I.P.A. Luncheon Talk. 6 th May, 2008

Transcription

1 Coalbed Methane in Indonesia I.P.A. Luncheon Talk Peter Cockcroft 6 th May, 2008

2 What is CBM? Technology CBM Reserves determination Comparison with natural gas development Monetizing CBM Where is CBM produced? Indonesia Building blocks for an efficient CBM industry 2

3 The Development of Unconventional Gas Resources from Coal The production of methane from coal seams broadly falls into three project types: coal bed methane, coal mine methane and enhanced coal bed methane. Each project type presents different opportunities i and issues to those involved 3

4 COAL BED METHANE (CBM) CBM is also known as coal seam gas (CSG) or coal seam natural gas (CSNG). These names are used interchangeably, but all refer to projects where coal is dewatered resulting in the production of gas at the surface. In these projects, once the gas ceases to be produced d then the development is usually abandoned d i.e. the coal is not produced. 4

5 Typical CBM Development 5

6 COAL MINE METHANE (CMM) CMM projects are performed prior to (or during) the production of coal reserves. This is often done as a safety precaution as the build up of methane is a safety hazard. The methane that is produced is often used on site for power generation, but can also be sold into the gas market. 6

7 Typical CMM Development 7

8 ENHANCED CBM (ECBM) Coal has double the affinity i to adsorb carbon dioxide id as it does for methane. This means that two molecules of carbon dioxide can displace one molecule of methane. ECBM provides an alternative mechanism for the production of methane. In this case instead of dewatering the coal, carbon dioxide is injected directly into the seam causing the displacement of methane. There are two benefits of doing this: The lead time before the production of economic flows of methane is significantly reduced. As dewatering can take up to two years prior to economic flow rates. Carbon dioxide can be sequestered and therefore carbon credits can be generated and then traded. Also, in countries such as Norway where carbon dioxide taxes exist, sequestration can be a tax mitigation tool. ECBM is still at the pilot stage of development, but it is seen as potentially important carbon sequestration methodology. 8

9 Typical ECBM Development 9

10 CBM- Overview 10 The process of extracting methane from coal seams and naturally fractured stacked thin coaliferous beds has gathered pace in Asia. A broad range of experience is evident with: well established Australian developments, emerging Chinese and Indian expansions, fledgling Indonesian licensing, and exploration potential ti being realised in many other regional states. Methane to Pipeline Gas Desorbed from Coal Water Produced water Reduced Water Pressure Submersible Pump Methane is contained in solution and on cleat surfaces within the coal bed and held in place by hydraulic pressure. Lowering of the hydraulic pressure by withdrawal of water from wells completed in the coal bed allows the methane to be released and recovered N O N - C O A L C O A L

11 In a conventional oil or gas reservoir, production is from oil or gas located above a water contact. t CBM production is different. Water completely permeates coal beds, and its pressure causes the methane to be adsorbed bd onto the grain surfaces of the coal. To produce CBM, the water must be drawn off first, lowering the pressure so that the methane will desorb from the coal and then flow to the well bore. CBM production is attractive due to several geological factors. Coal stores six or seven times as much gas as a conventional natural gas reservoir of equal rock volume due to the large internal surface area of coal. 11

12 Coalification Process 12

13 Coal cleat and fracture network 13

14 Characteristics of Coal Suitable for CBM Production 1. High gas content: 15m 3-30m 3 per tonne is typical. 2. Good permeability: 30mD - 50mD is typical. 3. Shallow: Coal seams < 1,000m in depth. The pressure at greater depths is often too high to allow gas flow even when the seam has been completely dewatered. This is because the high pressure causes the cleat structure to close, reducing permeability. 4. Coal rank: Most CBM projects produce gas from Bituminous coals, but it can be possible to access gas in Anthracite. 14

15 CBM Technology Drilling Hydraulic Fracturing Well Completion 15

16 Drilling 16

17 Horizontal Drilling 17

18 Slant Drilling for Surface to In-Seam Wells 18

19 Hydraulic Fracturing Hydraulic fracturing (more commonly known as fracing ) is the technique used to increase the surface area of the coal. The fluid systems and additives used in conventional wells are generally not suitable for CBM wells. This is because coal seam reservoirs have unique properties and therefore specially developed materials need to be used. 19

