bluuebunny/crossref_metadata_2025_split huggingface dataset:
Instilling Realism in Production Forecasting Decreases Chances of Underperformance
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 155443, ’Instilling Realism in Production Forecasting: Dos and Don'ts,’ by Avnish K. Rajvanshi, SPE, Robert Gmelig Meyling, and Danny ten Haaf, SPE, Petroleum Development Oman, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed.
Across the exploration-and-production (E&P) industry, several projects were found to underperform compared to the promises made at the time of project approval. Investment decisions on upstream projects rely, to a large extent, on the robustness of the predicted ultimate recovery and production forecast associated with the chosen development concept. The challenge for the E&P industry is to ensure that project approvals are based on realistic forecasts. This paper is intended to increase awareness among the forecasters and the decision makers about pitfalls associated with production forecasting.
Introduction
Recently, an industry benchmarking consortium concluded the sixth of a series of long-term production-attainment studies, which reviewed the production profiles of 59 major development projects from different hydrocarbon-producing regions. For the majority of projects, the forecasted production was not achieved.
Long-term production forecasts drive company strategies, portfolio choices, sales contracts, and shareholder promises. Too-optimistic forecasts result in underdelivery of projects, with often far-reaching consequences. Too-pessimistic forecasts, on the other hand, may lead to undervaluation of assets.
The value of an E&P company is determined by the projects in its portfolio. Some projects in the portfolio are mature, with a high likelihood of progressing to the execution phase. Some projects are immature, with a possibility of not reaching the execution stage (Fig. 1). For each project, it is important to have a realistic expectation of costs and production because this is the basis for business decisions. In addition, for immature projects, it is equally important to estimate the likelihood that they will be executed. At the portfolio level, this probability of maturation will lead to an appropriate expectation of expenditure and production and will facilitate the making of higher-level business decisions. Fig. 2 shows how to combine realistic forecasting at the individual-project level and at the portfolio level.
Pitfalls of Production Forecasting
Despite considerable efforts to prepare production forecasts, gaps between the forecast and the actual production are found in the majority of cases. Analysis of these gaps for a large number of E&P projects led to the following generic issues.
Conformance Control and Proactive Reservoir Management Improve Deepwater Production
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper IPTC 16702, ’Deepwater Production Improvement Through Proactive Reservoir Management and Conformance Control,’ by Rahim Masoudi, SPE, Hooman Karkooti, SPE, Shlok Jalan, SPE, Anndy Arif, Keng S. Chan, SPE, and Mohamad B. Othman, SPE, Petronas; and Steve Burford and Philip Bee, Murphy Sabah Oil, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
The K field is one of the more developed deepwater fields currently going through development in Malaysia. It has an excellent data set from which to optimize future development activities. In hindsight, it is clear that much more complexity exists than initially thought. As a result, uncertainty does not necessarily diminish at the start of production and a comprehensive collection and analysis of dynamic performance data are required in order to optimize recovery further.
Field Background and Geological Setting
The K field is a deepwater development located in 1330-m water depth offshore Sabah, Malaysia. The field was discovered by the K-1 well drilled to a depth of 3600 m on 30 July 2002 and marked the start of deepwater development in Malaysia. Five years after first oil, the field has more than 30 active wells including producers and injectors.
The K field is located in Block K (Fig. 1) and comprises the outbound tract of a major northwest/southeast-trending foreland fold-thrust belt that extends from Brunei to the Philippines and forms the margin of the North Sabah trough. Block K is dominated by fold-thrust structures. The reservoir section of the K field is dominated by mass-transport deposits with interspersed complex reservoir-bearing turbidite deposits.
Subsurface Development Challenges
The deepwater fields under development and study phases in Malaysia are usually considered to have more or less similar subsurface complexities and uncertainties. Among these uncertainties are level of heterogeneity, thinly-bedded-to-blocky sands, compartmentalization, fault intensity and behavior, reservoir connectivity, pressure and flow communication across the field, injection requirement from early production time, sand/fines production and reactive shale, wellbore stability, and commonly inadequate available data at the time the development decision is made.
The typical type log in the K field shows the reservoir has been subdivided into eight distinct reservoir packages labeled H110 through H150. In this ex-ample, the gross reservoir thickness (h) is 492 m with a net sand thickness of 50 m, giving an overall net/gross ratio of 0.102. Apparent from the type log is a large percentage of thinly bedded reservoirs, characterized to be beds that are less than 30 cm thick.
