Integrated Reservoir Study Methodology
This summary presents an example of the technical content and methodology which are regularly applied to integrated reservoir studies. Although all parts of this description are unlikely to be applied in all cases, the text also closely reflects "best practice" that might be applied as part of an evaluation of a producing or mature resource by an international oil and gas company.
Introduction to Integrated Reservoir Study Methodology
The broad objective of the example study is the determination of economically viable options for the redevelopment of a mature oil or gas resource and the promotion of that resource to international oil or gas companies. An overview of the methodology is shown below.
The example methodology is based on the following main stages:
- Subsurface Review and Reserves Evaluation: The available geological, reservoir, and petrophysical data will be analyzed and evaluated to prepare a reserves estimation for the resource. The same data will also be used with available production data to establish the main productive units within the field or resource. Numerical simulation models might be part of this review if there is sufficient data of an adequate quality.
- Production Forecasts and Development Plans: Predictions of future production will be made where appropriate using reservoir simulation or material balance methods. An optimized development plan will be prepared for the field which is designed to deplete the economically recoverable reserves, including those that do not appear to be drained by existing wells, as efficiently as possible.
- Refurbishment Plans: Where appropriate, a determination will be made as to which of the existing wells and infrastructure can be used in the optimized development plan. Work plans will be developed for the reuse of existing wells, drilling of new wells, remediation of the existing infrastructure, abandonment of surplus infrastructure, and an upgrade of the existing process facilities.
- Health, Safety and Environmental Assessment: An assessment of potential health, safety, and environmental factors relevant to each plan will be made. A plan to ensure environmentally acceptable operations will be developed.
- Capital, Operating Costs and Development Schedules: A sequenced work schedule and flow diagram will be developed for any work associated with field production enhancement. In addition, a field project budget, production forecast, and project cash flow study may be developed.
- Economics and Production Sharing: Where more than one option exists a comparative evaluation of the options will be made in order to establish a ranking in order of likely economic performance. Where appropriate, plans for foreign financial participation will be developed including the potential for production sharing. In addition, fields at the lower levels of economic performance will be critically reviewed to establish if abandonment of part of their facilities can produce a significant improvement in economic performance, thereby increasing their attractiveness for participation.
- Promotional Material: For resources that require external participation, plans will be developed to show enhanced future production under the improved engineering and production conditions. Promotional material will be developed to solicit international interest in the projects. Work carried out will include a review of previous efforts to obtain external participation, development of candidate lists for participation, and development of a presentation program for potential external participants.
An engineering review will be implemented for the field or resource. The initial stage of this analysis will be a subsurface review, comprising geological and reservoir engineering analysis to establish and classify existing or remaining reserves, and to establish potential future production.
The facilities required to achieve this production, along with the potential to use existing facilities will be evaluated. The subsurface requirements in terms of new wells and re-completions will be established, as will the requirements for surface engineering including new infrastructure and refurbishment of existing infrastructure and equipment. To ensure the scope associated with any redevelopment plan is fully captured, plans for abandonment of redundant wells and infrastructure will also be developed. Environmental assessments of the redevelopment plans and current operational practice will be implemented. These will ensure that environmental impact is kept to an economic minimum. Costs and schedules for redevelopment will then be produced based on the subsurface and surface engineering reviews.
The three main elements of the engineering analysis are:
- Sub-surface review and reserves evaluation
- Production forecasts and development plans
- Refurbishment plans
The economic analysis of a proposal to develop or redevelop an oil or gas resource will be based on the approach illustrated schematically below.
Methodology for Economic Analysis
Importantly, the economics review will not be the final stage in the process. Its results will be fed back to the engineering teams in order to refine development plans further to seek a significant improvement in economic performance.
This feedback process will produce the optimum economic production plan for each field.
