RESERVE ENTITIES AND CLASSIFICATIONS
Reserves
Introduction
Assets are the foundation on which E&P companies are built. The business of an E&P company is to acquire assets, increase their value through exploration and development activities, earn revenue through production, and dispose of assets once there is no further opportunity to add value to, or receive value from them. In today’s increasingly competitive environment it’s critical that organizations recognize and respond to both assets and business areas that are not contributing to the organization’s profitable growth. Assets that are no longer profitable or that fall outside the corporate areas of expertise are candidates for disposition. Business areas that are not competitive represent opportunities for refocusing resources.
Common strategies among the top oil and gas firms include aggressively managing their asset portfolio, restructuring their asset base, focusing on core strengths and expanding high return core businesses and improving the performance of under-performing business areas by reducing costs. Business drivers such as new technology, changing regulations, and shifting market demands change the nature of the business; this constantly shifts our perceptions about relative corporate strengths and weaknesses.
Uncertainties in price and market demand forecasts, and difficulties inherent in assembling the high-level asset performance information needed to accomplish these strategies, makes management of these portfolios a complex and demanding task. Data management strategies need to be structured to support the data query and analysis functions necessary to keep pace with the constant level of change.
Unlike centralized financial and human resource systems, information relating to reserves and production is dynamic and volatile. New information sources, such as those supplied by external vendors, consultants and GIS systems change rapidly and are rarely integrated into a form that can be shared and used throughout the organization. This information is often scattered in a variety of information ‘silos’, some centrally administered, some managed by departments, others are set up by individuals.
As a result, many, if not most, enterprises are faced with the following problems:
- Information is held in different formats and in different databases
- There is often inconsistency in the way the information is presented and analyzed between these sources
- It is almost impossible to integrate information from one data source with another. This can be because there is no common link (codes can be quite different between systems).
- Decision makers need to have a total, ‘holistic’ view of information
Integration of asset information and the corporate “portfolio” is critical to success in a data model, as is access to land, facilities, and proprietary well data necessary to see the full picture. Logical relationships between technical reserves and economic reserves must also be maintained. Models must provide the perspective to look at asset information the way the different business areas need to see it.
For a production engineer this means looking at the reserves and production associated with their area and facilities. For a Geologist, this means looking at proven, probable and possible reserves associated with their play. For a marketer, this means seeing production forecasts for proven reserves and approved capital projects, according to product and sales points. Each perspective represents a twist on the accounting roll-up most often used to manage asset data. Each perspective is equally valuable in getting information to the person whose business decisions will impact the entire company.
Ironically, the lost opportunities in not having asset information readily available are not readily apparent - “you don’t know what you don’t know”. To turn the picture around, however, even minor improvements in correlating business information across functional areas inevitably bring new opportunities to light.
Business Process Overview
Purpose
The Reserves Module provides a means of describing and managing information about Reserves data. This data is created throughout its life cycle, from the addition or acquisition of reserves, development and production of these reserves through disposition by sales or abandonment.
Description
The life cycle of Reserves data, from inception to final disposition through destruction or disposition, is lengthy. Reserves data is often processed and reprocessed many times in order to extract maximum value from the data; it is treated as a valuable asset in data sales and trades and provides important information for the design of new Reserves surveys. Each step in the life cycle is data intensive. Product generation and use of archived information at every stage mean that integration between Reserves data and a records management store is a critical component of effective Reserves data management.
Key Business Processes
Reserves Additions
A new reserve entity is generally created when a successful discovery well is drilled, when existing reserves are acquired from another company by purchase or trade, or when a productive zone is identified in an existing wellbore. With the exception of an acquisition, there is limited data available on which to make a reserves determination, or to attempt to forecast the production of those reserves over the life of the W. The initial reserves determination is usually made through volumetric calculations based on the aerial extent of the reservoir, the net pay thickness, porosity and water saturation of the reservoir rock. An alternative approach is to pick a similar well in the same field with an established reserves determination, and use these volumes by analogy. The initial production forecast for a new well is usually done by such an analogy.