20 WELL COMPLETION 20 org/

21 21

22 In-field Gas Gathering 22

23 CBM Schematic Production Profile Rate & scfd) (bwpd & Time (years) 23

24 Variation in Productivity 24 Source: SPE JPT Feb 2008

25 Reserves and Resources It is amazing how these terms are still misunderstood! 25

26 SPE Reserves and Resources The adoption of unconventional hydrocarbons within the March 2007 PRMS guidelines is a timely reminder to the regional CBM industry that a more systematic approach is required to address the uncertainty in volumes and forecasts and in assessing the project commerciality and risks This much needed d (?) wake up call will aid the integration of regional CBM within overall resource assessments Petroleum_Resources_Management_System_2007.pdf t t

27 CBM- Overview Guidance can be gleaned from the major producers and resource evaluators of Canada, the United States of America, and Australia. Expansion of North American guidelines is underway, aiming to address the pitfalls of estimating the value of reserves and resources. Technology transfer through SPE and SPEE meetings will provide the Asian region with an excellent template to fast-track resource definition and development, including advice on what-not-to-do! 27 (100 pages)

28 CBM- Uncertainties Uncertainties lie in all aspects of the assessment of CBM No different to conventional hydrocarbons Relate to the components of the volumetric equation used for CBM, and its application in business decision making: GIP = A * h * ntg * φ * (1 Sw) free Bgi GIP = A * h * (1 a% wc%) * ρc * Gc CBM daf daf Only 6 variables in the CBM In-Place estimation But opportunity for significant range of outputs 28

29 29 CBM- Uncertainties Area (A) Map Sketch Areal uncertainty pitfalls relate to level of project maturity Dip Projects follow the general flow of: Regional exploration stratigraphic mapping / coal seam mining Vast gross coal extent Site specific sample drilling (4-5 coreholes) Delimiting coal extent in exploration acreage Pilot study 4-8 clustered wells to lower water pressure direction of seams Coal workings Testing gpotential development coal area 10 skm Development (well spacing at few 100 m) Wholly dependent on market and infrastructure constraints Stratigraphic well Corehole Pilot Study Exploration licence area Production licence area Development outline

30 CBM- Uncertainties (A) SPEE/COGEH guidelines use a step out approach to the assessment of areal uncertainty Noting that coal measures have vast extents and it is difficult to assess singular pools 160 acre spacing used (800m diameter) 1P = 1 step out 2P = 2 step outs 3P = 3 step outs Not until project areal limits are defined can reserves be assigned 30

31 Thickness(h) Coal deposits can be stacked together within other lithologies over many hundreds of metres vertically Can give a very large GIP Potential to host free gas in stacked sands Not until the full sampling of the coals has been completed can a decision be made on what seams/beds will be developed Often only a few clusters of beds will be chosen as the net pay for development in the near term 31

32 Thickness (h) 32 Coal shallower than 150m and deeper than 1200m is usually excluded from volumetric calculations Too low gas content t at shallow depths and occluded d permeability at deeper depths SPEE/COGEH uses rules of thumb on requirements for clustering seams for development of: > 0.3m in thickness <300mvertical 30.0 separation Another major consideration is the maximum completed interval thickness

33 Ah Ash & Mit Moisture (%) Coal is mostly opaque under the microscope. The red-black material coal (vitrinite) in the thin section is the part of the coal that appears shiny black in hand sample, and is made from compressed wood tissue. The loop-shaped orange-yellow objects are the flattened large spores of plants. Field of view 3 mm Essentially these are the equivalents to the net-togross ratio of the individual coal bed Coal formed of non-net ash yield ( other lithologies ) l i and moisture content Analysis is performed in the laboratory and should have a relatively low range of measured uncertainty. However, Coals can vary significantly in ash yield vertically between seams Relates to the grade and depositional environment of the coal Moisture ( irreducible water ) contents are usually low (< 3-5 %) SPEE/COGEH suggest a cut-off of 50% for ash yield to qualify the bed as a suitably useable coal 33

