINANCIAL CONSIDERATIONS ... 59

4.1.1. GENERAL ... 59

4.1.2. INDY OIL COMPANY PORTFOLIO ... 60

4.1.3. TIE-BACK TO THE CLAIR FIELD (BP)... 60

4.2. DEVELOPMENT PLAN, RESERVES AND PRODUCTION PROFILES ... 61

4.2.1. DEVELOPMENT PLAN ... 61

4.2.1.1. Base case Development plan ... 61

4.2.2. RESERVES ... 63

4.2.4. WATER INJECTION POTENTIAL... 65

4.3. FIELD MANAGEMENT PLAN (FMP) ... 66

4.3.1. UNCERTAINTY MANAGEMENT. ... 66

4.3.1.1. Reservoir Heterogeneity ... 66

4.3.1.2. Faults and reservoir compartmentalisation ... 67

4.3.1.3. Deposition of the turbidites ... 67

4.3.1.4. Reservoir fluid properties ... 68

4.3.1.5. Size of the lower reservoir ... 68

4.3.2. Workover, Re-entry and sidetrack potential ... 69

4.3.3. Artificial Lift... 69

4.4. Further data gathering ... 69

4.4.1. MANAGEMENT OF RESERVES RANGE ... 71

4.5. DRILLING FACILITIES ... 71

4.5.1. OVERVIEW ... 71

4.5.2. RIG SELECTION ... 72

4.5.3. PRESSURE PROFILE AND MUD PROGRAM ... 73

4.5.4. WELL CONTROL ... 74

4.5.5. FLUID SELECTION ... 74

4.5.6. BIT SELECTION ... 75

4.5.7. CASING DESIGN ... 76

4.5.8. CEMENTING ... 77

4.5.9. DISPOSAL OF DRILL CUTTINGS AND MUD ... 78

4.5.10. BOTTOM HOLE ASSEMBLY ... 78

4.5.11. DIRECTIONAL DRILLING ... 78

4.5.12. RISKS AND UNCERTAINTIES ... 79

4.7. ENVIRONMENTAL IMPACT AND ABATEMENT ... 80 4.7.1. NON-TECHNICAL SUMMARY ... 81 4.7.2. ABANDONMENT ... 83 4.7.2.1. Abandonment Requirements ... 84 4.7.2.2. Surface Abandonment ... 84 4.7.2.3. Subsurface Abandonment ... 84 4.7.2.4. Equipment Recovery ... 85 4.8. COSTS ... 85 4.8.1. TAXATION ... 87 4.8.2. ECONOMIC ASSUMPTIONS ... 87 4.8.3. ECONOMIC PARAMETERS ... 88

4.8.4. CASH FLOW MODEL ... 88

4.8.5. ECONOMIC UNCERTAINTIES AND RISK MANAGEMENT ... 88

5. REFERENCE ... 91

List of tables

Table R1: Reservoir and fluid properties for using in reservoir simulation model

Table R2: The initialized parameter in simulation model

Table R3: Recovery factor from the different scenario models

Table R5: Alternative development plan comparison

Table G2: Statistics from well Z-7 core plugs

Table FE1: Wireline logs for each well

Table R7: Hydrocarbon Analysis of Reservoir Fluid Sample

Table R8: Produced water analysis

Table P4: Layer pressure vs Water cut

Table P5: formation water dissolved solids

Table R13: Properties used in simulation model

Table R14: The initialized parameter in simulation model

Table E1: Clair Processing Capacity

Table DVP3: the ranges of recovery factor from model simulation

Table D2: J.W.McLean specifications

Table D4: Drilling Fluids and Additives

Table D5: Bit selection

Table D6: Casing design

Table D8: cuttings volume and disposal

Table D9: Directional drilling overview

Table D10: Drilling Risks and Uncertainties

Table E2: Capital expenditure

Table E4: Operating costs, year 2011

Table E6: Economic assumptions

Table E7: Economics parameters

List of figures

Figure R4: Sensitivity analysis results

Figure R6: Five producers and five injectors position in the field development plan

Figure R7: Expected Production profiles

Figure G1: Core pictures (left: pebbles in sand, right : sand and cemented zone)

Figure P2: Neutron-density cross plot

Figure R9b: Sensitivity analysis of individual parameters

Figure R9 and Figure R10: STOIIP calculation from the volumetric estimates of HCIIP and Material balance

Figure R11: The extended well test data

Figure P1: well head sensitivity

Figure P2: Tubing size sensitivity

Figure P3: Deviation angle sensitivity

Figure R12: Reservoir 3-D simulation model

Figure R15: Well positions in three recovery mechanisms

Figure R16: Recovery factor simulated by three recovery scenarios.

Figure R17: the well location from pattern A

Figure R18: the well location from pattern B

Figure R19: Sensitivity analysis results

Figure R20: Six production wells development plan

Figure R21: Fix slot platform and two deviated wells

Figure R22: Alternative development plan comparison

Figure R23: Deviated well sensitivity analysis

Figure R24: FOPR vs time for deviated wells

Figure DVP1: Five producers and five injectors position in the field development plan

