Posted by ERCE on Thu, 05/07/2020 - 15:34

Introduction

For a commercial discovery to progress from the Exploration Phase to the Exploitation Phase in Indonesia, a plan of development (“POD”) must be approved by the Minister of Energy and Mineral Resources (“MEMR”), with consideration also given by SKK Migas (an Indonesian Government agency charged with regulating the upstream oil and gas industry).

Regulatory documents are published by SKK Migas on how Contractors should prepare and submit PODs. The POD Work Guidelines published in 2010 explicitly detail how a company should define and report Reserves. These guidelines differ significantly from widely used systems such as the SPE’s Petroleum Resource Management System (“PRMS”) or the Canadian Oil and Gas Evaluation (“COGE”) Handbook. In August 2018, updated Work Guidelines were published in which Reserves reporting is more in line with the aforementioned systems.

Types of POD

Upon a commercial discovery, a Contractor is required to prepare and submit a POD to the MEMR and SKK Migas. The POD outlines the technical aspects of the field (geology, geophysics, petrophysics etc.), hydrocarbons in place, resources, development scenario, production forecasts, facilities and economics. The first POD submitted is known as the First POD, or POD I, and upon approval, the field progresses from the Exploration Phase to the Exploitation Phase.

If one or more fields within an Exploitation Area are planned to be developed and follow a different structure to the First POD, a second POD, or ‘Next POD’, can be submitted. The Next POD must obtain approval from the Head of SKK Migas.

If existing infrastructure exists nearby to a discovery, the field can be produced after approval of a Put on Production (“POP”) plan. This differs from a POD in that a full development plan is not required, but only a maximum of two wells can be put on production per structure. Up to two POPs can be approved, after which a POD must be submitted. The POP must obtain approval from the Deputy in charge of planning in SKK Migas.

A schematic showing the POD process is shown below.

Previous Reserves Reporting under the 2010 POD

Although the Reserves categories (i.e. 1P, 2P and 3P) used in the 2010 POD are the same as those used in widely used international Reserves classification systems, their definition was markedly different. The 2010 POD Work Guidelines specify the following requirements in defining a range of Reserves:

Lateral Extent

Source: BP MIGAS – Work Procedures (Plan of Development), # PTK-072/BP00000/2010/S0 

These constraints on lateral extent could often lead to 1P and 2P evaluations of Reserves where robust geophysical/geological data and interpretation were ignored. For example, it may be that, after carrying out the appropriate rock physics work, seismic amplitudes support the extension of the penetrated reservoir some distance from the well. This consideration was only allowed at the 3P level.

The constraints were particularly restrictive in the absence of an ‘adequate’ well test. If an oil-water contact (OWC) or gas-water contact (GWC) has been established through pressure gradient analysis or log responses, it is likely that this structural contour leads to a hydrocarbon area greater than a 250 m or 750 m radius circle around the well. It should also be noted that there are no guidelines on the 1P lateral extent for an oil reservoir with <30oAPI.

One can understand though that the likely intention of the 1P lateral extent rule (in the absence of an adequate well test) was to prevent the overestimation of Reserves where subsequent testing leads to poor results. The rule has similarities with North American well spacing requirements used for example with SEC reporting.

In the PRMS, the guidelines on the lateral extent of Proved Reserves (1P) are less restrictive. The area of the reservoir considered as Proved Reserves can include undrilled portions if they can be reasonably judged as being continuous to the area delineated by drilling and defined by fluid contacts. The undrilled areas should also be judged to be commercially productive on the basis of available geoscience and engineering data. The key aspect under PRMS is the demonstration of continuity from the known accumulation with a 90% confidence. For Probable Reserves, less certainty is required in defining continuity away from well control.

The COGE Handbook contains similar guidelines to those in the PRMS. Proved Reserves may include an entire closure so long as there is adequate supporting geological/geophysical data for the continuity of the known accumulation.

Exceptions to the 2010 POD lateral boundary rules may be considered if:

  1. The reservoir has special characteristics;
  2. More than one well is present, and the well locations are such that the P1 areas of each well intersect. In this case the P1 area is determined as the outermost contour of the intersecting area, as long as the area still lies within the P1 vertical limit;
  3. Other references are used.

The use of ‘special characteristics’ and ‘other references’ are at the discretion of the MEMR and SKK Migas and are not explicitly defined.

 

Vertical Extent

Source: BP MIGAS – Work Procedures (Plan of Development), # PTK-072/BP00000/2010/S0 

The constraints on vertical extent were more in line with standard industry practice. However, some may argue that in the absence of any robust OWC/GWC interpretation, a more reasonable method for estimating the 2P vertical limit would be to use 1/2 of the way between the LKO/LKG and the spill point or HKW.

The same exceptions described for the lateral boundary rules can also be applied to the vertical boundary rules.

For 1P or Proved Reserves, the 2018 POD rules are not dissimilar to the PRMS guidelines, which state that Proved Reserves should be limited to fluid contacts and in their absence, to lowest known hydrocarbons (LKH) as seen in a well. However, if definitive geoscience, engineering or production data (e.g. seismic indicators or pressure gradient analysis) exist, these can be used to support a deeper contact than the LKH.

The COGE Handbook is also similar, stating that where fluid contacts are unknown, Proved Reserves must be restricted to the LKH.

 

Production Forecasts

Source: BP MIGAS – Work Procedures (Plan of Development), # PTK-072/BP00000/2010/S0

One of the critical aspects of the 2010 POD Work Guidelines was the way in which production forecasting was risked. The risked ‘Reserves’ would commonly be quoted as ‘2P Reserves’. The risked approach is often also applied to in-place volumes (i.e. a risked ‘2P’ STOIIP), which could then find their way into the static and dynamic models.