Capital and operating expenditure will be derived from detailed technical and engineering assessments of individual field rehabilitation options. Base case costs will be determined using applicable contracting strategies and looking at the opportunities for local equipment supply. Similarly, operating costs will reflect the potential for the use of local expertise but will also recognize the trend for labor costs to move towards international levels.
Production profiles and data from the reservoir modeling and analysis will be used as the basis for determining revenues to the project. An assessment of the range of likely oil and gas prices over the project period will be made from reviewing published forecasts. When determining the economics of individual projects a range of price scenarios will be used.
Export Options and Net Back Pricing Analysis
The export of oil and gas to world markets is critical in generating hard currency earnings (both for the project investors and any financing required). Consequently the options for exporting products need to be considered in detail. Where applicable, the feasibility and cost of using various export routes will be considered.
The revenue per unit of petroleum product at the field will not be the same as world market prices because of a combination of transport costs to get the products to market and variations in quality against standard markers. The net-backed value of the petroleum products, at the field, will be calculated using the following data:
- Price of marker product at the transaction date
- New product discount for example, new crudes usually trade at a discount in the first few years of sales as refiners learn about the quality of the blend and variations in quality between shipments
- Cost of insurance and shipment from the exit port to the marker crude point of shipment
- Quality differential
- Trans-shipment charges
- Storage charges
- Pipeline or railway transportation charges
- Duties, taxes, and commissions
The net back analysis will also recognize the change in field revenue as production from the fields increases and alternative transportation options become available. For example, because of low initial production volumes a field may initially have to transport crude by road/rail, here the net back revenue to the field will be low. However, as production increases and pipeline infrastructure becomes available, the products can be transported by pipeline, which is likely to be cheaper than road or rail; hence the net back revenue to the field will increase.
In addition to looking at export markets, the options for selling products locally will also be considered.
As the net back product price is the key revenue driver for any given project it will be one of the key variables in any subsequent sensitivity analysis. For each project option, the break even product price will be calculated.
The net back revenues from oil and gas sales and the phased capital and operating expenditures will be used to build an economic model for each project development plan. Discount rates which reflect the technical and economic risks of the project will be used to calculate Net Present Values (NPVs) and Internal Rates of Return (IRR). Appropriate hurdle rates will also be determined for the screening of field development options.
Costs will be modeled at a sufficient level of detail to allow meaningful development scenarios to be evaluated. Where appropriate, capital costs will be identified by process component or major equipment item to allow the economics of local and international procurement to be investigated. Similarly, operating costs will be split by major operation, i.e. transportation, tariffs, logistics, consumables, etc.
Optimization of Development Plans
If the initial field economics, compared with suitable hurdle rates, indicate low or unacceptable pretax rates of return, the development concept will be reassessed to see if an optimal technical configuration can be obtained. The revised development concept will then be reanalyzed and the economic indicators recalculated. This is an iterative process and will require the technical and economic teams to work closely together. All development scenarios and concepts will be documented such that the learning process can be captured and recorded and the decision-making process highlighted in detail.
In order to confirm the viability of a field redevelopment plan, and its attractiveness to potential investors, it is necessary to demonstrate the robustness of the project economics under differing scenarios that reflect the main areas or risk to the project. Potential areas of vulnerability are:
- Reservoir performance
- World oil and gas prices
- Capital expenditures
- Operating costs
- Export markets
- Transportation costs
- Political factors
The economics of the project will be assessed using risked production profiles (i.e. P10, P50 and P90 values) and using a range of oil and gas price scenarios. The vulnerability of individual field developments to export market availability and transportation costs will be determined by reviewing all of the potential market options and considering the impact of other field developments and the potential impact they could have on factors such as pipeline availability, etc. From this analysis, a range of probable values will be determined and used to calculate expected monetary values for each scenario. The variability of capital and operating costs will be considered through the use of contingencies in the cost estimates. A uni-variate approach will be used to determine the robustness of the project economics to each of the above variables. To determine the key economic drivers and hence the main areas of project vulnerability, each variable will be considered in turn while all other factors are held at the same value. The results from the vulnerability analysis will be compiled in tabular and graphical format with the key drivers suitably highlighted.