34 Gas Content (Gc) Errors arise when estimating the gas content of the coal during sampling, relating to: Q1- lost gas (lost during the retrieval) Q2- recovered gas (contained during the sampling) Q3- residual gas (released by crushing the coal) Large uncertainties can exist on estimation of Q1 Majority of uncertainty relates to: Spatial distribution of the gas content Can vary considerably both laterally and vertically Requires detailed mapping and high density sampling Units- either As-received or Dry Ash Free (daf) Traditionally gas-content values are obtained by desorbing core samples in the laboratory and then correcting these values for lost and residual gas. 34

35 Coal Density Coal has a density ranging g between approximately ate g/cm 3 Density used to convert gas content (scf/ton) to volume (scf/ft 3 ) Dependent on ash/moisture content and rank of coal Rank is the degree of metamorphism of the coal Peat (V.Soft) Lignite (Soft) Sub-Bituminous (Med.Soft) Bituminous (Med.Hard) Anthracite (Hard) Biogenic Methane Thermogenic Methane Highest Gas Contents found in Sub-Bituminous to Bituminous coals Errors often occur relating to the density value not being used on the same basis as the gas content value i.e. both must be As-received or daf Often a conservative density limit of 1.75 g/cm 3 is applied The average insitu coal density can be estimated from from a density log or from core measurements 35

36 Coal Core Samples 36 Source: Churchill Mining

37 Reserves Assigning Proved reserves to coalbed reservoirs requires gas production at economic rates. This needs: Sufficient gas-in-place Adequate permeability Successful dewatering A high enough gas price Cost-effective drilling, completions and production operations A roaringly successful well test 37

38 Reserves also require a production profile, which can be difficult to predict during the dewatering phase. In Indonesia, for example, where there are no analogous reservoirs, reservoir simulation techniques will need to be utilised. After the reservoir has been dewatered, conventional techniques such as material balance and decline curve analysis can be used. 38

39 Production Forecast Production and Recovery Factor Typical well production shows a decreasing water and increasing gas rate in the first 2 years followed by gas decline Coal may need significant dewatering before gas flows and potential fraccing to enhance permeability Rat te (bwpd & scfd) Time (years)

40 Recovery Factor Production and Recovery Factor Gas St torage Capa acity (scf/to on) Maximum recovery limited by the gas adsorption isotherm and the POD Langmuir volume (V L ) is the maximum amount of gas that can be adsorbed on the coal at infinite pressure Used to estimate the maximum recovery factor and indicate the rate at which gas will be desorbed d Reservoirs can be: V L Gas Storage Capacity (450 scf/ton) in equilibrium Critical Desorption Pressure (632 psia) Abandonment Gas Content (125 scf/ton) Abandonment Pressure (100 psia) Maximum Gas Recovery (230 scf/ton) Initial gas content (355 scf/ton) Initial Reservoir Pressure (1620 psia) Gas Recovery Factor 230 / 355 = 65% saturated (includes free gas), or undersaturated Reservoir Pressure (psia)

41 Gas Composition 41 Gas composition is usually very high percentage of Methane (>95%) but may contain Ethane and CO 2 CO 2 can aid recovery factors as it is preferentially adsorbed onto the coal surface CO 2 production can increase over time CO 2 (or Nitrogen) can be injected to adsorb to the coal and increase Methane recovery CO 2 sequestration has positive environmental implications

42 Importance of Reserves Certification It is not uncommon for Governments and CBM companies to state reserve potential for a region or project to be several tcf. When first considered, these numbers can seem very ambitious, particularly for an unconventional resource. When estimating the potential resource for a country or project four factors need to be considered: d 1. How much coal is there? 2. How much coal has CBM potential? 3. What is the gas content of the CBM coal? 4. How much of the gas can be produced economically? Generally, those involved are optimistic on all four fronts and this leads to 3P reserve estimates of several tcf. A good rule of thumb is to take a 3P reserve estimate and apply a recovery factor of 25%. By applying this factor, a more realistic estimate of recoverable reserves can be obtained. 42