Figure DVP2: Development plan and drilling program

Figure DVP4: Production profiles for field development plan

Figure DVP5: Field water injection rate profiles

Figure G3: Effects of cemented zones on vertical permeability

Figure D1 : J. W. McLean semisubmersible

Figure D3: Pressure Profile

Figure EV1: Risk Management Review Committee

Figure E3: Capex breakdown

Figure E5: Opex breakdown for year 2011

List of abbreviations

API American Petroleum Institute

bbl Barrel

BEP Best Environmental Practices

BHA Bottom Hole Assembly

Bo Oil Formation Volume Factor

Boi Initial oil Formation Volume Factor

BOP Blow Out Preventer

BU Build Up

BUR Build Up Rate

BUS Build Up Section

Bwi Initial Water Volume Factor

CAPEX Capital Expenditure

Co Oil Compressibility

Cr Rock Compressibility

DCF Discounted Cash Flow

DST Drill Stem Test

DTI UK Government Department of Trade and Industry

ESP Electrical Submersible Pump

FDP Field Development Plan

FPSO Floating Production and Storage Offshore vessel

GIIP Gas Initially In Place

GOR Gas Oil ratio

HIP Hydrocarbons In Place

HPWBM High Performance Water Based Muds

HSE Health and Safety Executive

IADC International Association of Drilling Contractors

ILD Dual Induction Log

ID Internal Diameter

IOC IRR

Indy Oil Company Internal Rate of Return

Kh Horizontal Permeability

Kv Vertical Permeability

Kv/Kh Vertical to Horizontal Permeability Ratio

KOP Kick Off Point

LLD Dual Laterolog

LWD Logging While Drilling

MCO Maximum Capital Outlay

MMSTB Million Stock Tank Barrels

MOD Money of the Day

MWD Measurement While Drilling

NCF Net Cash Flow

NPV Net Present Value

NTG Net To Gross ratio

OBM Oil Based Muds

OWC Oil Water Contact

Pb Bubble Point Pressure

PDC Polycrystalline Diamond Compact

PIR Profit to Investment Ratio

Pr Reservoir Pressure

Psi Pounds per Square Inch

PWD Pressure While Drilling

PVT Pressure,Volume,Temperature

QHSE Quality Health Safety and Environment

QRA Quantitative Risk Assessment

RF Recovery Factor

RIH Run In Hole

ROP Rate Of Penetration

ROV Remotely Operated Vehicle

Ro Resistivity of 100% water saturated rock

Rt True Formation Resistivity

Rs Solution Gas Oil Ratio

Rw Water Resistivity

SAC Special Area of Conservation

SBM Synthetic Based Muds

SCAL Special Core Analysis

Scf Standard Cubic Feet

STB Stock Tank Barrels

SSCV Semi Submersible Crane Vessel

STOOIP Stock Tank Oil Originally In Place

Sw Water saturation

TOC Top Of Cement

UKCS United Kingdom Continental Shelf

UKOOA United Kingdom Offshore Operators Association

VOC Volatile Organic Compounds

WBM Water Based Muds

WDA Written Down Amount

WHP Well Head Pressure

1.

EXECUTIVE SUMMARY

The Z-field is an oil field located in the North Sea, west of the Shetlands Islands (see map appendix 1). It is situated near a bigger field named Clair and operated by BP. Seven appraisal wells were drilled, and various data was gathered to know more about it. Our Field Development Plan presents our technical interpretation of the data and as a consequence how we decided to develop the field and produce the reservoir hydrocarbons.

Reservoir characteristics

The Z reservoir is synclined and highly heterogeneous due to the depositional environment which is a turbidite. The field includes two layers: one main layer containing around 150 million STB of oil in place (P50, obtained by material balance and by reservoir geometry) from Early Cretaceous, the oil-water contact being at a depth of around 8900 feet, and another one located below the main layer. However, data is too small to have a precise idea of how to develop this layer. For the main one, a recovery factor of around 35-40% is expected in the most likely case. However, several uncertainties are inherent to the field: how is the heterogeneity going to affect the permeability? Are there faults? Our development plan deals with these uncertainties by not letting them having a huge effect on the expected results before more data is gathered for a better understanding of the reservoir.

Development plan

We chose to develop the reservoir with 5 producers and 5 water injectors. This development scenario has been tested against several others (natural depletion, polymer injection), but this one gives the best results. Several drainage patterns were tested, leading to the optimized results being the base-case of the study. Water injection allows providing pressure support to keep the reservoir above the bubble point pressure.

Surface facilities

The Z-field is a marginal deep water field. Quite close to it is the much bigger field Clair (in terms of production and size) with processing facilities and hydrocarbons transportation facilities. Therefore, it has been decided to develop our field by tie-backing the Z-field production to the Clair field. This choice is mainly motivated by economic reasons; the other scenarios (FPSO or Tension-leg Platform) were giving lower NPVs and less recovery.

Economics considerations

Furthermore, this tie-back option allows mitigating several uncertainties: the Clair field is big enough to support a higher production than expected, and a lower production would simply result in the early abandonment of the field (still profitable). Variations of other economic factors such as oil price or exchange rate still make this project have a positive NPV. Therefore, the economic model is quite solid. Furthermore, this development strategy is in accordance with Indy Oil Company strategy, which is maximizing utilization of core infrastructures and maximizing the recovery.

Further development

More data need to be gathered in order to know more about the reservoir, especially the western area, to detect potential faults or assess the reservoir performance. The lower layer reservoir unit is quite a big uncertainty: how big is it? How hard will it be to produce hydrocarbons from it? Further development of the Z-field clearly involves the gathering of more data from this layer. The additional reserves will extend the field life of a few years; our development plan takes it into account by the possibility to purchase additional processing and transport facilities on the Clair field if needed.

2.

TECHNICAL SUMMARY

2.1.

GEOLOGY

The reservoir structure is characterized by its shape: it is synclined, the strike line of the two limbs being in a North-West to South-East direction. The shape of the upper layers (syncline as well) indicates that the deformation occurred after deposition. Core photographs indicate that the depositional environment is a turbidite going from the southern zone and spreading like a fan towards the exterior of the structure (it is actually thinning in these directions, being the thickest at the depositional source). Therefore, a high heterogeneity characterize the reservoir: there is no clean sand body but a mix of sand, mud and clay with cemented zones. This raises the uncertainty concerning the reservoir vertical permeability. Another uncertainty is the presence of faults in the reservoir.

2.2.

PETROPHYSICAL EVALUATION

Petrophysical analysis was carried out using an extensive suite of wireline Logs, SCAL, PVT analysis and RFT pressure surveys, gathered from seven appraisal wells.

In Well Z5, Z3 and Z1, the entire net pay thickness encountered was oil-bearing sand. Well Z4 was a dry hole, a water bearing sand was found below the OWC of well Z5. Well Z7 encountered two main reservoir sand bodies. GR and SGR were used for lithology identification and well-to-well correlation. The upper reservoir unit was correletable across the field.

The upper reservoir unit becomes thinner and the quality of reservoir deteriorates towards the eastern side of the field. Lithology Log for Well Z6 and well Z7 showed the reservoir is sandstone dominated, which was confirmed by the Density-Neutron cross plot. Besides, observation of cores retrieved from Well Z3 and Well Z5 showed heterogeneous

sand. The petrophysical properties of the reservoir have been computed using many methods for each well. Well Z1 was no used for analysis because of the insufficient data.

Shale Content was calculated using GR method, porosity was solved with bulk density logs except for well Z6 where we used sonic Log as there was no density Log. Water resistivity was computed using the water sampling analysis result of well Z5. Water saturation (Sw) was calculated using the Simandoux equation. The permeability was determined from linear regression, using the Core porosity and core permeability derived from SCAL.

2.3.

PVT ANALYSIS

Surface and subsurface fluid samples were collected from well 1, 3, 5, and 7 by FIT (Formation interval test) and conventional DST. The PVT analysis and gas chromatography were carried out to analyse fluid properties and hydrocarbon composition.

In terms of PVT analysis, the reservoir fluid seemed to be a light oil with API higher than 31.5 and low GOR (220 scf/STB). The oil properties in the Z-field are characterised as a highly undersaturated oil with a bubble point around 1050-1120 psia. In addition, the properties of fluid in upper and lower reservoir appeared to have no significant difference. They were considered uniform for the entire field. Thus, these results indicated that it will be possible to produce as commingled fluid from the two zones.