As part of the economic assessment, the fiscal framework for each development will be reviewed. Post-tax returns to investors and the government tax take will be determined along with post-tax returns to government and investor. The ability to revise and remodel the main parameters of a production sharing agreement (PSA) is also built into the software used. This will enable a number of tax models to be reviewed to determine the optimum fiscal regime that satisfies both investors and the relevant government.
Sub-surface Data Review and Reserves Evaluation
The reserves evaluation will be performed as part of an integrated sub-surface data review. Depending on the requirements of the project and data availability, the data review may include the following:
- Seismic data
- Geological and geophysical data
- Stratigraphic breakdown
- Porosity analysis
- Permeability prediction
- Saturation distribution
- Porosity/permeability relationships
- Well log data
- Reservoir data
- Production data
- Productive unit delineation
- Reservoir fluids
- Conventional and special core analysis data
- Well test analysis
- Decline curve analysis
- Material balance analysis
- Reservoir simulation models
- Subsidiary issues
- Biostratigraphy, sedimentology, and geochemistry
Seismic data can make a significant contribution to the up-to-date, history-matched, multi-layered simulation model for the reservoir. A reliable structural representation of the reservoir sequences is an essential prerequisite to the building of a reservoir model.
Review of the seismic time maps would take the form of an audit to confirm that contours on the maps equate to correlatable seismic events on the profiles, and that these seismic events correlate consistently to the major litho stratigraphic boundaries with which they are identified (as determined by the vertical seismic profile (VSP) and log data).
It is recognized that the methods used in data acquisition may preclude a detailed reworking of the seismic data. Procedures to achieve a full audit in the presence of good data are:
- Re-calibration of logs: A first step would be to examine the VSP data and sonic logs, digitize or edit as appropriate, and re-calibrate the sonic logs to produce new velocity logs, taking due account of elevation data, static corrections, etc. to achieve a match with the seismic data. The velocity logs would then be used to generate synthetic seismograms using wavelet frequencies appropriate to the seismic data. If seismic trace data is available in SEG-Y format at well locations, relevant traces close to the wellbore can be included in the display panel to facilitate correlation.
- Time maps re-profiled: The next stage would be to capture the time maps in digital form for further study (if time grids are already available this stage is unnecessary). Given a file of shot point locations in digital form, the time grids can be re-profiled along the seismic lines to produce overlays at section scale which should align with the seismic events on the original sections. Alternatively, the events can be loaded directly to a workstation for edit/review if the seismic trace data can also be loaded.
The starting point for a review of depth mapping would be a study of the geophysical report which would accompany such mapping to establish the basis of the technique employed. The team would aim to work closely with local geologists/geophysicists in the velocity studies to benefit from their experience of local conditions and problems.
The review would be made on the basis of:
- Suitability of the overburden seismic mapped events for delineating velocity units
- Basis for prediction of velocity away from well control
- How well the velocity model fits the time/depth curves from the wells
This review should include independent analysis of velocity control.
Recommendations would be made on the basis of time and depth reviews. On the basis of these reviews, recommendations would be made as to the appropriate course to take to achieve acceptable structural control for the remainder of the study. These recommendations could include re-picking/mapping of selected seismic horizons, reevaluating the velocity model and re-mapping in depth, or opting for a full review of basic seismic and well data. The recommendations would be included in the project report to outline potential future programs to obtain improved seismic data.
Geological and Geophysical Data
A database of observed and quantified core, ditch cuttings and log-derived data would be generated provided these data are available. The database would include lithofacies, thin section modal analysis data, diagenetic style, porosity/permeability data, porosity and pore throat types, mercury injection data, and log responses. This database would be used to define a number of characteristic rock types consistently observed through the studied sequences. Rock type definitions would include cross plots and statistical analyses. The purpose of defining the rock types is to attempt to identify particular reservoir characteristics associated with key surfaces on a regional scale.
