bluuebunny/crossref_metadata_2025 huggingface dataset:
Technology Focus: Tight Reservoirs (October 2010)
Authors: Kubala Gregory
Published: February 2015

Technology Focus

Shale-gas reservoirs are becoming an increasingly significant percentage of the global tight-reservoir landscape. Three questions reflect this increasing dominance but are applicable overall to tight formations.

Is the long multistage-fractured horizontal well into which millions of gallons of water are pumped downhole with only a third of the contacted reservoir propped open the most efficient way to produce the reservoir?

Is the long multistage-fractured horizontal well the endgame solution to Master’s Resource Triangle?

If the equations set forth by Darcy and Young/Laplace are valid, does contacting a large amount of the formation with only water constitute stimulation of the reservoir?

Capillary pressure is significant in tight reservoirs. Stimulation-fluid invasion into smaller pore diameters and invasion of proppant-free stimulation fluid into both induced fractures and dilated natural fractures will have an effect. Production-decline rates and long-term health of wells (improved fluid flow or degree of formation damage) in tight reservoirs will depend on how capillary forces are managed in the reservoir.

Log-normal large volumes of hydrocarbon found in tight reservoirs are difficult to develop because of constrained drainage areas, complicated petrophysics, lithology, and formation heterogeneity. These difficulties, complexities, and heterogeneities dictate planning of drilling, completion, and stimulation specific to the well in question. They also dictate continued advances in knowledge and technology if the majority of the hydrocarbon asset is to be produced effectively.

Early production levels will be dependent on the length of propped fracture from the wellbore that has actually cleaned up and this contributing to hydro-carbon flow.

Our industry needs to make advances in: real-time measurement; post-fracture monitoring with production analysis; identifying sweet spots, then placing perforations to create complex conductive fractures; innovative proppants and proppant-placement techniques in primary and complex fracture geometries; fluid recovery; formation-damage control and permeability enhancement; proppant transport with less-damaging stimulation fluids; and environmentally responsible drilling, completion, and production services.

Tight Reservoirs additional reading available at OnePetro: www.onepetro.org

SPE 128191 • “Selecting Drilling Technologies and Methods for Tight Gas Sand Reservoirs,” by Pilisi, N., SPE, Blade Energy Partners, et al.

SPE 131778 • “Using Microseisms to Monitor Hydraulic Fractures in the Bakken Formation of North Dakota,” by Gary S. Forrest, Schlumberger, et al.

SPE 130043 • “Fracturing Design Aimed at Enhancing Fracture Complexity,” by M.Y. Soliman, Halliburton, et al.
Technology Focus: Sand Management and Frac Pack (October 2010)
Authors: Goodman Harvey E.
Published: February 2015

Technology Focus

As our wellbore-integrity- and sand-management-modeling prowess grows from the laboratory to the field, the quest for reliable environmentally responsible energy resources continues to challenge, and in some cases demands, us to accelerate development of new well-system-integrity applications for the field. Well-engineering-systems design benefits from formation-failure-prediction modeling capabilities that can be verified in the field by a more diverse array of measurement techniques in both open- and cased-hole environments, even extending to the overburden by use of geophysical-survey techniques. Still, we are challenged to integrate the formation-failure predictions and observations with well-systems hardware and architecture that define the entire production system, from the completion up to the wellhead, and on through the surface facilities.

Papers selected for this month’s feature start with risk-based well integrity for CO2 storage in the subsurface. To ensure CO2 containment over time, well-integrity-modeling technology is pushed to its limits. The risk-based approach is introduced to manage the complexities of long-term storage.

A second paper looks at the basics of sand-exclusion-performance evaluation after a change in long-standing completion practice was made to shorten project-payout time. The paper examines this decision from the viewpoint of longer-term production performance.