Regarding the reservoir fluid composition, the result showed a very low amount of hydrogen sulphide (<1ppm), contained in both upper and lower reservoir fluid with around 2% carbon dioxide. Therefore, the corrosion may be an issue and corrosion inhibitors will be used if necessary.

2.4.

WELL TEST ANALYSIS

The production test in well Z-1 was conducted to get a good indication of STOIIP by using material balance. The oil has been produced for 1 year with a cumulative production of

751,000 barrels and followed by long time period shut in. As a result of this test, the pressure was depleted of around 213 psi from the initial reservoir pressure with a PI around 2.89. At the beginning of this test, the bottom hole pressure dropped rapidly by 286 psi in 21 days at the early stage of test. Moreover, the reservoir pressure didn’t stabilize to the initial reservoir (3713 psi), although it has been through a long shut in period (3 months). Therefore, the drive mechanism of this field seems to be depletion with no aquifer support or very small support in this field. Furthermore, the OIIP which is calculated by material balance is around 120-200 mSTB. This result is based on the fact that no water influx is occurring in the reservoir.The oil volume by MB equation shows a good consistency with the STOIIP obtained from the volumetric calculation. Based on these results, it can be concluded that this reservoir has no large fault to block the pressure disturbance in reservoir.

The DST well testings, which has been conducted in well 2, 3, 5, and 7, show a wide range of productivity index from the different areas of reservoir. Based on the results, the high PI zone is situated in the West area (Z-7) with productivity index from 5-7. This result shows a good agreement with the geological study and core analysis which indicated the high quality sand with high permeability and porosity in this area. However, the DST testing time from the other wells seemed to be very short (25-70 hrs), resulting in no late time region observed in log-log derivative plot analysis. Due to the low quality of data, this problem is needed to be dealt with and treated as the uncertainty in order to reduce the risk for field development project.

2.5.

RESERVOIR MODELLING APPROACH

Regarding the simulation study, the scenarios will be selected to study the field recovery efficiency. In addition, natural depletion, water flooding, and polymer flooding development plan will be simulated. After that, the effect of well positions, number and type of well (deviated and vertical) will be analyzed to construct the base case model. Lastly, the

sensitivity analysis will be carried out to study the effects of recovery efficiency from the reservoir uncertainty. Based on the undersaturated oil in reservoir, the 2phase, 3-D ‘Black Oil model’ was used to simulate the area of reservoir by ECLIPSE100. Subsequently, the reservoir model consists of 56x28x20 cells by grid corner point structure which generated and exported from PETREL software. In addition, reservoir and initialize properties are shown in

table R1 and table R2 respectively.

Reservoir properties Water Properties

Average temperature,

°F 175

Density,

lb/ft3 65.8 Initial Pressure, psia 3770

Bwi, rb/STB 1.02 OWC, ft (TVD) 8850 Viscosity, CP 0.4 Cw, psi-1 2.46E-06

Oil Properties Rock properties

Density, lb/ft3 43 Cr, psi-1 7.50E-06

Boi, rb/STB 1.17

GOR, scf/STB 224

Viscosity, CP

0.97-1.23 Bubble point pressure,

psia 1122

Table R1: Reservoir and fluid properties for using in reservoir simulation model

Datum, ft TVD Pi at Datum, psia OWC, ft TVD Pc at OWC, psia Oil in place, million barrels Reservoir initial conditions 8500 3770 8850 0 140

Table R2: The initialized parameter in simulation model

A coarser grid is then created (31,600 cells) and is used for the properties upscaling from the fine scaled grid (1,693,440 cells). The vertical transmissibility still is the uncertainty in this reservoir. It will be treated as an uncertainty and need sensitivity analysis. During simulation process, the reservoir was assumed to keep the reservoir pressure above bubble point pressure with constant temperature, resulting in no gas coming out of solution in the

reservoir. In terms of well modeling, all wells were set up with the tubing 0.67 ft for both producers and injectors. The location of the new wells tended to be drilled at the high PI zone near the appraisal well Z-7. Regarding the water flooding and other case scenarios, the appraisal wells were used as injector and producer for saving cost and rig time. However, the new wells seem to be necessary to achieve high production and economic rate (2,000 bopd). Based on the assumption that the reservoir will be produced above bubble point pressure, all wells were controlled by the bottom hole pressure (1,200 psia), whereas the injectors were limited at 12,000 psia to keep reservoir pressure constant. The production wells tend to be perforated in upper zone to avoid early water breakthrough.

Simulation results and main sensitivity

a) Recovery mechanism

By simulation study,the natural depletion scenario had a recovery factor of just above 10 percent after 4,000 days whereas the recovery efficiency in the water flooding case increased more than 38% during the same period. This result shows that the reservoir needs some pressure maintenance even at the early stage of production. However, the recovery factor from the polymer injection was not better than water flooding as expected. This is because not only the pressure support is an important parameter for improving the recovery efficiency but also the sweep efficiency that has to be improved to achieve the ultimate recovery.

Model Water Injection Natural Depletion Polymer Flooding

Recover Factor 38% 10% 28%

Table R3: Recovery factor from the different scenario models b) Drainage Pattern

The well location experiment was analyzed to compare between the extra injectors in the middle field (Pattern A) and only the edge water injection (Pattern B). After the simulation

study, the pattern A (an extra injector in the middle and edge area of the reservoir) appeared to be the most effective and has been selected as the base case for sensitivity study. In addition, this case has the following benefits.

- Higher production rate and recovery efficiency

- A number of wells at the high PI zone which allows to produce fluids from two zones.

- The injectors in the center and West area lead to better pressure support for the entire field.

- All appraisal wells were used as injectors or producers, allowing savings on drilling costs.

- Reduction of the risk of the connectivity uncertainty in the case where there are some faults isolating the high PI area from the other parts of reservoir.

c) Sensitivity analysis

The sensitivity analysis was used to take into account the uncertainty which occurred in the reservoir simulation. In addition, the reservoir and fluids properties were studied the impact on the recovery efficiency. The result of the analysis was demonstrated by a spider diagram in figure R4.

Figure R4: Sensitivity analysis results

Two models were developed from the base case and used as the alternative plan. Firstly, a new producer was added from the base case to increase production. While the second plan used the two deviated wells instead of the vertical wells in the reference case. The results were shown in table R5. However, the cost of deviated well will be more important than for a vertical one, and is more risky. Consequently, the economic and drilling issues need to be dealt with together to find the optimum length for the ultimate recovery factor during the production period.

Model Base Case Six production wells Deviated wells

Recover Factor 36% 38% 41.5%

Table R5: Alternative development plan comparison

2.6.