43 One of the most important trends to occur in the past few years has been certification of reserves by independent consultants. All of the major CBM projects have taken this approach and it is likely that many of the smaller projects will also follow this route in the future. A regional CBM Certification company is RPS Energy in Singapore Certification removes one of the major question marks that previously blighted CBM developments: How much gas is really there? Certification makes it easier to market the gas as it provides the necessary assurance to gas purchasers. It also provides the equity market with a means to benchmark CBM companies against conventional oil and gas companies. This makes CBM companies less niche and more mainstream. 43

44 44 Source: SPE

45 Comparison of Conventional and CBM Gas production 45

46 46 Source: Bruce Atkins

47 Further CBM Issues As CBM becomes more widespread (particularly in the USA and Australia), a number of issues are impacting the industry: water disposal, land access, licensing and methane loss to atmosphere. These issues are likely to be overcome and should not affect the long term viability of the industry. 47

48 Water Disposal A new CBM project can produce large volumes of water during its early stage of production. The volume decreases over time. Water disposal is an issue as it can be very saline (unlikely likl in Indonesia) and cannot be dumped into surface water supplies or be used for irrigation. Often the water is re- injected into subsurface rock formations, but this has led to concerns about contamination of the water table. In hot countries such as Australia, the water is put into evaporation ponds. In cold countries, the water is allowed to freeze and the salts are collected allowing surface disposal of the clean water. 48

49 49

50 Land Access CBM projects cover large areas of land. In some cases this land is already used for other uses e.g. agriculture. CBM producers need access to drill hundreds of wells and this can cause conflict with land owners. There have been several cases of land owners seeking injunctions to prevent access resulting in projects being delayed or even cancelled. Horizontal drilling can be used to reduce the impact of land access issues. 50

51 Project Economics Since companies involved in CBM tend to be small with limited resources, it is imperative that they are able to develop fields in a cost effective way. The nature of developments (initially capital intensive drilling programme followed by long lead times before commercial production rates) means that companies are unable to generate positive cash flow for a number of years. During the pilot project a company will determine the economic viability of a site. The project economics are determined by a number of factors: 51 Well flow rates Well spacing Cost of drilling and development Development costs Ability to dispose of water cheaply Good land access Access to market

52 CBM Project Development CBM projects typically go through the following stages of development: 1. Exploration 2. Geology & geophysics 3. Pilot project 4. Phased development 5. Abandonment 52

53 Monetising CBM Reserves Due to its unconventional nature, CBM producers initially had difficulties persuading gas purchasers to enter into contracts. This was mainly achieved by undercutting existing i suppliers by offering discounted gas prices. As CBM became more established, companies were able to reduce the discount while still remaining competitive with conventional sources. By adopting this strategy CBM has managed to develop significant market share and in some regions it is seen to be a significant threat to conventional gas players. 53

54 Gas Marketing Chemically CBM is identical to any other source of gas. Therefore, once it has been dried and compressed it can be sold into any market. Often, the main customers are base load power generators. This is because CBM supply cannot be switched on and off depending on demand, as wells that are shut-in start to water again. Another factor is the relatively long lead times required for production to be increased to meet new contracts. Lead times of two years are typical to allow for wells to be drilled and to allow sufficient time for dewatering and subsequent commercial production of gas. However, as with conventional sources of gas, should the project be remote from the gas market then the development might not proceed. 54

55 CBM - Risks In most cases the Chance of Discovery is relatively l well known due to regional stratigraphic assessments. Primary risks are associated with risks leading to the Chance of Development, such as: Will gas rates (permeability) and gas contents be high enough? Do a market and infrastructure exist? Are drilling rigs available? At what cost? How long will dewatering take (if required)? How will the volume of water be handled? Composition of the gas suitable for purpose? Well peak production rate high enough? Well spacing tight enough? How much will compression cost? What land ownership and royalty considerations exist? Environmental risks addressed? d? 55