The third paper deals with wellbore integrity in chemically active shale formations. The work experimentally investigates the effects of capillary pressure and osmotic forces on shale-swelling behavior. The study questions the practice of adjusting only the salinity concentrations in the aqueous phase of drilling muds to enhance hole stability by pulling water from the shales into the borehole to retard hydration (chemical osmosis). Could the highest saline concentrations cause associated water to move into the shales through ion transfer by diffusion osmosis?

Sand Management and Frac Pack additional reading available at OnePetro: www.onepetro.org

SPE 128038 • “Improved Selection Criteria for Sand Control—When Are ‘Fines’ Fines?” by Michael Byrne, SPE, Senergy, et al.

SPE 127931 • “State-of-the-Art Screen Selection for Standalone-Screen Applications” by R.A. Chanpura, Schlumberger, et al.

SPE 123478 • “A Comprehensive Study of Sanding Rate From a Gas Field: From Reservoir, Completion, and Production, to Surface Facilities,” by Gang Han, Hess Corporation, et al.
A Risk-Based Approach for Well-Integrity Management for a CO2 Geological Storage Project
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 122510, ’A Risk- Based Approach for Well Integrity Management Over Long Term in a CO2 Geological Storage Project,’ by Y. Le Guen, SPE, V. Meyer, O. Poupard, E. Houdu, and R. Chammas, SPE, Oxand S.A., originally prepared for the 2009 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 4-6 August. The paper has not been peer reviewed.

A risk-based methodology associated with well integrity is proposed within CO2 geological storage. The main objectives of this approach are to identify and quantify risks associated with CO2 leakages along wells over time (from tens to thousands of years), to evaluate risks, and to propose relevant actions to reduce unacceptable risks. 

Introduction

Concerns about greenhouse-gas emissions are growing. Both authorities and industries are thinking about solutions to reduce their emissions to adhere to the convention signed in Kyoto. The carbon capture and storage (CCS) technology constitutes one of the most suitable technologies to reduce greenhouse-gas emissions in the atmosphere. Pilots already exist worldwide. However, a large-scale deployment can be questioned for some of them. Among various issues, public fear, environmental impacts, economical aspects with respect to CO2 geosequestration, and possible gas leakages still constitute major issues. Wellbores constitute the only intrusive and manmade element of the storage system in the geologic systems. Moreover, the wellbore-integrity assessment implies a number of specificities, because of the time scales involved, the properties of the stored fluid and to the uncertainties characterizing the physical parameters and mechanisms. Demonstrating that the wellbore constitutes a safe barrier for CO2 confinement over the long term is of paramount importance for large CCS acceptance and deployment.

The full-length paper presents a quantitative risk-based methodology to evaluate the performance and the risks associated with well integrity in the long term, taking into account the degradations and aging of the components of the well coupled to porous-media flow occurring in a well. A statistical approach is integrated into the methodology to deal with the uncertainties associated with both the well characteristics and the input to the model. To illustrate the methodology and demonstrate its relevance to provide operators with operational recommendations, a synthetic case study is proposed.

Performance and Risks Methodology

The present methodology has been developed in accordance with a risk-based process. Here, risk is not just a concept but also a metric that can be quantified. Risk can be defined as the combination of the likelihood of a failure event (i.e., its probability) and the magnitude of its impact. The uncertainties of the system are converted into the notion of probability, and the quantitative CO2-leakage mass assessed into the notion of severity.
Technology Focus: Knowledge Management and Training (October 2011)
Authors: Ellul Ivor
Published: February 2015

Technology Focus

Past articles for this feature have touched on the topic of decision making. Indeed, last year’s article tackled the approach to decision making with a focus on situational awareness. This year, we focus on the availability of knowledge as an aid (on the one hand) and a prerequisite (on the other) to our ability to execute decisions rapidly and correctly.

Distilling the key paper topics offered up for this year’s Knowledge Management and Training feature resulted in an interesting “triple-S” configuration of systems, state, and studies.

