This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 181015, “Natural-Language-Processing Techniques on Oil and Gas Drilling Data,” by M. Antoniak, J. Dalgliesh, SPE, and M. Verkruyse, Maana, and J. Lo, Chevron, prepared for the 2016 SPE Intelligent Energy International Conference and Exhibition, Aberdeen, 6–8 September. The paper has not been peer reviewed.
Recent advances in search, machine learning, and natural-language processing have made it possible to extract structured information from free text, providing a new and largely untapped source of insight for well and reservoir planning. However, major challenges are involved in applying these techniques to data that are messy or that lack a labeled training set. This paper presents a method to compare the distribution of hypothesized and realized risks to oil wells described in two data sets that contain free-text descriptions of risks.
In the oil and gas industry, risk identification and risk assessment are critical. This holds particularly true during the drilling stages, which cannot begin before a risk assessment is conducted. While these risk assessments are typically conducted in a group setting, the project drilling engineer usually has a predetermined list of risks and likelihood scores that are the focus of the conversation.
One problem with this approach is that drilling engineers are inherently biased by personal experiences, which can affect their view on how likely an event is to happen. For example, if a project drilling engineer recently encountered well-control issues, the engineer will likely overestimate the chance of future well-control issues. On the other hand, if the engineer has never encountered a well-control issue, it may be unintentionally omitted altogether from the risk assessments.
Using historical data as a barometer could help the drilling engineer overcome these issues, though doing so requires a unified view of both prior risk assessments and prior issues encountered. Chevron maintains both data sets in disparate systems. The Risk Assessment database contains descriptions of risks from historical risk assessments, and the Well Operations database contains descriptions of unexpected events and associated unexpected-event codes, which categorize the unexpected events.
Leveraging both, a system has been created that allows a project drilling engineer to enter a risk in natural language, return drilling codes related to this risk, produce statistics showing how often these types of events have happened in the past, and predict the likelihood of the problem occurring in certain fields.
A year ago, this feature noted the continued languishing of crude-oil prices and the low margins in tight and very tight reservoir asset developments and the resulting substantial reduction in new-well drilling and completion. Little has changed since then. In the meantime, technology advancements have enabled a greater number of hydraulic fractures in long horizontal completions in such reservoirs, for example, resulting in more-cost-effective completions and greater initial oil-production rates. But low primary oil recovery and steep initial-production-rate declines still present overriding limitations. These tight and very tight oil-bearing reservoirs are typically characterized by oil-recovery factors of approximately 10%. However, on a positive note, in addition to improvements in completion efficiencies, recent advancements also have been made in the understanding and application of enhanced-oil-recovery (EOR) methods in such reservoirs.
While enhancing oil production from multizone, hydraulically fractured completions in tight reservoirs is not straight forward, recent studies, including field trial programs, have shown that applications such as gas injection and waterflooding, including smart water injection, have the potential to create significant improvement in oil recovery.
The three papers featured this month are from Canada. All address the importance of wettability and wettability alteration in improving sweep efficiency and oil extraction by use of gas injection or water injection. Both laboratory studies and field application, in the case of waterflooding, are discussed. Each, with their unique perspectives and approaches, provides understanding of EOR fluids; formation interactions; and the benefits and present limitations of gas injection, conventional waterflooding, and smart water injection.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 185037 EOR in Tight Reservoirs—Technical and Economic Feasibility by K. Joslin, Computer Modelling Group, et al.
SPE 185680 Compositional-Simulation Evaluation of Miscible-Gas-Injection Performance in Tight Oil Formation by Ahmed Mansour, Texas Tech University, et al.
SPE 180284 The Use of Propellants To Stimulate and Enhance Productivity From Tight, Damaged, and Low-Quality Reservoirs by J. Gilliat, Baker Hughes, et al.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 183329, “Downhole Sand-Ingress Detection With Fiber-Optic Distributed Acoustic Sensors,” by Pradyumna Thiruvenkatanathan, Tommy Langnes, Paul Beaumont, Daniel White, and Michael Webster, BP, prepared for the 2016 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 7–10 November. The paper has not been peer reviewed.