56 CBM - a World wide business? Approximately 70 countries worldwide have extensive coal bearing strata Over 50% of those have investigated CBM development Hard coal production (2006) MMt China 2482 USA 990 N~20 India 427 Australia 309 South Africa 244 Russia 233 Indonesia 169 Poland 95 Kazakhstan 92 Colombia 64 Investigated or investigating CBM Development and

57 Indonesia s CBM potential Indonesia is the world s largest seaborne exporter of thermal coal, but has yet to exploit its prospective CBM resource. The bulk of coal reserves are located in the provinces of South Sumatra, East Kalimantan and South Kalimantan.. 57

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60 Source: Advanced Resources International,

61 Coal concessions and pipeline infrastructure 61

62 With only one trial project in operation and no other exploration underway, it will be some time before CBM is in a position to compete for market share. Prospective operators in Indonesia cannot expect commercial production before 2013 and perhaps several years later. Experience from the Australian industry indicates that the cost of CBM supply is equivalent to or higher than that of conventional projects. New CBM operators in Indonesia may have to accept slightly lower returns than a conventional project whilst they establish their supply credentials. 62

63 Economics Experience from Australia s young CBM industry suggests that when gassy coals are discovered and a pilot project completed, operators were compelled to sell small volumes of gas at a 10-15% discount to the prevailing price, to establish an initial foothold in the market. At all stages, the returns on these projects are marginal.. The cash flow profile of CBM projects may not prove as attractive to these entities as conventional oil or gas developments. The key market for Sumatran CBM is likely to be Java. New sources of conventional gas are being sought to meet the forecast, sustained growth in Indonesian demand. 63

64 Infrastructure Indonesia s coal basins are remote from the major regional markets, but the recently-completed South Sumatra-West Java (SSWJ) pipeline could provide an option to bring CBM from South Sumatra to Java. With around three quarters of pipeline capacity spoken for, potential CBM operators will face stiff competition for remaining i capacity. It will be five years or more before any CBM operators are in a position to sign long-term supply agreements, by which time any spare capacity in current and planned pipelines will probably be taken and further infrastructure t (the proposed LNG regas terminal and the east-west t Java pipeline) could have reduced the need for further Sumatran imports. Thus, accessing any spare capacity in SSWJ I and II may still be the best hope for accessing Java. 64

65 Fiscal Drivers for CBM Growth US Section 29 tax credits fuelled massive growth in CBM industry in mid eighties Queensland Government requires electricity retailers to have 13% of their electricity generated by gas penalties for non-compliance of around $10/MWH India CBM-III bidding round in 2007 includes: Seven years tax holiday from the date of commencement of production. Fiscal stability yprovision in the contract. No participating interest of the Government. Freedom to sell gas in the domestic market at market determined rate. 65

66 Source: IHS,

67 Fiscal incentives?? The Government of Indonesia (GoI) has been licensing i conventional oil and gas projects for a long time now, however this experience does not guarantee a smooth licensing process. If the Government harbours ambitions to promote CBM development, it will need to ensure that the terms and incentives are in place to encourage operators to take up the options and invest in exploration and appraisal. It is worth noting that the CBM business in Australia went through four or five false starts over a 15-year period bf before any project was able to gain critical i mass. Projects in Australia are offered no tax breaks but such an incentive may be needed in Indonesia, if the government wishes to accelerate the process of CBM development The availability and form of any incentives also unknown. In Australia, CBM concessions are offered largely on the same terms as conventional gas projects, in a royalty/tax fiscal regime Indonesia s fiscal regime is far less favourable to contractors than that in Australia, and it is a more complex operating environment. The need for water disposal facilities may cause problems, as Indonesia is much more densely populated than Australia. CBM operations may need incentives such as an improved profit gas splits or lower Domestic Market Obligation (DMO), to compete with other sources of gas. 67

68 Ministerial Letter #033 in May 2006 explained that a coal company or an existing PSC holder has option to directly negotiate with the Government for a CBM PSC. If there is an overlap between the oil company and the coal company, a forced marriage may be necessary 68