Systems. Knowledge-base (KB) systems are becoming a key component in the workflow for delivering critical decision making. The industry has transcended what may now be considered standard databases. A variety of database configurations is available commercially, with great advances made over recent years. Overlaying available data with information and carefully collated knowledge is an emerging practice. Delivering the KB within a spatial frame of reference, commonly a geographical-information system (GIS), provides for a rich degree of multidimensionality.

State. Continuous access to the “state” of the integrated asset, including the reservoir, production, and pipeline systems, is readily available by use of now-commonplace supervisory control and data-acquisition systems. However, the ability to translate the state into meaningful information requires transfer through a series of process layers that filter and aggregate the data such that action may be taken as necessary and appropriate to maintain production targets.

Studies. The industry invests significant capital in conducting detailed integrated studies of assets at various points in their life cycles. While keeping internal and external consulting organizations in business, these studies usually deliver an enhancement, depending on the degree of acceptance of the recommendations. Additionally, depending on the organization, the shelf life of these studies may be somewhat limited. Any approach is, therefore, welcomed if an integrated study is incorporated within an enterprise decision-making frame of reference.

And the learning process continues….

Knowledge Management and Training additional reading available at OnePetro: www.onepetro.org

SPE 145080 • “Reservoir Engineering for Unconventional Gas Reservoirs:  What Do We Have To Consider?” by C.R. Clarkson, University of Calgary, et al.

SPE 144321 • “Integrating All Available Data To Improve Production in the Marcellus Shale” by Efe Ejofodomi, Schlumberger, et al.

OTC 21491 • “GIS Development for Geophysical- and Geotechnical-Data Integration: Application to West Africa Geohazard Assessment” by G. Dan-Unterseh, Fugro France SAS, et al.

OTC 21538 • “GIS Technology Development for Sediment Characterization of Angolan Deepwater Soil Conditions” by M. Hamon, Angolan Deepwater Consortium (Doris Engineering), et al.
Selecting a Completion Strategy for Sand Control and Optimal Production Rate - Unayzah Sandstone Reservoir
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 131078, ’Selection of Completion Strategy for Sand Control and Optimal Production Rate - Field Examples From Saudi Arabia's Unayzah Sandstone Reservoir,’ by Zillur Rahim, SPE, Bandar Al-Malki, SPE, and Adnan Al-Kanaan, Saudi Aramco, prepared for the 2010 SPE Asia Pacific Oil & Gas Conference and Exhibition, Brisbane, Australia, 18-20 October. The paper has not been peer reviewed.

For field development, it is important to identify reservoir structure, heterogeneity, rock properties, and fluid characteristics to select an optimal development strategy for enhancing production and increasing recovery in a cost-effective manner. Therefore, a detailed reservoir description and characterization is required by use of geo-physical, geological, and engineering data. This condensate-rich, high-flow-capacity, and highly sanding deep gas reservoir was developed gradually and optimized to select the most appropriate drilling-and-completion technique.

Introduction

Saudi Aramco’s SA-1 field produces from the Permian Unayzah formation. The first well drilled penetrated the Unayzah-A zone in 1997 and showed excellent reservoir quality. Cores were collected from the well and, subsequently, from other wells confirming unconsolidated reservoir rock with low Young’s modulus and compressive-strength values.

To avoid sanding during production, early wells in this field were completed as vertical wellbores with frac-pack stimulation using premium screens, even though difficulties were encountered during frac-pack installation. With technology advances in drilling and completion, the development method shifted to drilling horizontal and highly slanted holes. This method eliminated deploying the frac-pack system, increased reservoir contact substantially, and improved well performance. To protect well integrity and eliminate sand production, expandable sand screens (ESSs) were used for completing the wells. Higher sustained gas rates were achieved with a reduced non-Darcy skin, sanding was eliminated, and risks related to deployment of the completion equipment (ESS) were reduced.
Getting Beyond Gasland
Authors: Rao Vikram
Published: February 2015

Guest editorial

No shale gas production issue may be more fraught with partisan rhetoric than the possibility of methane in drinking water. Flaming faucets make for great imagery no matter the actual frequency of occurrence.

