Dmitrii, Smirnov (Petroleum Development Oman) | Aisha, Sariri (Petroleum Development Oman) | Mutasem, Abri Al (Petroleum Development Oman) | Tushar, Narwal (Petroleum Development Oman) | Fakhriya, Shuaibi (Petroleum Development Oman) | Riyami, Yaqoob (Petroleum Development Oman) | Zahir, Abri (Petroleum Development Oman) | Al-Hadhrami, Abdullah (Petroleum Development Oman) | AL-Yaarubi, Azzan Hamed (Schlumberger) | Habsi, Yumna Rashid Al (Schlumberger)
In the past 20 years, there has been a string of exploration successes in newly discovered oil-bearing carbonate reservoirs within the South Oman Ara salt basin. These oil reservoirs are deep (3000–5000 m), encased by salt, and have high reservoir pressure far above the hydrostatic gradient. The crude is light (30–45 API gravity) and contains 5–17% CO2 and 2–6% H2S. Reservoir properties are relatively poor: average porosity varies from 5 to 10%, and permeability varies from one to several tens millidarcy. The primary recovery mechanism is pressure depletion, with low recovery in the range of 4–8%.
Enhanced oil recovery (EOR) by means of immiscible gas injection (GI) was implemented in Field-B in 1993, and miscible gas injection (MGI) was started in Field-Z in 2012. The MGI program is expected to increase the ultimate recovery up to 45%. The main subsurface risks to the performance of the gas injection projects include vertical and areal conformance, gas breakthrough, and reservoir pressure decline. The key objective of the MGI surveillance is to establish residual oil saturation in gas-flooded rock. The key issues and challenges for the surveillance include low porosity, complex drilling operations, well design, and completion.
The well and reservoir surveillance management (WRM) activities included the drilling of a dedicated monitoring well, collection of various pressure measurements, injection of tracers, and acquisition of advanced openhole and casedhole data, which included nuclear magnetic resonance (NMR), pulsed neutron logging (PNC), and production logging (PL). The primary focus of this active WRM plan is to monitor the performance of the GI and MGI. The plan has been successfully implemented.
We present examples of reservoir surveillance data, such as the molecular diffusion-sensitive NMR and enhanced PNC data acquired in Field-B and Field-Z. The objectives of these measurements are to monitor the current oil saturation and detect and evaluate gas breakthrough. The static downhole pressure survey and formation pressure measurements were collected in newly-drilled infill wells. The PL and tracer survey data effectively provided information about gas breakthrough intervals and enhanced the understanding of the impact of vertical and lateral heterogeneity. This data is also useful for planning gas shutoff when the breakthrough is detected.
The applied surveillance strategy supports Field-Z and Field-B gas injection performance. The strategy can potentially benefit other analogue fields undergoing similar development options to reduce subsurface risks, proactively recognize problems, and devise effective mitigation actions.
There has been recognition in the oil and gas and mineral extractive industries for some time that a set of unified common standard definitions is required that can be applied consistently by international financial, regulatory, and reporting entities. An agreed set of definitions would benefit all stakeholders and provide increased - Consistency - Transparency - Reliability A milestone in standardization was achieved in 1997 when SPE and the World Petroleum Council (WPC) jointly approved the "Petroleum Reserves Definitions." Since then, SPE has been continuously engaged in keeping the definitions updated. The definitions were updated in 2000 and approved by SPE, WPC, and the American Association of Petroleum Geologists (AAPG) as the "Petroleum Resources Classification System and Definitions." These were updated further in 2007 and approved by SPE, WPC, AAPG, and the Society of Petroleum Evaluation Engineers (SPEE). This culminated in the publication of the current "Petroleum Resources Management System," globally known as PRMS. PRMS has been acknowledged as the oil and gas industry standard for reference and has been used by the US Securities and Exchange Commission (SEC) as a guide for their updated rules, "Modernization of Oil and Gas Reporting," published 31 December 2008. SPE recognized that new applications guidelines were required for the PRMS that would supersede the 2001 Guidelines for the Evaluation of Petroleum Reserves and Resources. The original guidelines document was the starting point for this work, and has been updated significantly with addition of the following new chapters: - Estimation of Petroleum Resources Using Deterministic Procedures (Chap.