ECONOMICS

The economical key issues considered during the financial appraisal of the Z field were the processing and the disposal of the fluid streams. The development facilities of deep-water fields are limited to floaters and tie-back to a nearby platform or ashore. The presence of the Clair platform in the neighbourhood of the Z field was analyzed with the opportunity to get the Clair owner to be involved in the development as a shareholder, to avoid any sharp rise in the processing tariff rates throughout the field life. FPSO and Tension Leg Platforms were the alternatives to a tie-back solution. With the current volatility in commodity markets, we made the economic rates assumptions related to the development by scrutinizing the rates fluctuations of the 5 past years. Among the three options available, the tie-back to Clair Platform was the most attractive scenario, and has the advantage of allowing selling the gas. The economical risks associated with the Z field development were raised and studied. As a result of this study, some solutions were outlined to manage them.

2.7.

DRILLING

Semi-submersible rig (J. W. McLean) will be used to drill the new wells. The well will be controlled by 10,000 psia BOP which will come with the rig. There are no major problems expected during the drilling since that the field is normally pressurised and there are no indication of overpressure zones from previous mud logs of the appraisal wells. In the light of this, two types of bits will be used (roller cone and PDC). Seawater, WBM and HPWBM will be implemented as drilling fluids at different sections with the appropriate weight (9-10ppg) and additives. The Common North sea Class G cement will be used and two grades of casing (K-55 and L-80) will be used with different weights. Two deviated wells will be drilled using rotary steering system. The cuttings from deep sections will be converted into slurry and re-injected into one of the appraisal well.

2.8.

WELL PERFORMANCE

Summary of analysis

• Z field wells will be drilled deviated and will use a 9”5/8 casing to complete the bottom hole (along with cement and casing perforation).

• The main assumption here is to maintain the pressure above the downhole fluid bubble point.

• Well head pressure will be 250 psi.

• All the producing wells will be completed with a 5”5 tubing string which will be coated or chromium to prevent corrosion. Corrosion may happen due to the presence of CO2 and H2S.

• The well which will produce from both upper and lower sands will be completed with a dual completion string 3”1/2 and 2”7/8 tubing.

• Gas lift will be required to lift the wells when water cut increases to a level which affects the wells productivity. Gas lift requirement will be included in the completion design.

• The water injecting wells will be completed by a 7” tubing to handle the high injection rate of 10,000 bbl/day.

Uncertainty

The range of the reservoir parameters (average permeability or skin factor from wireline logs and well) was obtained for the whole reservoir. However the data available from the well testing is quite poor due to the shortage and the low quality of well tests. Because of the reservoir high heterogeneity, these values might not reflect the reality of these parameters. The productivity index used in analysis was obtained from well test surface rates and downhole pressure measurements. These values depend on the well conditions (for example we have DST for different units of the same reservoir, and not for the whole reservoir). The exact string configuration used during the DST tests could not be reproduced as accurately as in the real well tests. Therefore, to manage the uncertainties which were introduced above, sensitivity studies with varying reservoir parameters were carried out to get the best possible production rate.

2.9.

PRODUCTION FACILITIES & ISSUES

Due to the small size of our field and due to the existence of nearby process facilities which have the ability to receive our produced fluids, the development production plan (DPP) is to produce our field hydrocarbons via a subsea cluster wells tied-back to the nearest field (Clair field) which is 20 km away. Five production wells are tied-back to one cluster with a manifold which is connected through pipelines to the Clair field, as well as injection wells. Control of the wells is by hydraulic and signal umbilical from platform. Clair field topside facilities might need to be upgraded if required; such as pipeline end station, oil heating, gas

and water treating, separator and metering equipment. The development plan is designed to handle a production of 20,000 b/d and has water injection capacity of 40,000 b/d.

2.10.

FIELD DEVELOPMENT PLAN

The field is planned to be developed as following: the recovery will be made thanks to water injection from day 1 with 5 producing wells (2 from already existing appraisal wells, 2 new deviated wells and 1 new vertical) and 5 water injection wells (4 from appraisal wells and 1 new vertical). All the production and injection will be dealt with the nearby Clair field operated by BP since the tie-back solution has been chosen (in terms of economics and oil recovery). The wells will be located as showed in the following figure R6:

Figure R6: Five producers and five injectors position in the field development plan During the first phase, new producers and injectors will be successively drilled and put on operation, for an expected plateau phase of around 1600 days. In the next phase, two injection wells [INJ1 & INJ3] will be shut and one production well [P1] will be converted into injection well. In the final phase in the project, the injection well [INJ4] will be shut and P4 will be converted from producer to injector. This final phase will last for approximately

1400 days. The resulting production profiles (for an economic limit calculated at 2000 bopd) are shown in the figure R7, for different cases (high, low and most likely).

Figure R7: Expected Production profiles

2.11.

ENVIRONMENTAL CONSIDERATIONS AND FIELD

ABANDONMENT

Our environmental statement will be conducted as required by DTI, UK. Our field lies under the Transboundary jurisdiction of Germany, France, Netherlands, Belgium and Norway. Our local sensitivities are drilling discharges, produced water, cetaceans, oil spills and transboundary issues. Drilling mud and cuttings will be treated and re-injected to well 1, oil spills will be carried out by our emergency support vessel, and produced water will be treated and re-injected to the sea. Flaring will be kept to a minimum.

IOC will be leasing BP’s Claire Platform for our operation offshore, limited surface abandonment will be carried out at the end of our operations. Sub-sea wells will be abandoned by squeezing cement to the perforated regions, plugging the borehole and providing a corrosion cap over the wellhead. Our producing zones will be plugged back with cement with a minimum thickness of 100 ft above and below the formation.

3.

FIELD DESCRIPTION

The field is situated in the North Sea and its area is around 200-240 million square feet (see top structure map appendix 2). It is located offshore west of the Shetlands Islands, and is 20 km away from the Clair field operated by BP (see map in appendix 1).

3.1.

STRUCTURAL CONFIGURATION

The most useful piece of information we use to determine the geometry of the reservoir is the seismics shot. The most obvious characteristic of the reservoir is that it is

synclined, the strike line of the two limbs being in a North-West to South-East direction

(see cross section appendix 3). The syncline deformation occurred after deposition: as we can see on the seismics the layers above are synclined as well; they would be horizontal if the syncline happened before deposition. Calculation of the structure different dips is possible thanks to the top structure map (given by seismic shots too): the main dip is 2.7° from the

horizontal towards a 120° clockwise from North direction. The western limb of the syncline has a dip of 12.3° from horizontal towards NE. The eastern limb of the syncline has a dip of 10.2° from horizontal towards SW.

3.2.

GEOLOGY AND RESERVOIR DESCRIPTION

3.2.1.