Well water contamination is personal and frightening. Carbon dioxide in the air barely registers on the average personal anxiety scale, but the quality of well water makes for avid reading and activism. In the case of shale gas, the industry response has been sweeping in denial. Both sides are playing fast and loose with the English language.

Shale gas operations can contaminate aquifers in potentially two ways. One would be through the leakage of chemicals used in fracturing (i.e., a liquid contaminant). The second would be the infiltration of aquifers by produced methane, a gaseous contaminant. If present, a portion may be released as a gas, as spectacularly depicted in the well-publicized documentary Gasland. Natural occurrences such as the Eternal Flame Waterfall in the Shale Creek Preserve in New York demonstrate methane intrusion into a freshwater source. The name follows from the fact that the gas remains lit with a visible flame under the rock overhang of the waterfall.

Methane is odorless and colorless, so it is hard to identify. It leaves no taste in the water, but can be hazardous if it collects in an enclosed space. When used in commerce, the industry deliberately adds mercaptans, a smelly substance (travelers on the New Jersey Turnpike near refineries know the smell well) for added safety. Gas leaks in a commercially supplied setting, such as a kitchen or furnace, are therefore detectable by smell. Leaks from a well would not be detectable by smell.

Natural contamination is either from relatively shallow biogenic methane or from thermogenic gas from deep deposits escaping upward along faults and fissures. The latter are generally caused by tectonic activity. The two types of gas leave fairly different fingerprints and often can be distinguished on that basis. Good oil and gas exploitation practitioners will avoid producing in areas with significant vertical leak paths because they impair normal sealing mechanisms.

Despite the seemingly sound scientific fingerprint techniques available, identifying the source of gas is subject to interpretation. This is particularly the case when, within the class of thermogenic origin, efforts are made to identify the age of the rock from which the leakage took place. In principle, both the isotope signature and the natural gas liquids (NGL) content have relationships with rock age. These relationships are not always well behaved enough to be unequivocal.
Sensabot: A Safe and Cost-Effective Inspection Solution
Authors: JPT staff _
Published: February 2015

Young Technology Showcase

In response to the oil and gas industry’s need to improve productivity while managing health, safety, and environmental (HSE) risks, Carnegie Mellon University’s National Robotics Engineering Center (NREC) developed and launched Sensabot, a mobile robot that it says can safely and cost-effectively inspect and monitor hazardous and remote production facilities. 

The robot performs the same inspection and reporting tasks that humans do, such as monitoring the condition and performance of production equipment and areas, but without the risk associated with workers becoming exposed to hazardous conditions. The robot’s ability to operate in flammable and explosive conditions and its mobility distinguishes it from current energy industry inspection technology. It provides the monitoring and reporting capabilities of separate stationary instrumentation and also can respond to dynamic situational conditions.

The primary business incentive for using this robot is the alleviation of HSE risk, as well as the reduction of logistic and manpower costs associated with worker-performed inspections. Also, because the robot offers a variety of sensor capabilities, the facility operator can reduce the number of fixed sensors at the site, and the cost and risk associated with workers installing and maintaining these sensors. While this robot requires regular maintenance, it can be performed in safe and well-equipped workshops.

Robot Technology and Specifications

This robot is designed to meet Inter-national Electrotechnical Commission (IECEx) standards for electronic equipment operating in flammable and explosive environments. The robot design also complies with NACE MR0175/ISO 15156, the standard for materials used in H2S-containing environments in oil and gas production. The robot meets the American National Standards Institute safety standards for guided industrial vehicles and industry standard for human factors engineering guidelines.