For the same field and dataset, the risked approach in the POD leads to lower estimates of ‘2P Reserves’ compared to other international classification systems. Furthermore, in the POD no risking is applied to costs so when applied to the risked production profile, economic results can be pessimistic.

Reserves Reporting under the updated 2018 POD

The POD Work Guidelines were recently revised in 2018. In general, the revisions close the gap between the 2010 POD and international classification systems.

Lateral Extent

Source: SKK MIGAS – Work Procedures (Plan of Development), # PTK-037/SKKMA0000/2018/S0

The lateral extent of the 1P case may now be based on analogue data if the obtained test data is inconclusive. Coupled with the support of geological and geophysical interpretation this could allow for significantly larger 1P areas. The quantitative limits of 250 m (oil) and 750 m (gas) are only imposed where no adequate analogues exist.

The definition of the 2P case has changed significantly and is no longer linked to the 1P area. The 2P lateral extent is now based on a best estimate 3D model, which should take into account all geological, geophysical and engineering data. This update will allow larger areas to be used in estimating 2P Reserves.

The changes to the definition of the 1P and 2P lateral extent should move POD estimates of Reserves much closer to PRMS and COGEH equivalents.

Vertical Extent

Source: SKK MIGAS – Work Procedures (Plan of Development), # PTK-037/SKKMA0000/2018/S0

Most of the rules guiding the definition of the 1P vertical extent are unchanged, except that now, if the OWC/GWC cannot be determined, the 1P is limited to the lower limit of the production test interval. Previously this was the LKO/LKG or the lower limit of the production test interval.

If the OWC/GWC cannot be determined, the 2P vertical extent is now defined as the LKO/LKG and the 1/3 of the way between P1 and spill point/HKW rule only applies if the LKO/LKG is equal to the lower limit of the production test interval.

If an OWC/GWC can be determined, then there is no difference between how the 2010 and 2018 PODs define vertical extents. However, if no OWC/GWC can be determined, then the 2018 POD appears to be more conservative than the 2010 POD as previously the 1P could be based on the LKO/LTO and now it must be based on the LTO which also reduces the 2P which is one third of the distance between the 1P and 3P levels.

 

Production Forecasts

   Source: SKK MIGAS – Work Procedures (Plan of Development), # PTK-037/SKKMA0000/2018/S0 

The most important update to production forecasting in the 2018 POD is the removal of risking. This change means that the production forecasts used for economic evaluation are consistent with the estimates of in-place volumes, recoverable volumes and costs. This will allow for more meaningful evaluations which will allow easier comparison to portfolios outside of Indonesia.

Application of risking may still be required to the production forecasts but this is only the case if there is insufficient or inadequate data. The minimum data requirement includes:

  • 2D seismic of sufficient density and distance between lines to cover the entire structure
  • Sufficiently representative sonic log, VSP or checkshot data
  • Standard open-hole well log suite (SP, caliper, GR, density, neutron, resistivity)
  • Sufficient core data to carry out RCA and SCAL
  • Cuttings, mud logs and gas readings
  • Supporting data for fracture analysis, e.g. image logs (if fractures are present)
  • Well test data/production test including pressure build-up test
  • PVT and water analysis
  • Reservoir pressure data describing the fluid gradient

Conclusions

The requirements for Reserves reporting under the 2010 POD were somewhat different when compared with other international Reserves classification systems such as PRMS and the COGE Handbook. The 2010 POD rules were generally leading to lower in-place and recoverable volume estimates. The primary reasons for this were (a) lateral limit constraints in the 1P and 2P estimates and (b) risking of 2P Reserves (i.e. 90% 1P + 50% 2P). Under such constraints, any subsequent reservoir modelling could become non-physical, making it difficult to accurately assess facilities requirements and project economics.

The updates made in the 2018 POD rules represent a significant shift in Indonesian Reserves reporting towards international systems. In particular, the primary reasons for difference have been addressed, with the 2P lateral extent now based on 3D modelling and risking being removed from production forecasts.

The new rules should lead to more representative estimates of in-place and recoverable volumes which in turn will improve economic evaluations.

 

Comparison of 2010 vs 2018 POD Rules: Lateral Extent

Sources:BP MIGAS – Work Procedures (Plan of Development), # PTK-072/BP00000/2010/S0; SKK MIGAS – Work Procedures (Plan of Development), # PTK-037/SKKMA0000/2018/S0 

Comparison of 2010 vs 2018 POD Rules: Vertical Extent

Sources:BP MIGAS – Work Procedures (Plan of Development), # PTK-072/BP00000/2010/S0; SKK MIGAS – Work Procedures (Plan of Development), # PTK-037/SKKMA0000/2018/S0 

Comparison of 2010 vs 2018 POD Rules: Production Forecasts

Sources:BP MIGAS – Work Procedures (Plan of Development), # PTK-072/BP00000/2010/S0; SKK MIGAS – Work Procedures (Plan of Development), # PTK-037/SKKMA0000/2018/S0 

ERCE has worked on a large number of projects across the Indonesian archipelago for a variety of clients including National Oil Companies, Majors, large and small independents, financial institutions, legal companies and service companies. We’ve performed and supported basin studies, strategy development, commercial studies, running datarooms, economic modelling, fiscal term review, M&A due diligence, Reserves & Resources evaluations and assessments, technical project work and legal expert work in Indonesia. We are also experienced in different stages of the development cycle in Indonesia including Exploration, Development and Production along with the regulatory bodies and requirements.

To find out more about how ERCE can help your business in Indonesia please contact enquiries.asiapacific@erce.energy.