"Would you recommend that your son or daughter go into petroleum engineering?"
This is a question SPE presidents and senior executives have been asked for decades and, for most of the last 40 years, the answer has been positive. However, how realistic is a positive response today?
In today's society, negative attitudes toward the extractive industries, and fossil fuels in particular, have made the oil & gas industry less attractive to college students. In addition, this negative opinion has been greatly exacerbated by issues surrounding climate change, not to mention the seemingly constant cyclical demand and massive layoffs during downturns. Factor in the inherent pressure for efficiency, new data-driven approaches and AI-based systems and the future of petroleum engineering looks to be quite different from what has been experienced in the past. In addition, decreasing oil demand in American and Europe may well portend radical changes in how the industry functions.
The objective of this paper is to outline the issues that should be considered and provide guidance on the assessment of reserves and resources in a variety of scenarios where petroleum accumulations straddle licence boundaries.
Petroleum accumulations straddling boundaries are common. Global estimates of the numbers of fields which straddle boundaries vary but run into hundreds or thousands with several countries/basins reported to have up to half of discovered fields straddling at least one boundary.
It is widely recognised that development of oil and gas fields straddling boundaries can be optimised through unitisation. However, less attention has been paid to the assessment of reserves and resources in such situations and how the nature and status of unitisation, or lack thereof, impacts reserves and resources assessment using the Petroleum Resources Management System (PRMS). Even in ideal situations where unitisation has been agreed, the methods and objectives of unitisation and reserves assessment are quite different. Unitisation is typically: based on in-place volumes, considers a single deterministic interpretation, follows specified technical procedures, without consideration of economics and is done at a specified time during a field's life, and may be followed by subsequent redeterminations. Reserves are: remaining recoverable volumes, consider a range of outcomes, do not follow specific procedures, do consider economics and are typically assessed at regular intervals, often annually, throughout a field's life.
The paper will examine a range of scenarios from those where unitisation has been agreed, through those where unitisation is mandated but not yet in place, to those where no unitisation is either in place or mandated. Several factors influence how such situations should be assessed. The status of the field and data on either side of the boundary will be considered including: have wells been drilled on one or both sides? Is production occurring on one or both sides? What consideration should reserves assessors give to scheduled redeterminations where agreements, formulas and outcomes are unknown. There are many cases where production has occurred on both sides and unitisation is required retroactively. Regulatory requirements regarding unitisation vary throughout the world. Where present, regulations often require unitisation to occur, but the practice lags behind the legislation. There are also situations where production has occurred on one or both sides in "rule of capture" scenarios without any requirement or plan for unitisation. Accumulations straddling international boundaries introduce additional factors that should be considered.
Carbon intensity (CI) of oil and gas production varies widely across global oil plays. Life cycle extraction from certain unconventional plays (
We perform well-to-refinery calculations of CI for major unconventional oil plays in North America and conventional plays in Asia Pacific. This approach accounts for emissions from exploration, drilling, production, processing, and transportation. The analysis tool is an open-source engineering-based model called Oil Production Greenhouse Gas Emissions Estimator (OPGEE). OPGEE makes estimates of emissions accounting using up to 50 parameters for each modeled field. This model was developed at Stanford University. Data sources include government sources, technical papers, satellite observations, and commercial databases.
Applied globally, OPGEE estimates show highest values in areas with extensive flaring of natural gas and very heavy crude oils - heavy oils require large energy inputs (
Unconventional production, especially from light tight oil is the most significant new source of fossil fuels in the last decade. Under a wide variety of carbon constraints, oil usage will continue for many decades and increase in the near term. Operators, governments, and regulators need to be able to avoid "locking in" development of suboptimal resources and instead provide incentives for shale operators to manage resources sustainably. This approach provides quantitative measures of such actions. Oil producers must prepare by eliminating development of marginal projects, elimination of flaring and venting, optimizing hydraulic fracture treatments, using improved recovery methods (
Carbon intensity (CI) is a quantitative measure of the carbon generated per unit of energy and is a useful way to compare alternative sources of energy or even various crude oils. The CI of oil and gas production varies widely across global oil plays. Life cycle extraction from some unconventional plays (e.g., tar sands) have some of the highest CIs, but even many North American shale plays have relatively high carbon intensity. Middle East crudes range from some of the lowest to some of the highest global values of CI. Flaring and venting of associated or non-associated natural gas dramatically increases CI.
This paper applies peer-reviewed processes across broad averages of shale activity in North America and compares them with Middle East activity. We perform well-to-refinery calculations of CI for major unconventional oil plays in North America and Middle East major producing countries. This approach accounts for emissions from exploration, drilling and completions, production, processing, and transportation. The analysis tool is an open-source engineering-based model, developed at Stanford University, called the Oil Production Greenhouse Gas Emissions Estimator (OPGEE). OPGEE makes estimates of emissions by using up to 50 parameters for each modeled field. Data sources include government sources, technical papers, satellite observations, and commercial databases.
