Oil, Gas and Water Production Forecast & Water Management

1. Oil, Gas and Water Production Forecast& Water Management Anup Bora

2. Presentation Outlines Introduction Production Forecasting challenges Different forecasting tools & Process AAP production forecast & methodology Summary of Forecasting KOC’s water production scenario Current initiatives Future Challenges Conclusions

3. Introduction • We address the following Questions while starting a project: • Technical Questions • Economic Questions • Technical Questions? • Is the reservoir productive at commercial rate? • How sure are we that it is productive? • How big is the reservoir? • What is the rate of recovery and how long will it last? • What recovery mechanism is anticipated? • Will ultimate recovery be defined by volumetric or performance? • Economic Questions? • Can the product be delivered to the market? • What sale price will be received for the product? • What will be needed to develop the reserves, and how much will it cost? • How much will it costs to operate the wells and facilities?

4. Production Forecast Process Credible Forecasts are required in all phases of EP lifecycle • Exploration: before the field is discovered • Volumetric estimate • Conceptual development plan • High level models • Appraisals: Forecasts are refined as new data become available • Justify further appraisals • Testing • Demonstrate sufficient economic robustness to mature a development concept • Development:development scenarios to determine optimal development strategy • Concept Selection • Well Planning • Investment economics • Produce: Forecasts are produced with several time horizons and objectives to optimize Asset Management and to review and improve field development • Abandonment/ Divestment: a best estimate of remaining production potentials

5. Forecasting challenges • Optimistic forecasts (oil overestimated) will lead to: • Under delivery against business targets not utilizing installed capacities • Loss of credibility and shareholder confidence • Continuous barrel chasing Contractual implications • It may impact reservoir health • Pessimistic forecasts (oil/water/gas underestimated) will lead to: • Suboptimal field developments with high constraints due to under design • Missed opportunities (projects ranked out, undervaluing assets). • Debottlenecking of existing facilities • Expansion projects needed earlier than planned => The goal is to provide a P50/mid case forecast that is realistic and achievable

6. Production Forecast - Uncertainties • Reservoir Consistency/Continuity • Drive mechanism • Water/ gas break through • Damage/damage removal • reservoir pressure profile • Impact and timing of development • Mechanical Integrity • Fluid composition • Metering accuracy • Vertical lift • IOR impact • Market • Weather

7. Hierarchy of forecasting methods When to use what methodology? (preferred method on top of each column)

8. When to use what Methodology • But: Do not exclude tools for any maturity level. Here “maturity” refers to the number of years a field has produced, the amount and quality of recorded data and the number of wells. However, given a certain maturity level of a field, some tools make more sense to use than others.

9. Oil Carbonate Reservoirs Analogues and Benchmark based forecasting Recovery average: 36% • Use of analogs (Lack of data) • Analogues can assist in estimating well productivity and ultimate recovery for reservoirs with limited data (exploration, appraisal). • Analogous reservoirs have to be similar in rock and fluid properties, reservoir conditions (depth, temperature, pressure), drive mechanism, development scheme and reservoir management strategy, but are typically at a more advanced stage of development than the reservoir of interest. • The link between properties and outcomes can be used to assess the performance and behavior of the asset under exploration/appraisal to identify those factors which control reservoir responses. • Benchmarking (used for validation) • Benchmarking of forecast against historical production performance (new wells, water injection efficiency, injection rates) is a common sense check. If your prediction differs from your historical performance find out why before accepting it. • Benchmarking is critical to validate assumptions on forecast parameters like water cut, uptime, deferment, project schedule, drilling time.

10. Performance based DCA forecasting Decline Curve Analysis (DCA) is a basic method to extrapolate historical production into the future. It requires the following: • Only Production data from a historical period with constant operating parameters can be extrapolated. • Decline parameters need to be assessed based on the current production mechanism like depletion or WF (exponential, hyperbolic). • DCA should start at the lowest level (completion, well) and then be aggregated to pattern, reservoir and field level. • Be aware that DCA doesn’t cover well interference, working with vintages of well groups is the proxy to use. • OFM is one of the standard tools implemented in KOC as base production analysis tool and the DCA functionality is available for well prediction and performance analysis (plan vs actual production).