Hinai, Nasser. M. Al (Department of Petroleum Engineering, Curtin University, Commonwealth Scientific and Industrial Research Organization, Australia, Petroleum Development Oman L.L.C.) | Saeedi, A. (Department of Petroleum Engineering, Curtin University, Commonwealth Scientific and Industrial Research Organization, Australia, Petroleum Development Oman L.L.C.) | Wood, Colin D. (Department of Petroleum Engineering, Curtin University, Commonwealth Scientific and Industrial Research Organization, Australia, Petroleum Development Oman L.L.C.) | Valdez, R. (Department of Petroleum Engineering, Curtin University, Commonwealth Scientific and Industrial Research Organization, Australia, Petroleum Development Oman L.L.C.)
Field A, located within the Harweel cluster in southern Oman, has been recognised as a viable miscible gas injection candidate. However, the mobility ratio of such a flood is unfavourable due to the low viscosity of the injected gas (0.01 to 0.04 cP) as compared to that of the in-situ oil (0.24 cP). One approach to overcome this issue is to thicken the injected gas to effectively control the gas mobility and increase the sweep efficiency.
This study will present the details of a numerical reservoir simulation study, which assesses the potential benefits of adding polymers to the injected gas to increase the viscosity. Considering the composition of the AG in Field A, we have examined a number of different AG compositions to include different levels of hydrocarbon gas and CO2. We have also evaluated the direct effect of the different gas compositions on the oil properties during the flood.
The simulation was carried out using CMG-GEM and the associated PVT module CMG-WinProp. A full-field 3D geological model has been built based on the typical geological characteristics and the light oil fluid properties in Field A. The simulation model takes into account the reservoir heterogeneities and future design considerations of the enhanced oil recovery (EOR) project to be implemented in the field.
The results confirm that increasing the injected gas viscosity close to that of the oil has a significant effect on the gas mobility, time of breakthrough and the ultimate recovery in Field A. It has also been observed that the oil viscosity reduction with natural gas dissolution is much more pronounced than that achieved with the pure CO2. Such an effect resulted in 4% higher oil recovery by the injection of thickened natural gas (76%) than the thickened pure CO2 (72%). Furthermore, bacause gas breakthrough is delayed, a low gas-oil ratio can be maintained during the injection. These results demonstrate the real advantages of thickening the natural gas over CO2 for improving the gas flood efficiency in a light oil reservoir such as Field A.
The contribution of this study is significant considering the fact that to date there have been limited studies evaluating the effect of thickened natural gas for EOR. Most of the previously completed research work in this area have mainly focused on the identification of thickener polymers for CO2 injection processes.
CO2 can be an effective EOR agent and is the dominant anthropogenic greenhouse gas driving global warming. Capturing CO2 from industrial sources in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future, by adding value through EOR production and field life extension, and providing long term secure storage post-EOR operations.
Shell is working to implement new generation CO2 projects, including offshore applications. Based on recent offshore project design experience, this paper describes the challenges in moving CO2 EOR from onshore to offshore and the solutions developed, in the key areas of safety, facilities, wells, subsurface and piloting. The overriding design principle in any project is HSE. Offshore operations brings a new set of challenges over inventory, pressure, confined spaces and evacuation, with conventional emergency procedures requiring modification because of the different physical characteristics of CO2 releases compared to hydrocarbon gas. Surface facilities need to be simple to minimise CAPEX, weight and space while maintaining flexibility, since there is less scope to incrementally evolve the surface facilities as is the case onshore. Balancing the tension between these objectives requires very close surface and subsurface integration to find optimal and cost-effective solutions.
This is illustrated with three key decision areas: gas treatment options for back produced CO2 and hydrocarbon gas, artificial lift and facilities capacity.