There is currently no proven technology available in the market that accurately identifies downhole sand-ingress locations in real time. In this paper, the authors present results from use of a new technology that uses in-well-conveyed fiber-optic distributed acoustic sensing (DAS) for the detection of sand-ingress zones across the reservoir section throughout the production period in real time.
Mechanical sand-control systems are not always fully effective. The end result may be high sand production, which results in choking back the well and reducing hydrocarbon production significantly. In most cases, the precise sanding interval is unknown, making sand-remediation operations (such as remedial plug placements) often ineffective. A successful remediation requires identification of locations of sand entry to inform targeted sand-shutoff operations. However, no proven technology accurately identifies sand-ingress locations during well production in real time.
The technology described in this paper has now been used successfully
While conventional surface acoustic sand detectors provide a delayed indication of onset of downhole sanding events, they do not provide information about the zones in the reservoir that are producing sand. A successful sand-shutoff operation, however, requires knowledge and definitive identification of the zones (or depth sections) in the reservoir contributing to sanding and their relative concentrations.
DAS has been viewed as a potential candidate technology for downhole sand detection in recent years. DAS systems are intrinsic optical-fiber-based acoustic-sensing systems that use the backscatter component of the light injected into an optical fiber to detect acoustic perturbations along the length of the fiber. The fiber itself acts as the sensing element, with no additional transducers in the optical path, and measurements are taken along the length of the entire fiber, allowing for a true distributed measurement using a single fiber. The technology provides sensitivity to strain variations by monitoring changes in the length and index of refraction of the fiber induced by impinging acoustic pressure waves.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185030, “Improved Oil Recovery in Tight Oil Formations: Results of Water-Injection Operations and Gas-Injection Sensitivities in the Bakken Formation of Southeast Saskatchewan,” by S.M. Ghaderi, C.R. Clarkson, and A. Ghanizadeh, University of Calgary, and K. Barry and R. Fiorentino, Crescent Point Energy, prepared for the 2017 SPE Canada Unconventional Resources Conference, Calgary, 15–16 February. The paper has not been peer reviewed.
Although improvement in hydraulic-fracture properties and infill drilling remains the focus of recovery enhancement from the Bakken, low oil recoveries and steep initial decline rates are experienced in primary-recovery operations, even after application of multifractured-horizontal-well technology. Therefore, many pilots have been executed to determine the viability of waterflooding for maintaining oil rates and improving recoveries through reservoir-pressure maintenance and sweep-efficiency enhancement. This paper presents the performance results from one of the waterflood pilots in the Viewfield Bakken.
A section of the Bakken reservoir (the geology of which is described in detail in the complete paper) deemed to be representative of the waterflood performance in Viewfield is considered for modeling. This section has been developed by use of multifractured horizontal wells completed in the Middle Bakken (main target reservoir) with a well spacing of 200 m (eight wells per section, named A through H). All eight wells started oil production within a similar time frame, and, after approximately 1 year of production, every other well was converted to a water injector.
Reservoir-Fluid Model. Conventional pressure/volume/temperature (PVT) analysis was conducted by a commercial laboratory on 12 surface-separator oil and gas samples. Recombination of fluids at reservoir temperature (156.2°F) yields a final gas/oil ratio of 810 scf/STB. Subsequently, a series of constant-composition-expansion and differential-liberation tests was conducted on the recombined fluid to determine oil-saturation pressure, oil-formation-volume factor, oil density, and oil and gas viscosity as a function of pressure. The Peng-Robinson equation of state and modified Pedersen viscosity correlation were tuned to replicate the PVT properties of oil and gas as a function of pressure.
Reservoir Grid Model. On the basis of the well tops and reservoir net-pay values, reservoir structure for the study area was generated. It is known that the minimum horizontal stress is aligned in the northwest direction and at approximately 50° with respect to the east/west horizon. Therefore, reservoir gridding is rotated at this angle to mimic the hydraulic-fracture orientation along the horizontal-well laterals. Grid size in the horizontal direction is 65×65 ft, and the total thickness of the reservoir is approximately 28 ft, which is divided into nine layers of equal thickness.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185076, “Imbibition Oil Recovery From Tight Rocks With Dual-Wettability Pore Networks: A Montney Case Study,” by Ali Javaheri and Hassan Dehghanpour, SPE, University of Alberta, and James Wood, SPE, Encana, prepared for the 2017 SPE Canada Unconventional Resources Conference, Calgary, 15–16 February. The paper has not been peer reviewed.