11. 3D simulation model forecasting • Where interference is occurring dynamic simulations has been proven as an excellent tool, but: • Before deciding for a simulation model there should be clarity on the decision the modelling is supporting. Early screening against simpler models (analogues, DCA or analytical modelling like MBAL & Buckley Leverett) is required as the time and resources for 3D simulation can be extensive. • The effort between the different scales of dynamic models (1D/2D/3D, PVT, structural complexity) is variable and should therefore be wisely picked. • Sufficient well and production/pressure data have to be available before it is worth going for a 3D static and dynamic model. • Incorporating uncertainties in the modelling work allows to generate a range of probabilistic forecasts for P90/P50/P10 profiles. P50 forecast evaluation and outcome spread from same HM

12. Activity & Development forecasting • Activity forecasting (Short Term): • Evaluating production gains from workover and infill drilling activities drives the monthly activity planning to deliver the monthly reference forecast. • This forecasting is mainly performance and benchmark based but needs to incorporate incremental evaluation including subsurface (interference) and surface (network backpressure) effects. • Development forecast (Long Term, life-cycle): • The long tern (life cycle) forecast covers the AAP planning and reserves within the annual planning cycle. • It requires integrated development planning on top of the NFA (BM) to deliver the incremental development scenario optimization. • The NKCOF team has piloted the use of PetroVR to generate the AAP forecast as it allows not only the effective aggregation of individual reservoir profiles but also incorporates surface constraints into the resulting forecast. • In addition PetroVR can generate alternative scenarios based on modified assumptions like surface project delivery or reconfiguration of the IAP to display different cases to assess the realism in the mid case forecast.

13. Realistic Forecasting Initial Forecast • Most Common forecast deviations • The key factors leading to gaps between forecast and actual performance are: • Unrealistic activity schedules • Lower than expected surface equipment operational efficiency • Reservoir model simplifications • Inaccuracy of historicaldata • Therefore Forecasts should always be benchmarked against available field performance data to ensure that production forecasts are realistic (like new well rates, GOR, water cut -> expected vs actual).

14. Production Data & DCA forecasting(Example from KOC Reservoir)

15. DCA forecasting All plots should point to same answer for best results

16. DCA forecasting- Example • The DCA can be forecasted well into the future until a technical limit is achieved. • Technical limits could include any of the following: • Field or well water-oil ratio limits • Water cut percentage • A minimum field rate limit • Individual well minimum rate limit • Maximum GOR cut-off • Understanding and documenting what the technical limit is, or why the forecasts end at a certain time, is essential for future analysis.

17. WOR Vs Cumulative Oil (NP)

18. Production Forecast Principles • Business Guidelines / Asset Action Plan provide classification for production profiles

19. Reserve Alignment with AAP profiles

20. Production Forecast Principles---Contd. Classifications of Production profile in Business Guidelines

21. AAP Workflow - The Big Picture • OOIP and Remaining Oil • PFT – GC Short/Long Term Forecast (no Dev.) • Field Development Programs • FFM Cum Oil vs. Watercut and ESP requirement • GC Historical Production (Oil rates and cums, water cut, GOR – daily and monthly, HP/LP) • Field and GC Facility Limits and Maintenance Down Time • GCs’ Current Month or Year potentials • Infill Drilling and Workover Programs • Field and GC Production SEK Long Term Forecast • Detail Development Programs • Field Drilling Requirements • ESP Power Consumption • GC HP/LP Gas • GC/EWDP/Field Water Handling and Dispatch Facility Sizing/Timing

22. Long Term Forecasting – AAP (WK)

23. WK Production Forecast Evaluation Criteria • Depletion plan • Well pattern, primary, • Secondary • EOR

24. Reason Behind the Discrepancy Between Forecast and Reality Well Losses Mechanical/safety reasons e.g. scale, sand, corrosion, ESP Failures, cross-flowing or lazy wells. Wells taken out for testing, logging, reservoir management or awaiting completion/tie-back. Plant Losses Mechanical/safety reasons e.g. scale, power failure, Corrosion, telecommunications. Working equipment taken off line due to shutdowns, maintenance, metering or tuning operations Export Losses Contractual restrictions, third party shutdowns Environmental restrictions e.g. flaring.

25. Technical Assurance Review (TAR) of AAP Forecast Reserves Management Team has been entrusted to carryout TAR of AAP forecast and underlying field development plans, with an objectives- • Assurance for meeting AAP Production Targets • Provide assurance on maximizing Ultimate Recovery in cost effective approach alongside prolonging the Health of the Reservoirs • Flag issues on uncertainties /risks in FDPs and request Asset FD team to develop necessary remedial actions TAR Process

26. Five Steps of forecasting

27. Summary of Forecasting • Forecasting methodologies are selected based on maturity (data availability) to pick the fit-for-purposeapproach • Forecasting methodology should be selected based on the business decision the forecast is supporting. • Applicable forecasting tools are analogs and benchmarking, analytical tools, performance based evaluation as well as simple->complex numerical simulation. • Activity and development forecasting needs to be done on an incremental base to incorporate interference and surface constraints as well as realistic project volumes. • Scenariosaround the P50/mid case are required to assess that the forecast has the same up than down side and is a realistic forecast. • Remember: Tools are only as good as the user understands the outcome. Use you common sense to test your forecast!