Depositional Environment

The depositional environment is a critical characteristic of a reservoir because it allows us to infer the distribution of the main reservoir properties according to the geological interpretation. Because there is not one and only one interpretation, it is important to define the different scenarios so that it is possible to mitigate the uncertainty in the development phase. Several clues relative to the Z-field reservoir can be found in the available data: seismic studies, logs, core plugs tests, lithology logs, mud logs and core pictures.

Let’s describe the core photographs: We had access to the viewing of the cores for 3 wells (Z-2, Z-3 and Z-5). By looking at them, it is possible to determine the energy of the deposition: several parts of the cores are poorly-sorted and we can see pebbles (figure G1), characteristic of a high energy deposition. Furthermore, these pebbles are often at the base of a fining upwards sequence, which means that the depositional energy decreases gradually. These sequences are often separated by cemented zones (light grey-white zones, figure G1). These cemented zones will have a bad effect on the reservoir performance by altering the

vertical permeability. The cementation comes from the invasion of the rocks by calcite,

which is either precipitated (by organisms in marine environment) or initially brought by the deposition. This invasion is stopped by the oil traces present in some parts of the cores. Are these cemented zones continuous sheets or just small zones? It is quite difficult to determine only from the core samples because the samples are just a few inches diameter. One of the main characteristics we can get from the study of the cores is that it is highly heterogeneous: it is further confirmed by the mud logs, we don’t have any clean sand body; everything is a

heterogeneous mix of sand, clay and mud.

Figure G1: Core pictures (left: pebbles in sand, right : sand and cemented zone) Cemented zone

Pebbles

Fining upwards sequence

The main characteristics we get from the cores are: poorly-sorted, pebbles, high energy deposition, fining upwards sequence, high heterogeneity and cemented zones. These parameters are particular of a turbidite deposition in marine environment. We can then determine one parameter of this turbidite deposition such as the direction of the deposition thanks to the study of the mud logs and logs, which will give the thickness of the sand body:

the thicker the sand body, the closer to the origin of the deposition. We can then work out

an isochore map from these thicknesses (appendix 3). It is possible to see that the thickest part is in the middle-south part of the reservoir and the further from this zone, the thinner it gets. This gives us a major clue about the direction of the paleocurrent (indicated by the arrows on the figure). The middle-south zone is then the source of the deposition (single

point-source). It is known from the core pictures that there were several successive

depositions. The major uncertainty now is the correlation of these depositions in the wells we have: How is the turbidite channelized? How can we correlate reservoir properties throughout the reservoir?

3.2.2.

Stratigraphy

One particularity of the reservoir is that it pinches-out on the northern part, which indicates that the trap is probably stratigraphic. Furthermore, the two limbs of the syncline lead to the elevation of some parts of the sand with an unconformity on the south west part. Therefore, one key part of the trapping system can be qualified as structural as well. The general stratigraphy can be determined thanks to the available mud logs and lithology logs, correlation between the wells can then be made and the result is shown on appendix 4.

The lower unit is detectable only in the well Z-7; therefore it means that it pinches out in the east direction. However, nothing more can be inferred about this unit.

3.2.3.

Source Rock

Well test fluid analysis states that we are dealing with an Early Cretaceous type of

fluids. However, due to the lack of data, it is quite difficult to know more about the source

rock.

3.2.4.

Trap and Seal

According to the mud logs, there is a layer of Marl located directly on top of the sand. This layer of marl is present in all the wells. Therefore marl is the cap rock that seals the

stratigraphic trap, keeping the hydrocarbons from migrating further (appendix 4: general

correlation from mud logs).

3.2.5.

GEOSTATISTICAL DESCRIPTION OF CORE SAMPLES

Some core plugs taken from the wells are analyzed in a laboratory to determine rock parameters such as porosity or permeability (horizontal and vertical). The results give quite a good idea of the quality of the sand at the well location; however it doesn’t reflect the real behaviour of the reservoir because of the heterogeneity of the Z-field. It is still interesting to statistically study the repartition of the porosities and the permeabilities, in order to know more about the sand quality. Results show that the cores taken from well Z-7 (both upper: 7U and lower layer: 7L) are of quite good quality: horizontal permeability is quite high (given by the arithmetic average) but very heterogeneous; however the vertical permeability is quite low (given by the harmonic average) and heterogeneous as well. The lower layer seems to be of much better quality than the upper layer.

Geometric average Harmonic average Arithmetic average Number of samples Standard Deviation Cv 7U KH 2,31 0,09 100,13 47 174,68 1,74 7L KH 12,08 0,13 381,29 90 517,56 1,36 7U KV 0,61 1,17E-05 75,52 47 124,47 1,65 7L KV 1,40 9,00E-06 251,08 90 393,71 1,57

3.3.

PETROPHYSICS AND RESERVOIR FLUIDS

3.4.

PETROPHYSICS

Seven appraisals wells wireline data (paper Logs and electronic versions), SCAL, PVT and RFT were available for petrophysics analysis of Z field. A careful check was conducted to ensure the consistency between paper logs provided and the composite Logs available from the software, and correction was performed where discrepancies were observed. All wells were assumed vertical except well Z7 and Z1 for which deviation surveys were provided. Well Z1 was not considered for study, as there was insufficient data to carry out analysis. The set of wireline Logs available for each well are detailed in table FE1 below:

Well Log Type over Reservoir Drilling Mud

Well Z1 CGR/SGR/NPHI WBM

Well Z2

GR/PHID/SONI/CNL/LLS/ILD/LLD/MSFL/CALI/SFLU/Core

/Por/KH/KV

WBM

Well Z3 GR/CNL/DENS/LLS/LLD/MSFL/CALI /Core-Por/ KH/KV WBM

Well Z4 GR/DENS/SONI/PEF/CNL/ILM/ILD/SFLU/CALI/DRHO/Pore core/KH WBM

Well Z5

GR/DENS/SONI/CNL/ILM/ILD/CALI/DRHO/POR-HEL/POTA/URAN/THOR/KH/KV

OBM

Well Z6

GR/SGR/DT/NCNL/SCNL/FCNL/ILM/ILD/ CALI/SFLU/ Core Por/

KH/RSFL

WBM

Well Z7

SGR/DENS/SONI/PEF/CNL/MSFL/ILM/ILD

/LLD/LLS/CALI/SFLU/DRHO/CGR/TVD/CorePor/KH/KVPOTA/URAN/

THOR/

WBM

3.4.1.

CORRECTIONS FOR BOREHOLE EFFECTS

There was no information to know whether the Service Company corrected the logs for borehole and mud filtrate invasion. Therefore, we assumed they have not been corrected and did so for all the Logs. For each well, the Caliper Log was used to correct for borehole effects and in addition, resistivity Logs were corrected for mud-filtrate invasion with Tornado charts. Equally, there was no evidence of the company that performed the wireline logging service, we assumed Schlumberger though and used theirs charts for correction.

3.4.2.