The robot is a battery-powered machine controlled by a human operator through a remote Wi-Fi link and joysticks. The complete robot system also includes infrastructure components, such as a customized dumbwaiter elevator and a cog rail ladder for cost-effective integration into multilevel production facilities such as drilling rigs and refineries.
Increased Oil Production With Something Old, Something New
Authors: Rassenfoss Stephen
Published: February 2015

Pumping is stopped to allow a pressure test to see if the formation will allow free movement of chemicals used to free the remaining oil in this old Oklahoma field.

Enhanced oil recovery (EOR) has become fertile ground for emerging—and re-emerging—technologies.

Emerging from laboratories are materials based on nanotechnology that could change what is possible with aging reservoirs. Researchers are working on making carbon dioxide foams built to last, time-release coatings to deliver gels deep into reservoirs, and tracers for real-time waterflood tracking.

Re-emerging are chemical EOR methods that have been around for 30 years but whose development was stunted by a long stretch of low oil prices. Higher prices are now inspiring a second look at EOR methods, taking advantage of advances in chemistry and computing to create cost-effective ways to rework underperforming old fields.

“It didn’t happen when the technology stopped developing in the 1980s,” said Jeff Harwell, a professor at the University of Oklahoma, who has been a catalyst for this re- emerging technology. “My perception is we are just to the point in the industry where oil prices have risen to the level where it is economic.”

Continued oil prices near USD 100/bbl makes EOR an attractive possibility—the estimated cost to produce plus the profit margin needed to justify the risk is about USD 60/bbl, Harwell said—but, for the many independents that own older fields, the cost of reducing salinity levels in their fields in order to use the available chemicals has been prohibitively high.

Harwell said he and others he knew in EOR realized that, while the economics once again favored it, work was needed to make EOR a realistic option for small and mid-sized operators whose budgets and appetite for risk are both limited. They worked with chemical companies to develop improved surfactants that worked without having to make costly modifications to fields, improved techniques for analyzing and planning EOR projects to increase the chance of success, and started a company to demonstrate what they could do.

He is not alone. Harwell pointed out that others, such as Gary Pope, a professor at The University of Texas at Austin, whom he describes as the EOR guru, is working with a chemical company to create improved surfactants. Big EOR service providers, such as Tiorco and Surtek, are also working on new things.

It is a tough sell, but one with big potential. In Oklahoma, only 14 billion bbl of the 82 billion bbl in the ground have been produced, he said. Many fields date back to the early days of oil exploration when the focus was on pumping oil as fast as possible. “It was really before petroleum engineering was a discipline,” Harwell said. Production was limited by early over-production and poorly done waterflooding experiments, adding to the petroleum engineering expertise required to rework these fields.
Mature Fields Hold Big Expansion Opportunity
Authors: Parshall Joel
Published: February 2015

Mature fields

While big discoveries and major new developments deservedly grab the headlines, mature fields are the backbone of global oil and gas production. Revitalizing these fields extends their productive lives and offers significant opportunity to expand worldwide reserves.

A 2011 report, “Mature Oil Fields—Unleashing the Potential,” by IHS Cambridge Energy Research Associates, indicated that approximately two-thirds of global daily average oil production comes from mature fields and that the percentage is increasing over time. The report considered fields mature if they had produced more than 50% of their established proved plus probable resource estimates or had produced for more than 25 years.

The term mature field does not have a single definition. Many engineers consider a field mature when production has declined to less than 50% of its plateau rate. Individual companies may apply their own definitions.

“We consider the subsurface and the surface,” said Olivier Heugas, a member of the mature field team at Total’s headquarters near Paris. “For the subsurface, we consider a field mature when the cumulative production has reached 50% of the initial 2P (proved plus probable) reserves. And for the surface, given the aging facilities, we consider a field mature after 10 years of production. So when one of the two criteria is reached, we consider it a mature field.

“There are other criteria we might consider, such as BSW (basic sediment and water) levels or a sharp increase in gas/oil ratio or depletion rate. It is on a case-by-case basis. There have been young fields with these subsurface or surface problems, and other fields that have produced for 10 years without these problems.”