Reservoir layering will be achieved by inputting the rock type classification into the sequence Stratigraphic framework. Each layer would then be characterized in terms of thickness, rock type, porosity/permeability, water saturation (Sw), and shale volume (Vshale).
If the data quality is only sufficient to support a lithofacies correlation based on electric wireline log interpretation and mud logs, the database would be populated with this subset of information as input to the reservoir modeling
The existing petrophysical analyses would be studied for use in the reserves and reservoir study phases. If suitable for further use, the current interpretations would be carried through with appropriate quality checks. If the data require reinterpretation, cored wells would be used to develop a robust field-wide petrophysical model of apparent log responses to analyze the logs for porosity, lithology, and fluid content. If necessary, alternative models for wells where hole conditions are poor may be developed. Computer processed interpretations already run will be used as reference for the components to be put into the model.
In low porosity zones, or zones with significant secondary porosity, the Archie equation parameters 'a', 'm' and 'n' are likely to vary. Correlations between core derived parameters and logs would be used to establish predictive relationships to model these parameters in uncored wells. The precise method would be decided after studying the core and log data.
The model developed from the cored wells would be used to analyze the logs of the remaining uncored well and uncored intervals. Following application of the petrophysical model, a check would be made to determine if the resulting distributions of porosity and lithology are in agreement with the geologist's interpretation of the sedimentary processes.
Accurate permeability prediction is very important and is a prerequisite for computing meaningful averages (such as permeability thickness). All available permeability information would be integrated and weighted for importance. If the data permits, transformations would be derived for derivation of permeability from uncored and untested formations. The geological model developed for the field would be used as a guide for areal mapping of the permeability.
Net/Gross cut-offs will be determined using a combination of computer processed interpretation (CPI) log data, conventional and special core analysis (SCAL) data, and facies analysis. Petrophysical sums and averages will be determined over net pay.
Before carrying out any work with capillary pressure, or indeed SCAL data, it would be necessary to establish if the SCAL data set is representative of the logged intervals. It is sometimes found that SCAL data sets are biased towards better or worse quality rock than the reservoir as a whole. Appropriate data would be identified and used in the reservoir evaluation.
Conventional core analysis results are the basis for predictions of permeability from porosity. However, secondary porosity lowers the permeability associated with a given total porosity so, given a sufficiently large data set, it should be possible to develop predictive tools to yield a quantitative or semi-quantitative secondary porosity index.
To this end, a review of all available geological core descriptions, petrographic data, and petrological interpretations would be undertaken and a standard lithofacies scheme confirmed or established. Through cross plotting and statistical analysis of the lithofacies codes, petrographic data, and core analysis data the primary facies, diagenetic, and fracture controls on reservoir quality will be defined and the porosity/permeability relationships established for the reservoir.
Core analysis results would be carefully related to lithofacies in order that a predictive model may be established for use in peripheral parts of the field, where well control is not available.
Well Log Data
Available well log data would be used to establish a log database that can be used for petrophysical analysis, geological interpretation, and synthetics generation. Data preparation would involve:
- Log Quality Control (LQC): This may be required at more than one stage in an evaluation since some anomalous responses may only come to light after log interpretation or geological correlation. The existing interpretations would be reviewed for consistency and accuracy of interpretation, with particular emphasis on generation of control data for the volumetrics calculations and the simulation inputs.
- Review of Core Analysis Reports: This will establish the consistency of laboratory preparation technique and relationships between porosity, permeability and grain density.
- General Review: Analysis of stratigraphic, biostratigraphic, sedimentological, and depositional environment studies.
The latter two components will largely involve integrating the existing data and interpretations to ensure consistency.
Where appropriate, available oil, water, and gas production data, on a well and reservoir zone basis, will be compiled into a database. Other time-dependent data, for example, recorded oil and gas gravities, water salinity, tubing head pressures etc. will also be incorporated into the database.