RESERVOIR LITHOLOGY DESCRIPTION

Two reservoir units were identified in Well Z7, the upper and the lower reservoir units. The upper reservoir unit was highly heterogeneous. Shale identification was made using gamma ray (GR) and spectral gamma ray (SGR) curves. Equally, Neutron-density cross plots (figure P2) and the PEF Plot on the Paper composite log were also used for mineralogy identification. The Cross-plot showed an extensive concentration of calcite in the reservoir, this was due to the presence of calcite cemented sandstone in the reservoir sand. This was also confirmed by the observation of cores recovered from Well Z5 and Z3. Mud logs were also used to further consolidate the abundant presence of calcite-cemented horizons in the reservoir.

Figure P2:

3.4.3.

WELL CORRELATION

Due to the high heterogeneity of the reservoir, it was difficult to distinguish layering in the reservoir with GR Logs. In order to make the correlation across the field, DST interpretation, from well test analysis, was used to improve more information about the connectivity. In addition, by pressure survey data, the upper sand was correlated across the whole field (see appendix 5).

3.4.4.

WATER RESISTIVITY

Water resistivity Rw used to compute Sw was determined from water analysis carried

out on twenty-six samples collected in well Z-5. The analysis reported a minor contamination of samples. We determined an average of representatives values of the water resistivity and the result was as follows: Rw= 0.052 @ 175°F.

3.4.5.

POROSITY MODEL

Density log was available for five of the wells analyzed, and was used for porosity computation as the neutron porosity showed higher apparent porosity due to dispersed shale present in the reservoir sand. Equally, core porosity and neutron porosity were similar as both indicate the total porosity. Core porosity was based on core oven-dried helium porosities and was therefore very close to "total porosity”. Shale corrections were applied to density logs to determine effective porosity.

3.4.6.

DETERMINATION OF S

As we have shaly sands in some part of the reservoir, we have used the Simandoux Method for water saturation computation. This method includes a shale correction for the saturation calculation. Values used across the field for the tortuosity, cementation and saturation exponent were a=1, m=1.78, n=2.06, they were derived from SCAL data of well

Z5. The true resistivity used in Simandoux method for each well was the deep resistivity corrected for borehole and mud filtrate invasion. Density porosity was used for all the wells except for Well 2 where sonic porosity was used since density porosity was not available. A comparative study with SCAL showed a match.

3.4.7.

PERMEABILITY LOG

A linear regression relationship (Appendix 6a) between core porosity and core permeabilities was determined; this was then used to indirectly compute vertical and horizontal permeability from density porosity Log for each well. The permeability deteriorated towards the eastern side of the field. A comparison between the permeability obtained from logs and well testing showed discrepancies, with the permeability obtained from well test being lower. This was probably due to the large scale of heterogeneity in our reservoir caused by the presence of shale and cemented zones within the reservoir. In addition, the well test permeability is the effective permeability measured at the reservoir prevailing saturation while the core permeability is the absolute one.

3.4.8.

MOVEABLE HYDROCARBONS

A study of the reservoir permeability around the wellbore zone was carried out by computing the moveable hydrocarbon. As result in well Z5, the mud filtrate substituted almost half of the original fluid in place in the reservoir zone, showing the permeability of the reservoir (see appendix 6b).

3.4.9.

NET-TO-GROSS

A net pay analysis was conducted for all of the wells. We assumed a mobility ratio threshold of 0.7mD/cp to determine the permeability cut off criteria. Linear regression relationship between the logarithm of the permeability and Φ, VSh and Sw respectively were

used to determine the threshold values of each parameter (appendix 7). The base Cut off criteria used was as follows: Vshale > 0.4, Porosity >0.1, Sw < 0.5, Kh>1mD.

3.4.10.

FLUIDS-BEARING ZONES

The LRU and the URU were identified as oil-bearing, with no gas cap throughout all the six wells analyzed. Resistivity Logs, neutron and density logs were used to identify reservoir fluids type. Core saturations were employed to confirm log results. An aquifer was also identified in Well 5 with the OWC at 8892ft. No aquifer was observed below the oil zone in well Z2 and in the upper Reservoir of well 7.

The table appendix 8 summarizes the properties of the upper sand reservoir obtained for each well.

3.5.

RESERVOIR FLUIDS

3.5.1.

PVT Analysis

Surface and subsurface fluid samples were collected from well 1, 3, 5, and 7 by FIT (Formation interval test) and conventional DST. The PVT analysis and gas chromatography were carried out to analyse fluid properties and hydrocarbon composition.

In terms of PVT analysis, separator, flash vaporization and differential tests were carried out to obtain the fluid properties including Bo, Rs and Pb from above to below bubble

point. The samples, both surface and bottom hole, were analysed in various stages of separator (from 60-150 F and 0-200 psig). Furthermore, fluid viscosity was measured by rolling ball viscometer at various ranges of temperature and pressure. As demonstrated in

appendix 9, the reservoir fluid seemed to be a light oil with API higher than 31.5 and low GOR. The oil properties in the Z-field are characterised as a highly undersaturated oil with a bubble point around 1050-1120 psia. In addition, the properties of fluid in upper and lower reservoir appeared to have no significant difference. They were considered uniform for the

entire field. Thus, these results indicated that it will be possible to produce as commingled fluids from the two zones.

Regarding the reservoir fluid composition, the selected separator gas sample was determined by gas chromatography until detectable limit. Moreover, the separator liquid was determined by both low and high temperature fractional distillation.As shown in table R7,the result showed a very low amount of hydrogen sulphide, containing in both upper and lower reservoir fluid with around 2% carbon dioxide.

Components Upper reservoir Lower reservoir

Mole Percent Mole Percent

Nitrogen 1.32 1.43 Carbon Dioxide 0.36 0.76 Hydrogen Sulphide 0.00* 0.00 Hydrocarbons METHANE 15.50 15.89 ETHANE 4.92 5.20 PROPANE 8.68 10.03 ISO-BUTANE 1.00 1.32 N-BUTANE 3.61 5.77 ISO-PENTANE 1.19 2.08 N-PENTANE 1.95 3.30 N-HEXANE 3.59 4.59 Heptanes plus** 57.88 49.63 TOTAL 100.00 100.00 * Less than 1ppm ** Molecular weight of C7+ = 243

Table R7: Hydrocarbon Analysis of Reservoir Fluid Sample

3.5.2.

Water Analysis

In terms of water analysis, Produced water was analysed by collecting 26 samples during the reverse circulation of well Z-5 in DST-1. Three of these samples, which consist almost entirely of formation water, were tested by API analysis. As a result of this test, it is evident that these samples were contaminated by sea water by 12%vol. The results of produced water analysis are shown in table R8.