Previous studies demonstrate that Montney rock samples present a dual-wettability pore network. Recovery of the oil retained in the small hydrophobic pores is uniquely challenging. In this study, the authors applied dual-core-imbibition (DCI) methods on several Montney core plugs and introduced the imbibition-recovery (IR) trio to investigate the recovery mechanisms in rocks with dual-wettability pore networks.
Spontaneous imbibition of aqueous phases (water, brine, or surfactant solutions) in fractured sandstone has been studied as a possible mechanism for enhanced oil recovery. Extensive experimental and mathematical investigations have been conducted for relating the imbibition rate and total oil recovery to the capillary and gravity forces and geometrical parameters. However, rock/fluid interactions in tight and shale reservoirs are more complicated than those seen in conventional reservoirs. In addition to capillary forces, organic materials and reactive clay minerals can inﬂuence the fluid ﬂow and storage in the small pores of low-permeability rocks. The affinity of reservoir rock to a particular fluid in such formations depends especially on rock mineralogy and properties of the organic matter that coats and fills the pores.
Previous comparative imbibition tests show that the affinity of the Montney samples to oil is significantly higher than their affinity to water. This behavior was explained by the presence of water-repellent pores within or coated by solid bitumen or pyrobitumen. In the complete paper, the authors focus on imbibition oil recovery of samples cored from the Montney Formation and investigate the role of rock-fabric complexities, such as dual-wettability characteristics, in oil recovery by water imbibition. A detailed discussion of materials used in the spontaneous-imbibition and oil-recovery tests, including rock and fluid properties, is included in the complete paper.
The authors conducted three sets of comparative tests on five twin core plugs, which were dry cut from Montney cores. The samples are characterized by measuring mineral concentration, total-organic-carbon (TOC) content, porosity, and permeability. The methodology is fully described in the complete paper.
More than half of all existing wells are estimated to require sand control or sand management throughout their lifetime, including unconsolidated sandstone in conventional reservoirs or flowback in unconventional reservoirs. The majority of recent major hydrocarbon discoveries, from Africa (Mozambique, Angola, and Tanzania), transcontinental countries (Egypt), North America (US and Canada), to Far East Asia (Malaysia), are offshore with high-permeability soft formation sands. Approximately half of them are gas-bearing reservoirs.
High-flow-rate gas wells are particularly susceptible to sand production. High-velocity or turbulent fluid flow generates large drag forces, dislodging unconsolidated sand particles. The free-flowing particles can erode downhole and surface equipment, including well-control barriers. In a worst-case scenario, this can lead to dangerous uncontrolled production.
To ensure successful sand management, a multidisciplinary engagement is necessary. The teams should be able to predict sanding tendencies, detect the sanding locations, select appropriate downhole sand-management and -control devices, and implement the best operating practices for the life of the well.
Because of the current downturn, operators are shifting their efforts to the revitalization of existing wells in order to squeeze more production from depleted reservoirs. The same holistic sand-management tactic should be applied to remedial sand control.
In summary, production from sand-prone reservoirs is a daunting task, with formidable challenges. Sand management and control remain as an old problem but with new challenges because of the suppressed oil and gas prices. Cost-saving and value-adding solutions are vital now more than ever.
For more information, read the featured papers, recommended additional reading, and other publications at OnePetro.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 181596 Defining Sand Control in an Uncharted Frontier: A Case Study on the Zawtika Field Development in Myanmar by Graham Grant, PTTEP International, et al.
SPE 181360 Case History: Integrated Approach to Sand Management and Completion Evaluation for Sand Producer in a Mature Field, North Sea by M. Ruslan, Dong Oil and Gas, et al.