A novel integrated CO2 gas lift system is described. This simplifies facilities and reduces CAPEX and OPEX, while at the same time providing a high degree of flexibility and risk management over the EOR life cycle in terms of subsurface uncertainty and reducing the issues around molecular weight variation in the recycled gas and the degree of turndown required in the facilities in the early years of EOR operations.
CO2 is the dominant anthropogenic greenhouse gas that is believed to be driving global warming and climate change. Carbon capture and storage (CCS) is a technology that may contribute to reduction in CO2 emissions. However, CO2 capture from flue gas sources with current technology is CAPEX and energy intensive, so that the cost of CO2 abatement with CCS is high.
At the same time CO2 is an effective miscible flooding agent for EOR. Capturing CO2 from industrial sources for use in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future. Firstly, by adding value through additional oil recovery and field life extension, which can offset part of the cost of CO2 capture, and secondly, by providing long term secure storage after EOR operations have been completed.
Moving from onshore to offshore
Existing CO2 EOR projects are all onshore, with the majority of projects supplied with CO2 from natural subsurface sources. A minority of projects is based on captured CO2 from anthropogenic sources, with the largest being the Weyburn CO2 EOR and storage project, using CO2 captured from a coal gasification plant . Operating offshore CO2 injection has so far been restricted to storage of CO2 produced from gas processing plants, with the Sleipner  and Snøhvit  projects each injecting around one million tpa of CO2. Maximising value from disposal of CO2, (whether this is from low cost sources such as gas processing plants or more expensive flue gas capture) requires suitable EOR target fields, and in regions such as Europe and the Far East, large scale operations require moving CO2 EOR offshore into the major hydrocarbon basins.
The majority of enhanced oil recovery (EOR) projects are being executed in the the U.S., Canada, Venezuela, Indonesia and China. The volume of oil produced by EOR methods increased considerably from 1.2 MMBD in 1990 to 2.5 MMBD in 2006 (Sandrea and Sandrea 2007). Current total world oil production from EOR is approaching 3 MMBD representing about 3.5% of the daily global oil production (Sandrea and Sandrea 2007). Thermal and CO2 methods are the major contributors to EOR production, followed by hydrocarbon gas injection and chemical EOR. Other more esoteric methods, e.g., microbial, have only been field tested, without any significant quantities being produced on a commercial scale. In recent years, the number of EOR projects has increased with escalating oil prices.
The number of EOR projects in the Middle East (ME) has also increased over the past decade. In some countries like Oman, there has been no choice but to implement EOR projects aggressively due to dwindling ?easy oil.? Other countries in the region have also started to think EOR, and are including them in their strategic short-, medium- and long-term development plans. Furthermore, there are many projects on the drawing board and appropriate screening studies and EOR pilots are being pursued region-wide. This paper reviews the current ME EOR projects from full-field development to field trials, including those on the drawing board. The option of advanced secondary recovery (ASR) — also known as improved oil recovery (IOR) — technologies before full-field deployment of EOR is also discussed. A case is made that they are a better first option before deployment of capital-intensive EOR projects. The ME‘s general drive towards ?ultimate? oil recovery — instead of immediate oil recovery — is highlighted in the context of EOR. Some of the enablers for EOR in the ME are also discussed in the paper. It highlights the opportunities and challenges of EOR specific to the region.