Applied globally, OPGEE estimates show the highest values are in areas with extensive flaring of natural gas and for very heavy crude oils. Heavy oils requiring large energy inputs (e.g., steam flooding) and/or the use of light hydrocarbon diluents for transportation have much higher values of carbon intensity. Saudi crude production, analyzed from public sources, has some of the lowest CI regionally and globally.
Examples illustrating how OPGEE can be used to evaluate the CI of public policy actions are provided. Further sensitivity analyses to pad drilling and improving well performance are shown, and the CI impacts associated with hydraulic fracturing.
While Middle East crude will remain vital to global supplies, unconventional production, especially from light tight oil (LTO), is the most significant new source of fossil fuels in the last decade. Under almost any conceivable carbon constraints, oil usage will continue for many decades and increase in the near term. Operators, governments and regulators must avoid “locking in” the development of sub-optimal resources and provide incentives for LTO operators to manage resources sustainably. Oil producers must prepare by eliminating development of marginal projects, eliminating flaring, optimizing hydraulic fracture treatments, increasing the use of pad drilling, using improved recovery methods (e.g., enhanced oil recovery using anthropogenic CO2), reducing energy use, and eliminating unnecessary gas waste.
Despite progress made in recent years and efforts of the World Bank-led Global Gas Flaring Reduction Partnership (GGFR), flaring of natural gas continues to be an environmental challenge and a waste of resources. By some estimates, as much as 3.5% of global gas production is flared or vented. In addition to wasting a non-renewable, marketable resource, flaring and venting represent a major source of avoidable CO2 and CH4 emissions that emit excessive amounts of greenhouse gas with no offsetting benefits. In the first half of 2016, Nigeria flared over 3 billion cubic meters (Bcm) (106 Bcf) of gas, with a nominal value of some US$300 MM. Excuses for flaring and venting include the costs of gathering, processing and treating gas, and the lack of infrastructure and access to funds to develop and deliver the gas into viable markets. Some financial terms for Production Sharing Contracts (PSCs) or other contracts, and low regulated gas prices, fail to properly encourage gas use. Sour gas or gas with high levels of non-hydrocarbon diluents, though not applicable to Nigerian gas, further complicates commercialization. A lack of collaboration between operators and regulators also contributes to improper development planning. Retrofitting costs and mature fields further complicate gas use.
The potential to monetize an ever increasing portion of flare gas in Nigeria has many positive benefits, including improving the environment for those living in proximity to oil and gas operations; both savings and new revenues for project sponsors; greater certainty for lenders, and the potential substitution of expensive and polluting diesel-powered applications.
Flaring and venting gas should be infrequent, brief and efficient. This paper presents a variety of ways to monetize small to medium volumes of gas, along with ways to minimize flared and vented gas. The relative volumes of gas required for a wide range of applications are reviewed, including distributed power, CNG, methanol or other GTL, mini- and micro-LNG, and other emerging technologies.
Duncan, A. B. (Gaffney, Cline & Associates)
To make informed decisions; Natural Gas resource holders, investors, regulators, and other project proponents need an understanding of the nature, costs, and cost drivers of Floating Liquefied Natural Gas (FLNG) technology. There is currently a wide range of FLNG projects under consideration, in construction, or in commissioning, yet the available public domain information suggests there are considerable variations in understanding the scope, costs, and cost drivers of these projects. This paper provides a brief review and analysis of public domain information, focusses on the cost drivers of an FLNG facility, and proposes a "screening" level approach to integrate FLNG costing into an overall field development costing.
Wilson, Séadhna (Gaffney, Cline & Associates)
At any stage of the Exploration and Production cycle decisions must be made with limited information. This situation can always be improved by investing more money or time in improving the quality and variety of information available. However, this in itself presents a decision as to whether the investment to get new information such as a new seismic survey is worth it. This paper outlines a practical and structured method to estimate the value of new information in monetary terms, which can be used to make an informed business decision on whether the new information is worth it.
The method is comprised of two primary elements. Firstly the problem is defined using a decision tree analysis approach that considers what decisions are to be made and their possible outcomes. Secondly, a collaborative workshop is used to estimate the probabilities required to populate the decision tree. This then enables the Expected Monetary Value to be calculated both with and without the technology that acquires the new information. The difference between the two is approximated as the value of the information. This paper uses a case study approach to explain this method that considers an operators dilemma in deciding whether or not to drill an appraisal well.
Obtaining a meaningful result from this process requires time and commitment from management and technical staff. However, at stake are the considerable sums of money in acquiring the new information and the subsequent investment decisions that draw on the new information. The method described as a minimum provides fiscal information to make investment decisions and at best, provides a framework in which the benefits and risks of investing in new technology can be fully understood.
There has already been much published on the use of decision trees to estimate the value of information. However, in practice it can be difficult to estimate the probabilities required for a decision tree analysis to work as they are not intuitive to describing the situation. This approach simplifies this by arranging the mathematics to make the task of the workshops clearer and more achievable. The result is a practical method that can be easily understood and implemented.