Water( well 5) 8896-8926 ft

Sample1 Sample2 Sample3

ppm solid 74750 76640 77010

specific gravity at 60/60F 1.051 1.052 1.052

Resistivity 0.129 0.127 0.127

pH 7.22 7.5 7.24

Hydrogen Sulphide None None None

Table R8: Produced water analysis

Furthermore, oil and water were recovered at 8930 ft by a 1 gall FMT tool. Subsequently, an API analysis and ‘finger print analysis’ were performed to analyze oil and water. As a consequence of these tests, the formation water seems to be contaminated formation water. In addition, from the chromatogram, the oil consists almost entirely of oil base mud filtrate.

Based on the summary table, corrosion may happen due to the high water salinity and high concentrated solid. The corrosion inhibitor will be used and injected into the well if necessary. Moreover, the corrosion monitoring log should be run to examine the tubing damage from corrosion.

3.6.

HYDROCARBONS IN PLACE

3.6.1.

Uncertainties Associated with HCIIP Determination

As depicted in figure R9 and figure R10, the tables show the HCIIP which were calculated by the volumetric estimation and material balance calculation. Based on the geometry, the input parameters were obtained from petro-physical data, core, and PVT analysis. Whereas the MB equation can calculate the initial oil in place by using data from EWT or extended well testing (see appendix 10). The high and low STOIIP cases for both geometry and material balance were simulated by Monte Carlo method to account for the parameters uncertainty. By using the Crystal Ball software, the parameters distributions were assumed as being normal and triangular distribution (see appendix 10). The results have been

demonstrated in the probabilistic range with P10, P50, and P90. After that the STOIIP with P50 was used as the representative base case to construct the reservoir model.

An Estimation of the Z Field STOIIP with volumetric method was obtained using the Monte Carlo Simulation. The input parameters for the simulation were derived from petrophysical and PVT analysis. Each of the parameters was modeled using an appropriate probability distribution function to account for the associated uncertainty. The results are shown in figure R9 and a distribution of the cumulative probabilities and sensitivities are shown in Figure R9a and Figure R9b respectively.

Figure R9a: STOIIP Cumulative distribution function Figure R9b: Sensitivity analysis of individual parameters

Figure R9 and Figure R10: STOIIP calculation from the volumetric estimates of HCIIP and Material balance

Regarding the results, the STOIIP calculations from Material Balance and geometry have no significant difference. By integrating the MB equation and geometry, the correct STOIIP ranges can be confirmed, leading to a reduced risk of uncertainty.

STOIIP calculation

From Reservoir geometry:

P

=

196 million STB

P

=

157 million STB

P

=

124 million STB

STOIIP calculation

From Material Balance:

(Based on no water influx)

P

=

200 million STB

P

=

152 million STB

3.7.

WELL PERFORMANCE

3.7.1.

APPRAISAL WELL TESTING

Extended Production test

A one-year production test in well Z-1 was conducted to get a good indication of STOIIP by using material balance. As demonstrated in figure R11, the oil has been produced for 1 year with a cumulative production of 751,000 barrels and followed by a long period of shut in. As a result of this test, the pressure depleted around 213 psi from the initial reservoir with PI around 2.89. At the beginning of this test, the bottom hole pressure dropped rapidly by 286 psi in 21 days at the early stage of test. Moreover, the reservoir pressure didn’t stabilize to the initial reservoir pressure level (3713 psi), even if it has a long time shut in period (3 months). Therefore, the drive mechanism of this field seems to be depletion with no aquifer support or very small support in this field.

Furthermore, the OIIP which was calculated by material balance is around 120-200 mSTB. This result is based on the fact that there is no water influx in the reservoir (see

appendix 10). The oil volume by MB equation shows a good consistency with the STOIIP which was obtained from the volumetric calculation. Based on these results, it can be concluded that this reservoir has no large fault to block the pressure disturbance in reservoir.

Figure R11: The extended well test data

Drill Stem Test

DST has been conducted in well 2, 3, 5, and 7. The main results are shown in

appendix 11. It shows a wide range of productivity index from the different areas of reservoir. Based on this summary table, the high PI zone is situated in the West area (Z-7) with productivity index from 5-7 (appendix 12). This result shows a good consistency with the geological study and the core analysis which indicated the high quality sand with high permeability and porosity in this area. In addition, the no flow boundaries were suspected around well Z-7 from build-up analysis in Pansystem software (see appendix 13). The fault distance from the well test analysis is reasonably close to the big fault (unconformity boundaries) which is situated in the Western area of the field.

However, the DST testing time from the other wells seemed to be very short period (25-70 hrs.), resulting in no late time region observed in log-log derivative plot analysis. Therefore, the well test analysis can only define the effective permeability, skin and average reservoir pressure by semi-log plot in Build-up analysis (demonstrated in appendix 11). In addition, the average pressure from the build up analysis is not really different from the initial

pressure from the production test except for well Z-7. This is because the DST in well Z-7 was conducted after the pressure depletion from production test in well Z-1. Regarding this result, it would be believed that the reservoir has a connection between these two areas. Furthermore, by comparing with the static data from core analysis, the permeability which is obtained from core analysis and well test appeared to be really different in well Z-7 (appendix 14) due to the high heterogeneity in the reservoir. However, this result supports the assumption that the high permeability zone is situated in the West of the field around well Z-7 area.

Well test analysis of the Lower reservoir

Well test analysis from well Z-7 (west of the field) and log analysis indicated that there is the another reservoir situated below at 10260-10400 ft (MD). From the DST analysis, it seemed to be faults or no flow boundary situated in U-shaped around well Z-7. This well has been test by DST and clearly showed the clean sand with higher permeability and porosity than the upper reservoir.

Moreover, the radius of investigation calculated from the lower reservoir is around 900 ft. However, the volume of oil in place could not be identified by neither well testing nor geological structure map because of the lack of data. Regarding the above reason, it appeared difficult to include the lower reservoir in the simulation model and it will be treated as the uncertainty. Therefore, it has been suggested that the well test should be conducted in this area (Z-7) to confirm the reservoir drainage area before development or drill more wells to gain the information from this reservoir: from the reservoir fluid analysis point of view, it is showed that it would be possible to produce fluids from two zones at the same time as commingled.

3.7.2.

Well flowing design

3.7.2.1.

WellFlo Analysis

By using the WellFlo software, a good understanding of the relationship between the inflow and outflow performance has been achieved, as well as the reservoir, the completion and the well head conditions. Well flow behaviour simulation and performance of the Z field have been done by using the WellFlo software and by modelling the outflow and inflow of the appraisal wells.

The data collected from DST, cores, composite logs and fluid properties from wells Z-2, Z-3, Z-5, and Z-7 were used to build a base model with a PI reflecting the field characteristics. Getting the best match results with actual data was obtained from DST results. The base model is then used to run different reservoir possible conditions (sensitivity studies).