SPE 182511 New Criteria for Slotted-Liner Design for Heavy-Oil Thermal Production by Mahdi Mahmoudi, University of Alberta, et al.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 181598, “Prospective Unlocking of Future Reserves in Offshore Abu Dhabi: Field-Life Extension Through Hybrid Development Concept,” by T. Nakashima, SPE, D. Ouzzane, SPE, G. Dudley, SPE, and M. Al-Marzouqi, ADMA-OPCO, prepared for the 2016 SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. The paper has not been peer reviewed.
Field A, a giant field consisting of many subreservoirs, is offshore Abu Dhabi and has produced for 50 years, mainly through peripheral water injection. A long-term development plan (LDP) for the field aims to extend the production plateau by 25 years through infill drilling and waterfloods. This paper describes an approach for optimizing the number and type of drilling centers required to enable the development plan to be flexible in design to accommodate infrastructure, facilities, drilling, and subsurface constraints.
Field A, a giant carbonate field, has been developed for 50 years. As the field reaches maturity, it moves to another phase of development. Design of the next development phase, the LDP, began in the early 2010s. The LDP assessment stage, which screened the surface and subsurface development concept, was recently completed, and the development planning team is preparing for the selection stage. The assessment-stage conclusion was for drilling from artificial islands (AIs), wellhead towers (WHTs), or a combination of both and leaves a degree of freedom. This paper describes the optimization approach of the drilling-center options.
The LDP is just the first phase of a large-scale long-span offshore reservoir redevelopment that aims for a further 50 years of production. The complexity of the field is significant because of limited seabed space, the age of the existing surface facilities and pipelines, and challenging drilling circumstances.
These complexities differentiate the development project from other offshore projects, and an appropriate selection of drilling centers is one of the more important keys to project success.
Field and Development History
The field of carbonate reservoirs is in shallow water. The field is 40×20 km, and different reservoirs have been developed by two different operators. The stack of reservoirs is divided into shallower reservoirs (U Reservoirs) and deeper reservoirs (L Reservoirs).
The L Reservoirs are geologically divided into two major reservoirs, L1 and L2, which have been developed similarly. The development began with natural production with original reservoir energy. Beginning in the 1970s, pressure maintenance through dump flood-water injection by connecting the target reservoirs with a shallow aquifer was conducted for 10 years. For further reservoir-pressure maintenance, powered peripheral water injection was started, and the development scheme has been continuous, with reinforced pressure maintenance through immiscible gas injection from the top structure.
As time goes by, an increasing number of new processes that oil and gas companies want to push to their workforce will come in the form of an app. This is true for field technicians as well as production engineers.
But just as with anytime change is introduced, the improvements these apps are intended to deliver may not be lasting—or realized at all—without strong internal acceptance.
ChaiOne is a Houston-based app developer that has built its business around this conundrum. In its 9 years, the company has worked for several of the upstream industry’s most recognizable names including ExxonMobil and Schlumberger.
Chief Executive Officer Gaurav Khandelwal said the company’s success lies in its bottoms-up strategy, which begins with the end user and “understanding their problems, stresses, frustrations, and emotions.”
This work relies on teams of behavioral psychologists, anthropologists, and software interaction engineers who are tasked with figuring out new ways for workers to save time and money for their companies. Like others who promise efficiency improvements to the oil and gas business, a lot of ChaiOne’s efforts are centered around reducing how much time is spent on regular working hours and overtime.
“When we take the user-experience-driven approach, and send people into the field to study a process, often we find tremendous amounts of waste in the way things are being done,” explained Khandelwal, adding that, “In 4 to 6 weeks, we can find millions of dollars in savings in these companies.”
Smarter Field Repair
Many of the software products that ChaiOne has created cannot be discussed thanks to the industry’s penchant for nondisclosure agreements. But among those that it can speak freely about is CygNet, which was developed for inter-national service company Weatherford.
This iPhone app connects with oilfield SCADA systems to show engineers production trends or to relay important alarms. Khandelwal said operators who use the app—12 of which supplied input to steer its development—are now using fewer field technicians to deal with routine oilfield problems.