69 PSC Terms? First Tranche Petroleum (5%) Cost Recovery Cap (80-90%) Equity to be Split (80% to Contractor) Tax (44%) DMO (0?) Investment Credit (?) Thus contractor take is (100-5) x (0.8 x 0.44) =

70 The attraction to the vast and seemingly lucrative CBM opportunities regionally has attracted a mix of interest: Major international petroleum companies State petroleum companies Mining companies Investors Each wants their piece of the pie but Asia is in a state of catch-up in this fast-moving emergent industry. Expedient addressing of this lag will allow the appreciation and capitalisation of its potential. 70

71 Potential Operators A number of upstream operators are interested in the opportunity that CBM presents and some have indicated a very positive intent. Indonesian state company, Pertamina, is similarly positioned and eager to participate Major international companies have been mentioned as potential participants, i t but CBM projects in Indonesia appear to have limited it materiality to a super major at the present time. Regional operators with a proven record in Australian CBM, for instance Arrow Energy and Santos, have expressed a strong interest in entering the business in Indonesia. A recent feature of the Indonesian licensing i landscape is the presence of local, one-off operators, which in the main, fail to deliver the potential predicted for their acreage. Another party that will have a major bearing on how the future of a CBM industry are the coal operators. 71

72 Barriers to Success? While the huge potential of Indonesia s coal resource is widely recognised, the environment in which it must establish itself is very challenging. The sector is at an extremely early stage and a number of obstacles must be cleared for it to progress: The lead time to commercial gas production is likely to be a minimum of five years. Market conditions will certainly change by the time that CBM is competing for market share. A major variable is the terms under which the blocks will be licensed. Whilst lessons may be drawn from the development of a viable CBM industry in Australia, Indonesia has a more complex operational and legislative environment. 72

73 Key Success Factors Coals at the right depth with permeability and gas contents in an acceptable range A low cost drilling and services industry specifically designed d for CBM and not Oil and Gas Appropriate fiscal incentives to kick k off the industry Companies encouraged to build a portfolio of CBM opportunities not just one PSC (ringfencing?). CBM is a volume/margin business. A simple, easy to use and quick-acting regulatory system Easy land access and water disposal An attractive gas market with good gas prices Experienced CBM companies who have a track record of success Constructive co-ordination with the Coal license holders 73

74 Appropriate Regulatory Systems have been Essential CBM needs legislation and regulatory framework designed especially for it it is not like traditional oil and gas and it can conflict with coal resource if not properly managed Coordination between CBM and coal producers is essential Environmental Authorities must be involved early on to manage water disposal and rehabilitation issues 74

75 Required Reading Is the PSC the best fiscal regime for the CBM business? 75

76 76 CBM business model is different to normal gas business CBM is much more capital-intensive For the CBM sector to thrive, hundreds of wells per year will need to be drilled can BPMIGAS cope with a multifold increase in activity? HSE requirements are different remember these are basically water wells Tertiary coals in a tropical climate will be a new technical challenge for CBM Transparency of fiscal, regulatory and taxation is essential The concept of POD methodology and ring fencing needs to be reviewed Is the PSC the best mechanism? Royalty/Tax fiscal regimes are better suited to such high activity endeavours Both US and Queensland CBM industries received a huge boost from targeted incentives. India is following suit CBM needs legislation and regulatory framework designed especially for it it is not like traditional oil and gas and it can conflict with coal resource if not properly p managed Coordination between CBM and coal producers is essential Environmental Authorities must be involved early on to manage water disposal and rehabilitation issues

77 The issues that face the growth of the CBM Industry in Asia are related to several key points: It is a fledgling industry Uncertainties and Risks and not fully understood/documented Infrastructure and equipment are not readily available Expertise are not home grown Anything associated with Coal has a bad press Coal is a dirty word 77

78 78

79 or should we prepare for this?

80 Acknowledgements Dr. Mike Reeder, RPS Energy Wood W d MacKenzie IHS 80