The available data will be evaluated and assessed for suitability for use in reservoir simulation models, and where appropriate, classical material balance. The use of a database such as Microsoft Access will enable the efficient filtering and processing of data from individual reservoir zones in addition to the per well analysis envisaged.
Trends in well performance will be sought to identify key "swing" producers in a field for targeting of possible remedial work in the outline development plan.
Productive Unit Delineation
The data from all sources: geophysical, geological, petrophysical, reservoir, and production disciplines will be integrated to define the main productive units in a field. A productive unit is defined as a discrete carbonate or sand unit which is in pressure communication throughout its areal extent. These will form the basis for the construction of classical reservoir engineering models of the reservoirs and fields. Data will be history matched on a productive unit basis in the models.
Available reservoir fluid property analyses will be studied to generate input data for material balance, petrophysics, or reservoir simulation. Areal or vertical variations in oil composition and/or properties will be investigated. Historical data from producing wells will be reviewed to derive variations in well stream properties with time. Future production problems associated with fluid compositions would be highlighted. Suitable software packages would be utilized in this evaluation.
The suitability of temperature information for integration to yield reservoir temperature profiles for simulator input would be assessed.
Weatherford's staff have considerable expertise in the collection, analysis and interpretation of PVT data, and in the modeling of such data for simulation.
Special Core Analysis Data
Available core data will be screened for use in the study. If possible, appropriate measured rock compressibility will be chosen for input to the material balance and possible reservoir simulation models. Core data and log data will be reconciled where possible by choosing wells with the most comprehensive suite of data for the validation. Parameters available from both core and electric wireline logs will be compared to achieve a consistency of interpretation within the limitations of the available data.
If SCAL data are available, these will be screened for validity. Spreadsheet evaluation of the data will be the major tool for the critical review; consistent interpretation of the data will be ensured with other sources of information, for example, electric wireline log interpretation. Much of the SCAL data which are acquired even using reputable core analysis contractors is in many cases suspect and of limited use due to poor understanding of the influences on the results or poor experimental procedures. Sensitivities may therefore be required to assess the influence of relative permeability curve shapes, capillary pressure curves, endpoint saturations, etc. to test the robustness of future development plans to the data uncertainty.
If capillary pressure data are available, these will be evaluated to derive Sw as a function of height above free water level (FWL). These data would be required for volumetric studies and for use in reservoir simulation studies where appropriate. Transition zone lengths will be determined from the capillary pressure curves and the information used to aid the evaluation of the reservoir.
If relative permeability data are available, these will be assessed for validity of measurement technique and appropriateness for the reservoir conditions. If a representative set of relative permeability can be derived, fractional flow plots will be constructed.
Well Test Analysis
If there are well tests available with bottom hole pressure information, these will be reviewed to ensure consistent and appropriate analysis has been performed on the data to yield sound conclusions. If necessary and feasible, a subset of these could be reanalyzed if problems were identified in the review phase. The review/reanalysis would use the industry standard PanSystem® software well test analysis package developed by Weatherford and would be targeted on those wells having the most complete data set for review. An interpretation consistent with the geological understanding of the depositional environment and the petrophysical analysis of the available logs would be achieved if possible, and the calculated permeability compared to the core analysis results if appropriate. If sufficiently robust analysis is possible with the available data, conclusions regarding the presence of reservoir barriers and baffles will be drawn: e.g. distances to nearby faults, channel presence, interlayer communication, etc. However, the quality of pressure gauge data is crucial to an accurate analysis and if only mechanical pressure gauge data are available (e.g. Amerada charts) then the results obtained from these analyses may be qualitative rather than quantitative. As the leading well test analysis consultancy company in the world, with industry experts in the analysis of tests, Weatherford will ensure that the maximum value will be extracted from any test data available.