When a worker is on his way back from a repair job, it is not unusual for another problem to arise at a wellsite just 10 minutes away. In the past, Khandelwal said that the technician would likely be unaware of a nearby failure, and because dispatch did not know they were close by, an additional crew would be sent out. With the CygNet app, the reverse is now true for its users. When a repair team is out on location and a nearby well sets off an alarm, CygNet sends a geo-targeted notification. And just as important, the app can also help them decide if the issue needs to be attended to at all.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18984, “Three-Dimensional Full-Field and Pad Geomechanics Modeling Assists Effective Shale Gas Field Development, Sichuan Basin, China,” by Liang Xing, PetroChina; Xian Chenggang, SPE, Schlumberger; Shu Honglin, PetroChina; Chen Xin, Schlumberger; Zhang Jiehui, PetroChina; Wen Heng, Schlumberger; Wang Gaocheng, PetroChina; and Wang Lizhi, Guo Haixiao, Zhao Chunduan, Luo Fang, and Qiu Kaibin, SPE, Schlumberger, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2016 International Petroleum Technology Conference. Reproduced by permission.
The oilfield-development plan (ODP) for a shale gas field at the southern edge of the Sichuan Basin in China started in early 2014. The first wells drilled in the field and its adjacent blocks experienced significant challenges, such as severe mud losses, stuck tools, losses in the hole, high treating pressure, and unexpected screenout. Because an accurate understanding of geomechanics and its roles at various scales is vital, 3D full-field and pad geomechanics models were developed for achieving efficiency and effectiveness in implementing the ODP.
The Ordovician-Silurian Wufeng-Longmaxi hot shale is an emerging shale gas play in China.
Currently, the major exploration and development activities of the play are in the Sichuan Basin and its adjacent areas. For shale gas development in the Sichuan Basin and its adjacent areas, using the megascale, high-density, and continuous and regular pad drilling as is used in North America is difficult because surface and subsurface conditions are significantly different from those of the well-known North American shale plays.
The strong environmental and social constraints that typify the Sichuan Basin and surrounding area are shown in Fig. 1. Drilling pads for shale gas developments are commonly located in narrow valleys that are often home to farmland and residential villages with dense populations. Differences of elevation among neighboring pads can be from several hundred meters to more than 1000 m. To speed up development of marine shale gas in the Sichuan Basin and its adjacent areas with a minimized learning curve, a geoscience-to-production integration of research, engineering, and operation with its associated research and development, methodologies, and work flows must be applied. This geoscience-to-production integration aims to optimize both efficiency and effectiveness dynamically at single-well, pad, and field scales with systematic and continuous optimization of technologies and solutions and the accumulation of knowledge and experience to enhance well productivity.
One shale gas field, which is the study area of this paper, is in the mountainous area at the southern edge of the Sichuan Basin. The first wells drilled in this field and its adjacent blocks experienced significant geomechanics-associated challenges, such as severe mud losses, tools or drillingpipe sticking, losses in the hole, high treating pressure while hydraulic fracturing, and unexpected screen out of fracturing stages. Having reliable yet evolving understanding of geomechanics and its role at various scales during the progress of the ODP is vital. This paper describes the development of 3D full-field geomechanics models and high-resolution 3D pad geo-mechanics models and their engineering applications.
Each year, the Society of Petroleum Engineers (SPE) honors members whose outstanding contributions to SPE and the petroleum industry merit special distinction during its Annual Technical Conference and Exhibition (ATCE). Recipients of the 2017 SPE international awards will be recognized at the Annual Reception and Banquet held on Tuesday, 10 October. The 2017 SPE ATCE will be held in San Antonio, Texas.
Honorary Membership is conferred on individuals for outstanding service to SPE and/or in recognition of distinguished scientific or engineering achievement in fields encompassed in SPE’s technical scope. Honorary Membership is the highest honor SPE confers upon an individual and is limited to 0.1% of SPE’s total membership.
SPE Distinguished Lifetime Achievement Award
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Anthony F. Lucas Gold Medal
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DeGolyer Distinguished Service Medal
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Lester C. Uren Award
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Robert Earll McConnell Award
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Charles F. Rand Memorial Award
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Distinguished Service Award
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Cedric K. Ferguson Medal
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Young Member Outstanding Service Award
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