Advancements in Completion Technology Increase Production in the Williston Basin
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 159586, ’Advancements in Openhole-Completion Technology Increase Efficiencies and Production in the Williston Basin,’ by John Paneitz, Whiting Petroleum, and C. Christopher Johnson, Matthew White, and George Gentry, Baker Hughes, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed.
Over the years, hybrid systems have been installed in horizontal wellbores to increase the number of compartmental sections for hydraulic fracturing because of the limitations of ball-actuated fracture sleeves. Experimenting with hybrid systems provides operators with the ability to optimize spacing of fracture stages along the horizontal section when sleeve technology alone does not allow for the desired number of stages. The costs are higher for operators to perform a hybrid-type completion, however, and this has driven enhanced sleeve technology to allow for all-sleeve completions.
Introduction
The Bakken shale located in the Williston basin covers an area that includes portions of North Dakota and Montana in the US and Manitoba and Saskatchewan in Canada (Fig. 1). An unconventional reservoir, the Bakken formation is one of the last giants to be discovered in North America. The US Geological Service estimates that the undiscovered US portion of the Bakken formation holds 3.65 billion bbl of oil, 1.85 Tcf of associated gas, and 148 million bbl of natural-gas liquids.
Advances in horizontal drilling of extended-reach wells and in completion techniques have increased the amount of recoverable oil and gas. Wells drilled in the Bakken are typically drilled horizontally across two 640-acre sections, with laterals that can extend more than 9,000 ft. Two completion methods known for cost-effectiveness and high well efficiency that are used in these wells are the openhole-packer system and the sleeve one-trip system.
Openhole-Packer and Sleeve Completions
Openhole completions performed in the Bakken are commonly run as a one-trip system on drillpipe containing the following equipment: a hydraulic or mechanical running tool, liner-top packer or liner-hanger system, openhole packers, fracture sleeves, and float equipment. Once the system is in position, the appropriate fluid is displaced, and the liner-top-packer is set; the running tool is dis-connected from the system and removed from the well. The openhole packers pro-vide compartmental isolation along the horizontal wellbore with fracture sleeves placed at each stage, forming a pathway for stimulation fluid and the production of hydrocarbons.
Real-Time Analysis for Remote Operations Centers
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16999, ’Remote Real-Time Analysis - A Game Changer for Remote Operations Centers,’ by Erland Saeverhagen, Arve Thorsen, Jan Ove Dagestad, Nic Spanovic, and Kate Cannon, SPE, Baker Hughes, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
Drilling completion, production, and general surveillance are all areas that benefit greatly from remote real-time analysis. However, several challenges to remote services exist, including communications issues, fear of job loss, and working outside one’s comfort zone. What is considered an important development goal for a business might be regarded as a threat to an individual, leading to reduced development within remote services.
Remote-Operations Business Model
A remote-operations business model removes geographic location and physical distance in all phases of oilfield-service delivery. It reduces the cost of delivering services, increases geographic reach, and improves safety. Remote operations, in essence, are real-time workflows that integrate personnel at rigsites and at assembly and maintenance and overhaul (AMO) facilities; at remote operations centers; or at real-time operational centers (RTOCs) anywhere in the world.
Remote operations are the acquisition of sensor data from rigsite equipment and instruments, and the transmission and processing of those data from remote locations. Monitoring, alarm, or advisory services are delivered in real time with global delivery models, increasing the capability to move work from the point of service to another lo cation, where it can be performed more safely, more quickly, and at a lower cost.
Infrastructure, while critical, is only an enabler. The true sources of efficiency and competitive advantage come from the organizational redeployment of the workforce and the re-engineering of workflows. Providing on-demand expertise enables service providers to deploy new technology faster and deliver high-end services in areas with few local qualified resources. Customers also benefit from bundled services, which require the integration of different disciplines and expertise that may be in short supply.
The Digital Oil Field
Improved connectivity through radio link, fiber optics, and satellite systems has opened a new world of opportunities for operation optimization. Real-time operations monitoring occurs from any office, accessing data streams through Web portals. New downhole tools and software have been developed on the basis of these new abilities, and new service levels have resulted, leading to new and interesting jobs, improved well placement, high service quality, and reduced non-productive time (NPT).