Reserves Determinations
Volumetrics
The reserve volumes are calculated based on knowledge of the reservoir’s physical characteristics as a container for the reserves. First the rock pore volume is determined by multiplying the aerial extent of the reservoir by its average net pay and average connected porosity. This yields the total volume available to contain moveable fluids. This is then multiplied by the fraction of the pore volume containing either gas or oil, which is usually calculated as 1 - Water Saturation and by a volume conversion factor between fluid volumes at surface conditions and fluid volumes at reservoir conditions. This yields the hydrocarbon volume originally in place. The last factor is the recovery factor, which is the percent of the total hydrocarbon in the ground that you expect to produce. This then results in the ultimate recoverable reserves volume.
Decline Analysis
As with any commodity being extracted from a container, the rate at which it comes out diminishes as it is being consumed (try this with ketchup for example). With oil and gas, this is usually because it is reservoir pressure which forces fluid to move from the reservoir to the wellbore, and as the fluid is produced the reservoir pressure is diminished. Decline analysis is a way of statistically analyzing production volumes which decrease with time and cumulative production under consistent operating practices, to arrive at a forecast which continues along this established trend to predict future performance. Eventually the forecasted production rate falls below a minimum threshold, and the well is assumed to be abandoned. If you significantly change the way you operate the well, you will change the rate at which it produces oil and gas. Such changes interfere with the validity of trying to perform decline analysis along the established trend.
This technique is usually considered the least ambiguous method of calculating remaining reserves, so long as a reasonable trend can be established, as it does not rely on assumptions about the reservoir itself. The production volumes required for the analysis are usually readily available from independent data vendors, based on volumes reported to regulatory agencies. It is therefore the easiest analysis to perform on a well or field in which you do not have access to proprietary information.
Gas Material Balance
The basis of gas material balance is to assume that the reservoir acts like a closed tank of inert gas under pressure. As gas is removed from the reservoir, the pressure declines in a fashion consistent with the size of the tank and the compressibility of the gas itself. The underlying assumptions do not allow for movement of any fluid into the reservoir, phase change behaviour within the reservoir, or compaction of the reservoir rock due to settling, as the reservoir pressure diminishes. To perform the calculations, average reservoir pressures are required over the life of the reservoir. While a well is producing, the pressure immediately around the reservoir is lower than the average reservoir pressure. It is this pressure differential that causes gas to move toward the well bore. To achieve a measurement of average reservoir pressure, the well is shut in for a period of time to allow the pressure in the reservoir to equalize. Where the reservoir permeability is low, the time required to get true equalization may be many years, and as such, the pressure measurements made in these situations are only approximations. Generally though, the longer the well was left shut in before the pressure measurement was made, the more accurately the average pressure is determined. If more than one well is producing from the same reservoir, then ideally all the wells should be shut in while allowing the reservoir pressure to equalize. This loss of production is the most expensive component of acquiring accurate pressure data.
Reserves Approvals
Reserve volumes are a significant component of an E&P companies value as represented to shareholders, and are usually the major component. As such, accountability for changes to these volumes is important. Approvals may be based on both a technical assessment as well as on a business assessment. The technical approval covers off engineering verification that the estimated volumes are realistic for the certainty with which they are stated. The business approval covers off the funding commitments required to book undeveloped reserves as Proved – i.e. it is certain that the development of these reserves will happen in the future. Approvals may thus be required from multiple individuals before reserve changes are put in place.
Changes in Reserve Volumes
Once the appropriate approvals have been received, a mechanism is required to ensure that the effected balances changes are made. This is more an application issue than a business workflow.
Final Year End Numbers
At some point in the reserves reporting cycle, a decision is made to close off further changes to the reserve volumes for the current period (usually a year). The current balance at this time becomes the closing balance for that reserves reporting period, and forms the basis for subsequent corporate reporting. As reserve volumes may be subject to audit, it is required that the integrity of the detailed reserves information making up the reported reserve volumes is maintained.
Subsequent changes must be clearly identified with subsequent reserves reporting periods.
Production Adjustments
The most common reason for reserve volumes to change is that reserves are being produced. This is usually the one reason for reserves revisions which does not require any formal approval, and for this reason is often managed as an automated, or semi automated process.
Prior Period Production Adjustments
Occasionally, a reserves reporting period may be closed off with some of the production volumes for that period existing as an estimate, rather that an actual measured volume. There are also instances of production adjustments occurring that change the previous years “actual” production volumes. In both these situations a special reserve adjustment needs to occur when the correct production volumes become available. As the reserve numbers for the previous reporting period are not to be changed, the production revision must occur in the reporting period in which the discrepancy is identified. A separate revision category is usually used to separate such book keeping corrections from the production adjustments associated with the actual production for the current reporting period.