3.7.2.1.1.

Methodology

The WellFlo base-model was built by using the data available and with the reconstruction of the DST string which was used for the testing of well Z-3. The further input of the reservoir data is then used to tune the model and to make it match the actual well test data. This base-case model is then studied with the modification of various parameters (sensitivities) under different reservoir conditions. According to this study, it will be possible to determine the behaviour and performance of new drilled wells anywhere in the reservoir and under any conditions. The completion string can then be optimized, as well as the configuration design and downhole completion (including perforations density, phase and angle deviation, wellhead pressure and facilities options). In a later phase of the field life, the lifting capacity will decrease along with well production due to the water cut increase; flowing the well will therefore require artificial lift. Thanks to its availability, gas lifting will be used rather than ESPs (as explained in the artificial lift section below).

The correlation which gives the best match results of the outflow from the base model is Haggedorn and Brown. The model is then tuned thanks to the modification of the L-factor, to more precisely match the flow obtained from the well test (as shown in appendix15 and 16).

3.7.2.1.2.

Sensitivities

3.7.2.1.2.1 Well head Pressure

By taking into account separator requirements, the optimum well head pressure is 250 psi. Figure P1 and appendix 17 below show the well head pressure sensitivity.

well head sensitivity

0 500 1000 1500 2000 2500 3000 3500 150 200 250 300 350 400 450

well head pressure psi

fl o w r a te S T B /d a y

Figure P1: well head sensitivity

3.7.2.1.2.2 Well flow design

A generic model for the upper sand was developed with a reservoir thickness of 140ft. It was assumed that wells will be drilled with zero formation damage thanks to the penetration

Upper

sand Average PI , STB/D/PSI 7

Bo bbl/STB 1.2

Average layer pressure 3775 Average permeability, k md 130

Bubble point, psi 1100

Well radius, ft .6

Average thickness, ft 140

depth of perforations which should be enough to bypass the damaged zone. Furthermore, reservoir pressure will be maintained above bubble point. Sensitivities were then generated for various conditions: different tubing sizes, different deviation angles and different perforations densities with various phases and penetration depths.

3.7.2.1.2.3 Perforations dimensions

As it is shown in the appendices 18, 19, 20, the best perforations density is 4 shots/ft with a phase of 90 degrees. The penetration is 50 inches.

3.7.2.1.2.4 Tubing size

From WellFlow we can find that the highest production can be obtained from the 5.5” and 5” diameter tubing as shown in the figure P2 and appendices 21. It is interesting to note that 5.5” is the most common and used tubing diameter in the North Sea area.

Tubing size sensitivity

0 500 1000 1500 2000 2500 3000 3500 4000 1.99 2.5 3.5 2.9 4.044 4.89

Tubing inside diameter" inche"

fl o w r ra te S T B /d a y

3.7.2.1.2.5 Deviation

As it is shown in the figure P3 and appendix 22, the maximum production can be achieved with an inclination up to 75°. This inclination will give the best flow rates. However the well deviation will be limited by the dip of the reservoir layers and by the length of the deviated bath in the reservoir. Drilling the wells with a 60° inclination gives adequate flow and also simplifies wireline logging and operations.

Deviation sensitivity

deviation angle "dgree"

fl o w r a te S T B /d a y

Figure P3: Deviation angle sensitivity

3.7.2.1.2.6 Layer Pressure and Water Cut Variation

A 5.5” diameter tubing size and a 60° inclination will now be assumed. The table below shows the prediction of the well performance under different pressures and the maximum water cut which can be handled under these conditions. As we can see, if it is assumed that the pressure will be maintained by pressure support both by water injection and rock compressibility, the well will continue to flow at different water cuts as shown in table P4 (and appendix 23) below. The economic rate is 500 STB/day with a water cut of 80%.

Layer Pressure (psia) Water Cut (%) 3700 3600 3500 3400 3300 3200 3100 3000 0 4332 3947 3556 3156 2748 2331 1826 1031 10 3857 3486 3108 2718 2318 1907 1299 112 20 3371 3015 2650 2274 1887 1425 720 0 30 2886 2548 2202 1849 1488 957 0 0 40 2417 2101 1773 1436 1039 434 0 0 50 1947 1655 1351 1033 1033 0 0 0 60 1489 1227 954 636 600 0 0 0 70 1053 829 592 303 205 0 0 0 80 646 474 285 73 0 0 0 0 90 286 188 81 0 0 0 0 0

Table P4: Layer pressure vs Water cut

3.7.2.1.3.

Artificial Lift Selection & Design

Due to the increase of water cut, natural reservoir energy will not be enough at some point to lift the fluid to the surface and then to the surface facilities, in this case artificial lift is needed according to location and reservoir parameters (such as pressure, oil °API or GOR). It will be suitable to consider the gas lift as the method of artificial lift rather than ESP (electrical submersible pumps). Considering the fact that the field economic water cut is 65 %, artificial lift will be needed to enhance production at 40% water cut. Appendix 24 shows gas lift design characteristics and operating conditions to produce liquid. For a liquid production of 8293 bbl (4119 bbl /day of oil), a gas injection rate of 3mmscf/day is needed as shown in appendix 25 and 26. Economic production rate water cut is then increased to 90% at 500 STB/day. And two dummy valves are to be installed and other accessories as contingency plan when needed.

3.7.3.

Wellbore Completion

As a result of drilling operations the casing of 9”5/8 will be set at TD, cemented and perforated with a casing gun that will allow the selection of the flow zones (and avoid water

zones when needed). The perforation penetration depth should be more than 50 inches with a phase of 90 degrees to get the best performance as mentioned above. The completion schematics are shown in appendix 27 and 28 for the wells which produce from the upper sand and the wells which will produce from the two layers of sand (upper and lower sand as present in well Z-7).

3.8.

PRODUCTION ISSUES

3.8.1.

Scaling Corrosion

The formation water has a high concentration of sodium ions and chloride cations according to the samples of water extracted from the separator to identify scaling issues. According to the chemical composition of formation water the type of scales anticipated are calcium sulphates and barium sulphates. Furthermore, incompatibility between formation water and injection sea water can be a source of scale creation. The table P5 below shows the dissolved solids in the formation water. Scale Inhibitors should be injected when required to prevent the scales from building up in the tubing and the production facilities so we can avoid any tubing plug or flow restriction.

CATIONS ANIONS

Sodium 36.6 Chloride 59.6

Potassium 0.38 Sulphate 0.16 Calcium 1.2 Bicarbonate 1.26 Magnesium 0.38 Carbonate NIL Barium 0.011 Hydroxide NIL Strontium 0.29 Total iron 0.027 Total dissolved solids (Mg/L) 76640 Dissolved iron 0.000013 PH 7.5