En Route: CO2 Stories
Authors: Labastie Alain 
Published: February 2015

President's column
The second SPE International Conference on CO2 Capture, Storage, and Utilization will be held 10-12 November in New Orleans. CO2 issues are at the center of many controversies, within the general public as well as the scientific community and even the oil and gas community. These controversies may have a significant impact in our industry, so I would like to take this opportunity to share with you some personal thoughts on the subject.
It is important to make a clear distinction between facts, which are well established, and theories or interpretations, which may be subject to intense discussion. Let's start with facts.
CO2 concentration in the Earth atmosphere has been increasing since beginning of the industrial era, about 150 years ago. This increase is well correlated with the intensive use of fossil fuels as energy source.
There are many substances acting as greenhouse gases (GHG) in the atmosphere, the most important being water vapour. However, only the concentration of CO2 has significantly increased in the past century.
The oil and gas sector accounts for one-third of GHG emissions, but this is mostly due to the end users, you and me: transportation, heating of buildings, etc. The oil and gas industry itself, including E&P, refining, and distribution of petroleum-related products, accounts for only 5% of the global GHG emissions, much less than agriculture (share=14%) or deforestation (share=17%).*
This is important to remember: our industry is perceived as being responsible for a large fraction of GHG emissions, and this is not true. The end users-i.e., the general public-are responsible, and they don't realize that.
However, many unconventional hydrocarbons that we are beginning to produce have much higher CO2 emissions per barrel, as compared to conventional light oil. For example, emissions from extra-heavy oil produced by thermal methods are 4 times higher, and even 10 times higher if we include upgrading. (This is due to steam generation and heating for upgrading.) Another example is synthetic fuels from gas-to-liquids (GTL) conversion (Fischer Tropsch process), which are 15 times higher in CO2 emissions than conventional oil.
These are facts, well established. Let's talk now about interpretations and theories. One of the most controversial is the concept of global warming, which is creating a lot of . . . 'warm' discussions. This is only a theory; apparently the data are not sufficient to establish that as a fact (I am not a climate scientist, so I don't want to elaborate on that).
However, it is fact that there are hundreds of peer-reviewed scientific papers confirming the global warning concept, and not a single one, to my knowledge, stating the opposite. Again, I am talking only about peer-reviewed papers, which are supposed to give sound information.
Sand-Control Reliability: Finding the Sweet Spot
Authors: Green Annabel 
Published: February 2015

Guest editorial
Sand control represents a diverse range of technologies designed to meet the demands of hydrocarbon recovery from weak sandstone formations. Although the technology is developing and improving, industry adoption of new sand-control techniques is typically much slower than for oilfield technologies in general.
While is it often necessary to control the unwanted production of reservoir sand into the wellbore, sand-control techniques to varying degrees add cost and complexity, yet are operationally unforgiving and have relatively poor long-term reliability. Added to that is a single-point critical failure mode in a completion that is often both unrecoverable and unrepairable. The challenge, then, is to provide sand-control technology that addresses these weaknesses and to select solutions that will maximize value for any given application.
This fundamental challenge is unchanged from the time when sand control was first installed in wells more than 100 years ago; what has changed is the variety and complexity of applications. For example, extended reach, high rate, deep water, high-pressure/high-temperature, heavy oil, multilateral well construction, and reservoir segmentation all place differing demands on the sand-control completion but all represent higher-cost environments in which maximizing the return on investment is essential. In response to this increasing diversity and criticality, the industry has seen an increasing range of sand-control techniques. There are now at least 20, many of which are “new,” have evolved, or are under development. But since none is a panacea, how do we evaluate and rank this increasing range of options and application challenges to maximize net present value (NPV)?
There are three key factors in determining NPV: cost, performance, and reliability. The cost element is relatively simple. Operating expenditure, capital expenditure during installation, and the cost of failure—lost production and remediation—can be readily quantified. And generally, even for new techniques, the tools exist to model the well performance and confidently predict (at least) relative performance. While the performance of sand-control completions for some solutions is determined by the productivity reduction that occurs due to skin damage or wellbore size reduction, performance can also be positively influenced. Sand control with stimulation techniques or chemical treatments can increase productivity, and inflow-control technology can be combined to aid wellbore cleanup and improve ultimate hydrocarbon recovery. More recently, options for additional functionality have been introduced to provide degrees of reservoir management.