Decline Curve Analysis
Available well production data will be analyzed by the methods of decline curve analysis (DCA). DCA provides a methodology for predicting the future performance of a well by analysis of past behavior and extrapolation of producing trends. The data will be reviewed and screened to derive the most appropriate DCA method to use. i.e. which variables can be used to predict most accurately future behavior, e.g. water cut versus cumulative oil production, and which equation best describes the observed decline. The analysis will be performed either using a spreadsheet (Microsoft Excel) analysis or using a software package such as Schlumberger GeoQuest's Production Analyst. (note that this is an alternative to forward prediction with a numerical reservoir simulator and often is not needed for good quality data sets)
The classical reservoir engineering tool of material balance will be used where appropriate to analyze the reservoirs to yield appropriate values of the connected hydrocarbon volumes. Material balance relates the volumetric changes within the reservoir under the pressure reduction due to production, to the observed surface volumes. The more accurately the basic data (fluid and rock properties) are known, the more accurate will be the results obtained from the material balance calculation. Uncertainties in system compressibilities, or in the behavior of the fluids under the pressure reduction will translate directly into uncertainties in the implied volumes from the material balance. Production allocation will be required to assign the fluid withdrawals correctly to the various reservoirs to allow the material balance predictions to be accurate. Reservoir drive indicators will be calculated from the material balance equations and the main sources of reservoir energy identified. Values for the in-place volumes calculated from material balance will be compared to the volumetric estimates obtained from the geological and petrophysical maps. Gross discrepancies identified by these comparisons will be addressed to ensure that a consistent reservoir model is obtained prior to further study.
Reservoir simulation is a significant skills area in Weatherford. Many Weatherford engineering staff members have performed black oil and compositional simulation on homogeneous reservoirs. Local knowledge is also important and several Weatherford's staff have performed simulation studies of fields in a wide range of major oil provinces. Simulation can be performed with the simulator preferred by the client, although most studies by Weatherford's staff have been performed using ECLIPSETM and the company has licensed this software for its use.
Weatherford can take existing reservoir simulation models and update the history match, or develop a new model. Extensive experience in the use of such applications mean that this process can be performed efficiently and reliable results generated in minimal time.
Accurate use of numerical reservoir simulation relies on sound basic data. Errors and uncertainties in the volumes of fluids produced, the basic rock and fluid properties, and the pressures measured in the reservoir unit under consideration translate into uncertainties in the connected volumes and drive strength indicators. Careful assessment of the quality of the input data will be performed prior to undertaking detailed numerical reservoir simulation to ensure that sufficient accuracy can be achieved during the matching phase. The methods and equipment used to measure the data will be examined and, where necessary, recommendations made to increase the data quality to assist future development of the field.
During the development of the reservoir models it is possible that biostratigraph and geochemistry issues may arise and may be usefully investigated. The actual extent of the work to be carried out will depend on the quality of data available.
Production Forecasts and Development Plans
Production forecasts will be made based on the results of numerical reservoir simulation or material balance studies. The individual productive unit forecasts will be integrated into a field wide development and exploitation plan for each field.
Optimized Production Plan
An optimized production plan will be developed for each field or resource. The development plan will be designed to deplete the economically recoverable reserves, including those which do not appear to be drained by existing wells, as efficiently as possible. Areas of the productive units which do not appear to be drained by existing wells will be identified, and locations of additional wells to recover these reserves will be proposed.
An assessment of the opportunities to increase the proven reserves of each field will be made by indicating the additional areas of probable and possible reserves which are likely to be present around the margins of the field, in deeper reservoirs, and on separate adjacent structures. A drilling program to explore for or delineate these additional non-proven reserves will be designed.
Utilization of Existing Wells and Production Infrastructure
The purpose of this stage of the work will be to determine which of the existing wells and infrastructure are most efficiently used in the development of each field. Where appropriate, proposals for new wells and facilities, and proposals for wells and facilities to be abandoned will be made. Work plans will be developed for each type of activity required to implement each part of the field's redevelopment plan.