A Huge Global Resource

Regardless of the definition, mature fields are a huge global resource. With reserves categorized as proved or probable, attempts to expand reserve levels come at a relatively low risk. Modest additions to a base of this size can be very substantial.
Data Mining Applications in the Oil and Gas Industry
Authors: Abou-Sayed Ahmed
Published: February 2015

Data mining and analytics

The recent proliferation of resources exploitation, in both traditional and unconventional basins, has led to more upstream oil and gas industry activities in more regions than ever. These newer activities, when added to the already challenging work environments in such frontiers areas as deep water and the Arctic, place tremendous demands on the industry to work more efficiently and avoid risks to people, capital, and the environment. An emphasis on monitoring and assurance of the production operations during exploitation has caused the oil and gas industry to enter the digital age during these last two decades in a grand way and has generated what the information technology (IT) industry calls “big data.” Data acquisition in instrumented wells and monitoring of fields and operations processes are routinely carried out in both real-time and post-mortem modes. Management and use of this big data have become critical for the industry and its stake holders, including regulators and financiers. Integration of data analytics into the practice of petroleum engineers is essential to establishing a vision for the oil and gas industry to move toward data-based decisions in the production and operations arena.

The largest amount of computing power in the industry so far has been dedicated to the collection and storage of information (databases and warehousing) as a result of the low cost and portability both of electronic sensors and computer memory. Great emphasis has been put on automated reporting, standardized presentations, and streamlined data transfer to cut costs for data processing and dissemination. Even when no immediate need for the data was present, the low cost of data collection has driven company decision makers to support data storing and sorting for later analysis.

Current databases contain transactions that can be stored and retrieved without relying on employees’ memories. Unfortunately, while information banks are full, clients are not communicating efficiently and data sharing sometimes is inhibited by the size of the specialized warehouses. Integration of the data and coincidence of the information seen by all team members across the organization has been lacking. The more serious gap in this digital age has been in the transformation of this data into information and knowledge that could drive management actions or become the basis for corporate-level decisions.
Improving Horizontal Completions in Heterogeneous Tight Shales
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146998, ’Improving Horizontal Completions in Heterogeneous Tight Shales,’ by Roberto Suarez-Rivera, SPE, Chaitanya Deenadayalu, Maxim Chertov, SPE, Ricardo Novalo Hartanto, SPE, and Patrick Gathogo, Schlumberger, and Rahul Kunjir, University of Utah, prepared for the 2011 Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed.

Production from nanodarcy-range-permeability shale formations requires extensive hydraulic fracturing, large volumes of water, and closely spaced wells. Comparing calculations of the possible fracture-surface area created during treatments to production results indicates that a large portion of that surface area is ineffective for production, resulting in ineffective use of resources. A fundamental understanding is required to improve the efficiency of horizontal completions in producing shales. The objective of this study was to improve completion design and horizontal-well-completion efficiency.

Introduction

When considering tight-shale-formation characterization and completion design, one should evaluate the formation characteristics conducive to economic production: reservoir quality (RQ), representing the multiple properties defining reservoir potential, and completion quality (CQ), representing the multiple properties defining the potential for creating and sustaining a large surface area in contact with the reservoir. RQ and CQ properties vary in the near-wellbore and far-wellbore regions. For CQ, the far-wellbore region represents the region of contact between the created fracture and the reservoir. Well production depends on this surface area being in contact with good RQ, and depends on conditions of containment, fracturability, rock/fluid interactions, and loss of surface area and fracture conductivity during production. The near-wellbore region represents the choking point between the created surface area and the wellbore. The goal is to maximize connectivity between the fracture system and the wellbore. This goal is attainable by minimizing near-fracture tortuosity, maximizing fracture width, reducing breakdown pressures, and limiting the risk of solids production. The result is a nonsubjective and consistent method that provides a means for understanding variability in fracture performance along wellbores (e.g., inferred from microseismic monitoring, trace analysis, and stage-by-stage flow measurements) and for selecting perforation stages on the basis of measured or log-inferred rock properties. The method also provides a means for monitoring consistency between the predicted values and measured results.
Sanding Prediction Validated by a Perforated Test in a Sandstone
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 158255, ’Sand Prediction by Different Criteria and Validation by a Perforated Test in a Sandstone,’ by Y. Wang, SPE, Petro-Geotech, and E. Papamichos, SPE, Sintef Petroleum Research, prepared for the 2012 SPE Heavy Oil Conference Canada, Calgary, 12-14 June. The paper has not been peer reviewed.