Having quantified cost and performance, what is left is reliability, and herein lies the challenge that is in many ways unique to sand control.
Platelet-Technology Applications Provide Economic Remedy for Well-Integrity Problems
Authors: Stewart Kevin 
Published: February 2015

Technology Update
Up to 40% of the world’s oil wells are shut in, or operating with dispensation, because of well-integrity problems. With the proportion that large, these wells collectively represent major potential for increasing production to meet oil demand—growing globally each year by 1 million BOPD—if improved and more-economic remedies for these problems can be found. Better remedies can reduce the need to drill new wells.
With the right technology, leaks in casing, tubing, well valves, and connections can be diagnosed relatively easily. However, fixing them has traditionally been more difficult. Issues typically have included cost, availability of rigs or workover units, personnel requirements, leak-fixing processes, weather, and third-party dependencies. These various considerations can result in extended and long lead times to bring shut-in wells back on line or indefinite postponement of needed interventions on wells that are operating.
There are also significant planning and logistics issues, and lengthy down-time can result. Well output could be partially or totally lost for months—affecting production quotas and revenue targets—before a rig is mobilized and deployed. And rig workovers can be complex and risky. Removing a well-head during a workover, for example, could affect well integrity and bring about health, safety, and environment (HSE) risks bigger than the problems the workover is intended to remedy.
Brinker Technology has recently developed a system called Platelets, a rigless, through-wellhead workover technology that allows the major planning, logistical, and downtime issues of traditional work-overs to be avoided and commensurate cost savings to be achieved.
In concept, the technology functions similarly to the way the human body responds to cuts and wounds, where platelets in the blood are drawn to the cut and create a seal. The oil and gas technology is designed around free-floating, discrete particles conveyed by means of an inert carrier fluid. The platelets deployed in this technology are specifically engineered for the size of the leak and the operating conditions of the system. Platelets are pumped down-stream while suspended in the carrier fluid and, when they reach a leak, pressure-differential forces entrain them into the defect to create a mechanical seal (Fig. 1). The polymeric and elastomeric materials incorporated in the platelet technology produce a seal more durable than steel and have no negative effects on the treated infrastructure.
The platelet technology previously has been applied in subsea pipelines and water-injection systems. Its applications have now been extended to casing, tubing, well valves, and connections. The technology includes specific designs for both static- and dynamic-sealing applications. Additionally, by incorporating specially designed software, the technology can be used diagnostically to locate leaks (Fig. 2).
Subsea Developments Key To Future Production
Authors: Thomas Mark 
Published: February 2015

Ongoing advances in subsea technologies and their proven application in offshore regions around the world mean that there can be few, if any, other areas of the upstream industry that can claim such strong prospects for the future. With exploration and development projects routinely taking place in waters well beyond 1500 m, and with some nearing the 3000 m mark, the need for reliable subsea systems and hardware—and continued essential R&D—remains paramount if oil and gas companies are to access the new and increasingly remote reservoirs they need to replenish their own reserves and meet the demands of an ever-thirsty global energy market.
The future of the subsea market looks remarkably promising. The case looks even more solid when you consider that many observers appear to forget that subsea does not just mean deep water and harsh environments—there are dozens of developments currently under way or in the pipeline in much less than 400 m of water that will require subsea systems and hardware. When you consider that whatever the basic offshore design or concept—drilling rig, fixed production platform, floating production facility, or total seabed-to-shore package—subsea equipment of one form or another is required, the view gets even better.
Add to this the increasingly cost-effective subsea systems also being introduced to the market or further refined, with various seabed processing, separation, boosting, and compression designs either in action or emerging for pioneering projects around the world within the next year or two, and the fundamentals become even more reassuring, not only for the industry itself but also for shareholders and an investment community looking for lower-risk options post-Macondo.
Some of the offshore industry’s leading authorities are forecasting that, despite some relatively short-term delays in the US Gulf of Mexico, the future for the subsea market is healthy up to 2014 and beyond. Infield Systems says in its latest market update that the subsea sector’s future looks good due to the basic factors of reserve depletion in shallow-water regions, increased deepwater activity, and enhanced-oil-recovery efforts and techniques. “More than USD 87 billion will be invested in development drilling and the manufacturing and hooking-up of subsea units to 2014. This represents a substantial 30% increase over the previous 5 years,” it states.