Drilling of Additional Wells
A work plan will be developed for the drilling of new production and injection wells in addition to delineation and exploration wells. A drilling and completion program for each well will be developed utilizing the appropriate modern technology.
Reuse of Existing Wells
The optimized production plan will include a recommendation for the use of existing wells, and, where appropriate, will recommend a workover plan for wells where this is indicated as beneficial by economic analysis. Where possible, multiple completions which allow separate reservoirs to be produced independently, will be included, as will gas and water injection wells to improve recovery.
Use of Existing Infrastructure
The optimized production plan for each field will be compared with the existing infrastructure to establish which platforms and associated infrastructure will be retained. Platform survey results and existing documentation on the facilities will be reviewed to establish remediation work required to improve status to recognized international standards of safety and utility. API standards supplemented by appropriate BSI, ISO, ASME, Institute of Petroleum, ISA, N-FPA, TEMA, and AISC standards will be used as the benchmark.
A work plan will be developed for the remediation activity. This will include the equipment required and suitable sources of this equipment. Where equipment cannot be soured locally, this will be indicated and costs and preferred routes of importation will be established.
New Infrastructure Work Plans
The requirement for new infrastructure for each field will be established through review of the optimized production plans and a survey of the local capability to support this requirement will be made. With this basis, preliminary designs of new facilities will be developed along with a work plan for their installation. Designs will be carried out to recognized international standards (API standards supported by other appropriate standards will be used as the benchmark).
The new infrastructure work plan will be combined with the drilling plan to provide a consolidated work plan for installation of the new infrastructure.
Well Abandonment Plans
A work plan will be developed for the abandonment of the wells not required by the optimized production plan for each field. Preliminary designs will be developed for well abandonment, the recovery of surplus equipment, including mechanisms for its salvage, refurbishment, reuse or scrapping.
Removal of Surplus Facilities
A work plan will be developed for the removal of infrastructure that is not required for the optimized production plan for each field or is irreparably damaged. Preliminary designs for facility removal will be developed including reduction for scrap, transportation site and mechanisms to achieve partial cost recovery.
Health, Safety, and Environment Assessment
An assessment of potential health, safety and environment (HSE) factors relevant to each project would be made. The assessment will be based on the following approach:
The policy will be to ensure that in carrying out its business operations, all employees are aware of the importance of health, safety, and environmental issues where such issues are relevant. Health, safety, and environmental issues will be treated with the same degree of importance as other considerations.
Organization, Responsibilities, Standards, and Documentation
The implementation of any work would be carried out under the supervision of a project leader who has overall responsibility for their satisfactory completion and all health, safety, and environmental considerations. All design work will be carried out by suitably qualified and experienced engineers who will perform work to meet the relevant standards. The standards used in engineering studies are those recognized by the international oil and gas industry, such as API, BS, and IP Codes and the relevant HSE considerations within them.
Engineering projects are fully documented and where HSE considerations are required to be included, the approach used and the results of any study made will be fully documented.
The provision of engineering design services will include the following approach:
- Identification of potential hazards
- Assessment of likelihood of occurrence
- Assessment of consequences of occurrence
- Identification of methods to avoid or reduce hazard
- Identify control measures to limit impact of hazard
- Identify recovery measures should those controls fail
The preferred hierarchy in the incorporation of HSE into design and engineering is:
- Elimination of the hazard (e.g. by substituting non-hazardous processes, chemicals, etc.)
- Incorporate inherent safety into design (e.g. by selecting a design pressure for a pressure vessel in excess of the maximum achievable pressure)
- Process control systems
- Process safeguarding systems
- Procedural controls
Planning and Procedures
In planning the HSE requirements of individual projects, the following requirements are followed:
- The relevant regulatory and legal HSE requirements
- The client's specific project HSE instructions
- The relevant industry standards and codes of practice
All procedures will be implemented with the objective of reducing environmental contamination to an economic minimum.