North American shale oil producers find themselves in the spotlight. Before 2015, much focus was placed on the miraculous growth of U.S. crude production, which ramped up by 1 million barrels per day (MMBbl/d) every year for five consecutive years, a phenomenon often characterized as the shale boom. But, heading into 2015, these same producers were hit particularly hard by the sharp and rapid decline in crude oil prices. In an attempt to better understand how North American production has reacted to the fall of oil prices, this paper begins with a high-level overview of the key value drivers behind the shale boom. It aims to explain how past drilling activities, ongoing rig count changes and drilled but uncompleted wells influence current and future shale oil production. Although the dynamics of crude supply and demand are highly unpredictable, this paper identifies underlying themes in the North American oil and gas industry that continue to prevail during a highly volatile market.
Discover a Career
If I had a time machine, would I travel back in time to change anything if I could do it again? Should I have taken that job offer as a public relations guy on a treasure-hunting dive boat in the Philippines? No, I do not think so. All experience makes us who we are, and some say they would not change a thing. On the other hand, if I have to change one thing I would have striven harder to learn the languages of the countries in which I have previously worked and would recommend the same to anyone with similar opportunities. I also recommend pursuing variety in one’s career. Change brings opportunities and challenges. Only through change, is progress possible.
When I was growing up in northern Canada, we were offered career advice in high school to learn a trade and work as a welder, truck driver, or get a job on the rigs. I did not feel these career options suited me as I was thinking in terms of further education and I have always enjoyed traveling. Hence, weighing both of these, I decided to pursue a university degree abroad. Since then, I completed my university studies, joined the oil and gas industry, and have enjoyed a diverse career overseas.
Throughout my career transitions, maintaining objectivity has been the most recurring challenge I have dealt with. Through experience, I have learned an important rule when it comes to expatriate life (which applies equally to other career transitions): Never make career-altering decisions in the first 6–12 months after moving to a new country or taking up a new role. It is human psychology to feel excited and motivated about any new location or job immediately after arrival. However, after about 6 months a period of negativity (or reality) sets in and one begins to see only the downside of a new position or new location. My experience suggests that the period of negativity does pass, and when it does, the experience can be truly objective—bringing the positive and useful aspects of past experience to bear while learning and experiencing the best that a new role has to offer.Over my career, I have gained a lot through changes in my role, career path, or location. Changes in setting can often provoke one to become more open, a better listener, and more patient. I have learned the importance of clear communication and that “communication” involves explaining, listening, and confirming that both parties truly understand both directions.
Gross rock volume is typically the biggest uncertainty in volumetric estimation, especially early in field life. Assumptions about fluid contacts are often the biggest component of volumetric uncertainty. This paper will examine how a better understanding of hydrocarbon trap and seal capacity allows more accurate volumetric estimates and improved risk assessment.
Recent advances in several areas such as basin modelling, hydrocarbon charge, seal capacity and fault seal analysis have allowed a more comprehensive understanding of hydrocarbon traps. Hydrocarbon charge studies indicate that the proportions of generated hydrocarbons that are trapped in conventional reservoirs, the trapping efficiency, are very low, in the order of a few percent. Many times more hydrocarbons are generated than traps have the capacity to store.
Analysis of individual fields suggests that many traps are filled to capacity rather than to structural spill points. Fill capacity may be limited due to lack of top seal or fault seal. Fields that are not filled to structural spill are often limited by trap capacity rather than by insufficient charge. Hydrocarbon phase in a trap is affected not only by source rock type and maturity, but also by seal capacity.
With exploration wells often targeted at or near the crest of structural highs, over-optimistic assumptions about fluid contacts, in particular an assumption of fill-to-spill is a major cause of misunderstanding volumetric uncertainty.
These observations and results have implications throughout the life cycle of a field, from risk assessment of prospects to estimation of volume ranges during exploration, appraisal and development.
Look-backs and post-mortems are also useful to assess whether previous assumptions about hydrocarbon charge, seal capacity and fill mechanisms have been accurate or if they need revision. Analogues and lessons learned from existing fields and discoveries can also provide valuable insight into future predictions. Assessing volumetric uncertainty in terms of trap and seal capacity rather than relative to structural spill points allows better quantification of volumetric uncertainty.
Hydrocarbon Generation and Trapping Efficiency
Previous studies of hydrocarbon trapping efficiency have suggested that a relatively small proportion of generated hydrocarbons are conventionally trapped. Large proportions of the hydrocarbons generated are retained in the source rock without migrating, and remain as targets for unconventional reservoir development. Of the hydrocarbons that are expelled from source rocks, most are lost to the surface or are retained in carrier beds. The proportion of hydrocarbons captured in conventional traps is estimated to range from a few percent to around ten percent. Figure 1 highlights the large proportion of hydrocarbons retained in the source rock, but also shows the relatively small amount of conventionally trapped hydrocarbons. Expelled hydrocarbon volumes are typically many times greater than trapped hydrocarbon volumes.