28. Forecasting minimum requirements Each company shall have: • Embedded and auditable process in place for generating and managing Production Forecasts, covering short term to end of field life, as basis for effective asset management. • Compare actual performance against the forecasted (including the key assumptions) on a regular basis- at least quarterly. • Clear single point accountability and responsibility for the quality of the Production forecast for each major assets, including the quality of the input data. • The base case Production forecasts shall be the estimate / P50 and fully auditable. • Main threats and opportunities to the best estimate forecast shall be identified, and the resulting uncertainty shall be quantified as ‘high/P10’ and ‘low/P90’ case production forecasts and shall be documented and demonstrably managed in a risk register.

29. Forecasting minimum requirements Each company shall have: • Any management adjustment to the / P50 production forecast (upward or downward) to arrive at the production targets shall be fully transparent and documented. • Production forecasts shall quantify all fluids (liquid and gases) produced and injected in a consistent manner and shall be consistent with the appropriate resource volume category. • Production forecasts shall honour all constraints imposed by surface facilities, pipelines and wells and shall be consistent with all the activities included and budgeted for in the Operating Plan.

30. Water Management

31. Water Management Strategy Produced Water Management is key for increasing oil production and maximizing its recoverable reserves. A holistic approach for water management consists of Maximization of oil recovery by optimized use of produced water Maximize well productivity Conserve reservoir energy Use of appropriate technology Treatment of water Subsurface Control of produced water Ensure protection of environment Periodic review and update water management strategy Maximize Profit

32. What is Produced Water? It is a mixture of injected water, formation water, dissolved hydrocarbons and treating chemicals. Oilfields are responsible for more than 60% of daily produced water generated worldwide. The rate of produced water production is expected to increase as oilfield ages.

33. Physical and Chemical properties of produced water The major constituents of interest in produced water are: Salt content: Salt content can be expressed as salinity, total dissolved solids, or electrical conductivity. Oil and grease: Many types of organic chemicals that collectively lend an “oily” property to the water. Various inorganic and organic chemicals: These chemicals are found naturally in the formation and the chemical additives used during drilling and operation of the well. Naturally occurring radioactive material (NORM): Low levels of the radioactivity can be transferred into produced water

34. Water Handling Challenges Mature oil fields will require enhanced development activities Produced water properties and volume can even vary throughout the lifetime of a reservoir. Handling of fresh aquifer water, formation water, sea water and low saline water for injection purposes. Compatibility of the water with formation. Steam flooding for tertiary recovery will generate additional volumes of water. Environmental regulations. Oil and gas companies must view water as a strategic component of their value chain.

35. Key elements of water management in KOC Water Production Forecast (reservoir subsurface) Production/Disposal and Injection wells Power requirements (MEW) Flow lines/Surface facilities GC’s for separation of oil, gas and water Effluent water disposal system Water Injection system Effluent water injection

36. Key issues for Water Management in KOC Accurate prediction of future water production profiles. Technology for separation of oil and water. Handling more volumes of water efficiently To decrease water handling costs (integration of various facilities across the fields/asset/company) Increase productivity (controlled water production) Increase recoverable reserves (EOR processes) Enhanced Water Injection requirements Low salinity water injection Water disposal plans to meet regulatory requirements. Recycle and reuse of produced water

37. KOC’s current initiatives Enhanced water injection plans to provide pressure support and improved sweep efficiency. A number of Water injection project planned/implemented across all the assets (Wara in SEK and other reservoirs in NK and WK). Increased volumes of water disposal in Shuaiba formation in Kuwait (it can handle poor quality water also due to its fractures and vuggy nature) Other aquifers for disposal are Tayarat and Rhaduma Water handling capacity plan to be enhanced for all areas. Artificial lift method like ESP to handle more volumes of liquids.

38. KOC’s current initiatives Enhanced water injection in NK area with sea water phase II project. EOR plans are drawn up for maximize recovery from its reservoirs. Cyclic steam process already implemented for HO reservoirs. Expecting more volumes of water after completion of the project. The strategy to produce the reservoir with horizontal wells to reduce water production (already implemented in NK assets).

39. Conclusions An integrated water management approach is being adopted to optimized the utilization and disposal of produced water. This will help in cost reduction and better management of the reservoir. KOC is entering into a new strategy for oil production with combination of enhanced oil production using Water Injection, EOR and New Technology. Optimize water utilization plan will maximize oil production and better utilization of produced water in KOC. This will lead to good economic performance and better management of the environment.

40. Thank You