Processing and By Products
Oil as it exists in the reservoir usually contains dissolved gas. This effects its volume in situ. By the time it is measured at surface, however, most of the dissolved gas has separated out of the oil, and very little volume adjustments occur during further processing. Oil volumes are tracked at surface conditions, and though these volumes may be explicitly referred to as dead oil, or stock tank volumes, this is usually implied.
Gas, on the other hand, contains a number of impurities and by products that may be separated from the gas in multiple stages. The volumes measured for raw gas as it is produced at the wellhead may be different from the volumes of raw gas arriving at the plant inlet separator. Changes in pressure and temperature within the gas gathering system may have caused heavier hydrocarbons such as pentane to condense into a liquid usually called
condensate. Within the gas plant undesirable impurities such as water vapour, Carbon Dioxide (if present in excessive amounts) and Hydrogen Sulphide (if present) are removed and disposed of. Saleable by product such as Propane, Butane and C5 plus are removed both to ensure that the residual gas meets pipeline specifications, as well as to produce a saleable product.
An additional source of volume loss for gas is the consumption of part of the gas stream as fuel gas for running compressors and other production equipment.
To account for such loss in the overall gas volumes, loss factors are identified either for each processing stage, or for the overall volume loss between wellhead and sales meter. By product yield rates are also identified to establish anticipated natural gas liquids production resulting from gas processing.
To avoid confusion when reporting gas volumes, it is expected that raw and sale gas volumes be easily identified. A common convention is to report gross lease volumes on a raw gas basis, and partner shares on a sales gas basis.
Reserves Ownership and Reporting
Reserves reporting is usually required for both the total gross reserves (often called 8/8ths) as well as specific partner interest sets. In addition to identifying the partner’s interest, the report should also identify the interest type being reported (Working Interest, Net Before Royalties, Net After Royalties, Revenue Interest etc.) Such requirements for reporting apply to both remaining volumes, as well as to those revisions which brought about the volume changes from the opening balance to the closing balance.
Reserves ownership arises from the mineral agreements in place for the land containing those reserves, though subsequent agreements for finding and producing the reserves may over ride the original mineral agreements. As such, there is no upper limit to the complexities which may be introduced into the ownership of the reserves. Even for a single well in a single zone, ownership may vary between the products being produced, and may also change over time. Ownership may even vary between the gas originally dissolved in the oil at time of discovery, and that which exists as a separate gas phase (or gas cap) immediately above the oil. As gas is gas when it comes out of the well, both engineering and accounting determination is required to establish what volumes are deemed to be solution gas, and what volumes are deemed to be gas cap gas.
Revision Reasons/Categories
There are both business and corporate reporting requirements to categorize the reasons reserve volumes have changed. This is accomplished by defining a set of revision reason categories, and ensuring that when reserve revisions are made, the revision volume and associated category are also identified. Where a single reserve change contains components that apply to separate revision categories, then separate revision records are required for each component. Generally these categories group revisions by reasons such as: Drilling of new Exploration Wells, Drilling of offset wells, Acquisition or Disposition of properties, Interest changes due to payout, Capital Development, as well as production performance better or worse than expected.
Economic Evaluation
Reserve evaluations are usually made first on a technical basis – what the well is capable of producing, and then on an economic basis – what the well is capable of producing while maintaining a positive cash flow for the operator. Where the share of revenue and operating costs is not the same between owners, the point at which the cash flow becomes negative will be different for the different ownership positions.
Technical forecasts change only when the well’s performance changes. Economic forecasts may change every time the price forecast fluctuates. At times of abrupt negative price changes, companies are faced with reporting reduced earnings as well as reduced reserves. The question usually asked is “Why should we write down the reserves, the oil/gas is still there isn’t it?” The answer is “Yes, it’s still there, but for this price regime more of it is going to be left there when the well becomes uneconomic.”
Tables
Decline Analysis
Material Balance
Volumetrics
Reserve entities as PDEN
Reserve Economics
Reserves
- RESENT_CLASS
- RESENT_COMPONENT
- RESENT_PRODUCT
- RESENT_PROD_PROPERTY
- RESENT_REVISION_CAT
- RESENT_VOL_REGIME
- RESENT_VOL_REVISION
- RESENT_VOL_SUMMARY
- RESENT_XREF