SPE, _ (Society of Petroleum Engineers) | AAPG, _ (American Association of Petroleum Geologists) | WPC, _ (World Petroleum Council) | SPEE, _ (Society of Petroleum Evaluation Engineers) | SEG, _ (Society of Exploration Geophysicists)
Society of Petroleum Engineers (SPE)
American Association of Petroleum Geologists (AAPG)
World Petroleum Council (WPC)
Society of Petroleum Evaluation Engineers (SPEE)
Society of Exploration Geophysicists (SEG)
1.1 Rationale for New Applications Guidelines
SPE has been at the forefront of leadership in developing common standards for petroleum resource definitions. There has been recognition in the oil and gas and mineral extractive industries for some time that a set of unified common standard definitions is required that can be applied consistently by international financial, regulatory, and reporting entities. An agreed set of definitions would benefit all stakeholders and provide increased
A milestone in standardization was achieved in 1997 when SPE and the World Petroleum Council (WPC) jointly approved the “Petroleum Reserves Definitions.” Since then, SPE has been continuously engaged in keeping the definitions updated. The definitions were updated in 2000 and approved by SPE, WPC, and the American Association of Petroleum Geologists (AAPG) as the “Petroleum Resources Classification System and Definitions.” These were updated further in 2007 and approved by SPE, WPC, AAPG, and the Society of Petroleum Evaluation Engineers (SPEE). This culminated in the publication of the current “Petroleum Resources Management System,” globally known as PRMS. PRMS has been acknowledged as the oil and gas industry standard for reference and has been used by the US Securities and Exchange Commission (SEC) as a guide for their updated rules, “Modernization of Oil and Gas Reporting,” published 31 December 2008.
SPE recognized that new applications guidelines were required for the PRMS that would supersede the 2001 Guidelines for the Evaluation of Petroleum Reserves and Resources. The original guidelines document was the starting point for this work, and has been updated significantly with addition of the following new chapters:
Estimation of Petroleum Resources Using Deterministic Procedures (Chap. 4)
Unconventional Resources (Chap. 8)
In addition, other chapters have been updated to reflect current technology and enhanced with examples. The document has been considerably expanded to provide a useful handbook for many reserves applications. The intent of these guidelines is not to provide a comprehensive document that covers all aspects of reserves calculations because that would not be possible in a short, precise update of the 2001 document. However, these expanded new guidelines serve as a very useful reference for petroleum professionals.
Chap. 2 provides specific details of PRMS, focusing on the updated information. SEG Oil and Gas Reserves Committee has taken an active role in the preparation of Chap. 3, which addresses geoscience issues during evaluation of resource volumes. The chapter has been specifically updated with recent technological advances. Chap. 4 covers deterministic estimation methodologies in considerable detail and can be considered as a stand-alone document for deterministic reserves calculations. Chap. 5 covers approaches used in probabilistic estimation procedures and has been completely revised. Aggregation of petroleum resources within an individual project and across several projects is covered in Chap. 6, which has also been updated. Chap. 7 covers commercial evaluations.
Chap. 8 addresses some special problems associated with unconventional reservoirs, which have become an industry focus in recent years. The topics covered in this chapter are a work in progress, and only a high-level overview could be given. However, detailed sections on coalbed methane and shale gas are included. The intent is to expand this chapter and add details on heavy oil, bitumen, tight gas, gas hydrates as well as coalbed methane and shale as the best practices evolve.
Production measurement and operations issues are covered in Chapter 9 while Chapter 10 contains details of resources entitlement and ownership considerations. The intent here is not to provide a comprehensive list of all scenarios but furnish sufficient details to provide guidance on how to apply the PRMS.A list of Reference Terms used in resources evaluations is included at the end of the guidelines. The list does not replace the PRMS Glossary, but is intended to indicate the chapters and sections where the terms are used in these Guidelines.
HSE challenges are substantial in sour gas projects; the poisonous nature of H2S introduces the risk of a toxic release with potential to cause multiple fatalities both inside and outside the site boundary.
Learning from recent sour projects emphasises a "keep it in the pipe" philosophy: appropriate materials selection, use of high-integrity components for facilities, wells and flow lines, and removal of as many leak sources as is practicable. Effort is also required to reduce personnel exposure, either through minimum intervention / minimum manning, or by spacing facilities to minimise the impact of a toxic cloud. However, the implementation of these apparently simple elements involves a complex balance of HSE goals against operability, maintainability, availability and Capex/Opex targets. Conflicting factors include:
• Very high costs associated with corrosion-resistant materials.
• Potential maintainability / operability hindrance associated with removal of leak sources (valves, flanges, instrumentation).
• Availability losses imposed by prohibiting online maintenance (forcing turnaround maintenance shutdowns).
• Costs and operability difficulties associated with large-scale plant spacing.
The solution lies in a design that optimises these elements to achieve risk levels that are as low as reasonably practicable, or ALARP. In doing so, it is important that the HSE Risk Assessment methodology aligns with the Reliability, Availability and Maintainability (RAM) premises, and that both are underpinned by the Operations Philosophy. This critically requires Operations input from a very early stage of the project.
Emergency Response capability also needs to be considered early in sour projects, since this too will underpin fundamental design and Operations Philosophy decisions such as layout spacing and requirements for cascade air systems and safe refuges. As a result, H2S release detection mechanisms; personnel H2S response training and respiratory protective equipment will also play a critical role in the ALARP demonstration.
Critically, Sour Gas developments should take an asset lifecycle view to understand the feasibility of incremental facility changes, field Simultaneous Operations (SimOps) and replacement of aging equipment.
Finally, there must be a consistent and integrated approach to HSE in sour projects all along the value chain, since the chain is only as strong as its weakest link, and there are no second chances with H2S. "Sour Mindset" responsibility must be demonstrated during design, throughout construction and commissioning, and into operations, by both Company and Contractor personnel. Only by this means can ALARP really be achieved.
As a consequence of limited capability for the acquisition, analysis and interpretation of subsurface data, uncertainties pervade the Exploration and Production (E&P) business. To minimise investment risks, robust development plans, premised on adequate understanding of uncertainties, are critical. Experimental Design (ED), complemented with Response Surface Method (RSM), which uses a statistical proxy equation to model the response (dependent variable) as a function of independent variables (uncertainties), is a common method for studying subsurface uncertainties.
In this paper, current applications of ED to subsurface modelling are evaluated from fundamental principles- mathematical and physical consistencies of the proxy equations, as well as robustness in modelling uncertainties. Within the context of modelling and mitigating subsurface uncertainties, major shortcomings of the ED and their implications for decision-making are highlighted. These include inconsistency and non-uniqueness of proxy models, violation of basic theoretical physics, non-preservation of the correlation between variables that are known to be inherently related, non-controllability of input variables, under-estimation of the impact of uncertainties, and the challenge of constructing (interpolating) realistic simulation models from an ED output.
Although ED is consistent with statistical principles, its description of reservoir physics is not satisfactory. In its present form, reservoir complexities are apparently too overwhelming for reliable modelling or optimisation by the proxy models. Consequently, it is recommended that the application of ED be limited to situations where a simple understanding of the effect of a controllable variable on a dependent variable is required, or where the range of uncertainties is well known within a narrow interval. These include production/injection management, ‘model-based' control algorithms for ‘intelligent' completions, business planning and similar areas of the E&P business characterised by continuous data, and where the independent variables could be engineered for the desired objectives.
This paper summarizes parts of the strategies that were developed to demonstrate the feasibility of the first miscible sour gas injection project in one of the reservoirs of a cluster of fields in southern Oman. The hydrocarbons in the cluster are contained in carbonate "stringers??, which are approximately 100m thick slabs of carbonate floating within salt at depths between 2.5 km to 5 km. Large quantities of sour gas with 3-4% H2S and 10-15% CO2 are available to be used as miscible agents. The cluster is developed in a phased manner. The key objective of phase one, producing via primary depletion, was to gather data from a number of different reservoirs to determine whether a miscible gas injection project is feasible. A balance between early delivery of new oil and the complex subsurface appraisal that takes resources & time is necessary. An example of a workflow that led to the construction of static & dynamic reservoir models with different realizations in one of the fields is described. This includes 3D seismic, well test and PVT data, well logs, correlations and interference testing. Advanced technologies have been utilized to monitor reservoir performance from
Phase 1 and to forecast predicted oil recoveries for the miscible gas injection projects. The collection of production data and pressure performance along with appraisal drilling have provided valuable information to allow the reservoir models to be updated. It is illustrated that the emerging data can lead to subsurface concept refinements which have been included in the project design. The subsurface strategies are described as to how the information has been incorporated in the detailed facility design for this first miscible sour gas
injection project in Oman.