Sand production from a perforated sample was determined by the onset of a significant discrepancy between strains in orthogonal directions. The onset was analyzed with three sanding models—shear-failure, cohesive-tensile-failure, and effective-plastic-strain (EPS) models. The EPS model provided results closest to testing. Equivalent plastic displacement (EPD) is proposed as an additional critical parameter that enables determining the sanding onset directly.

Introduction

Predicting sanding is increasingly important in completion and production engineering. If the sanding point is surpassed, engineers must determine if, when, and what sand-control strategy is required, and these determinations critically affect the decisions regarding the type of completion selected, such as fracturing, horizontal well, open hole, or cased hole. Engineers also need to evaluate the benefit of oil-production enhancement if no sand control is implemented. All these issues can depend on the accuracy and reliability of the sanding prediction. Even though a Mohr-Coulomb (M-C) criterion is used widely for the critical-shear-failure or sanding conditions, it has been considered too conservative; therefore, a Lade model is proposed.

Study

Three criteria, reflecting different sanding mechanisms, are applied extensively to sanding problems in the field, and, consequently, different critical sand pressures or drawdowns are generated. Use of these criteria to determine the sanding point from a single test or field condition can yield more questions than answers; therefore, defining an adequate criterion could be quite helpful. The use of stress-oriented criteria usually is simple, requiring fewer parameters, but such criteria can be too conservative, and, more importantly, those required parameters cannot be measured and monitored directly. The models used with stresses often are determined statically (i.e., they cannot be linked uniquely to the deformation), whereas extensive deformation can be linked proportionally to sanding, which is essential to determine the critical point both physically and mathematically. Another issue of the use of stress-oriented criteria defined by the M-C and cohesive-sanding models is that the parameters cannot be measured or monitored in the laboratory or in the field; instead, they are acquired from an indirect strength measurement because stresses or strengths can only be interpreted, not measured. Alternatively, a deformation-related criterion is proportional to well unloading and the required input can be monitored and measured directly.
Data From Above: The Advantages of Unmanned Aircraft
Authors: Jacobs Trent
Published: February 2015

Unmanned Aerial Vehicle Technology

Making them fly was the easy part. Making them useful was the next challenge. And now unmanned aerial vehicles (UAVs) are being put to the test to determine where they are the most applicable to the oil and gas industry. Companies and university researchers developing these “flying computers” believe that their sector is ready to rapidly expand, because of recent technological advancements and legislation that will open up the unmanned skies in the industry’s largest potential market by 2015: the United States.

UAVs are already being used by some oil and gas companies to inspect flare stacks and track migrating wildlife and ice floes in the Arctic. In the near future, UAVs will be used as important tools to respond to oil spills and pipeline monitoring, and in offshore installation and decommissioning operations.

A few years ago, the militaries of the world held a virtual monopoly on the application of UAV technology, and UAVs available to the private sector were little more than eyes in the sky with limited functionality. Today, commercial UAVs are the benefactors of miniaturized electronics, partly thanks to the smartphone industry and advanced software programs specifically designed to make sense of the different types of data that can be gathered while flying. Equipped with lasers, high-definition cameras, thermal imaging systems that can “see” at night, and an array of other sensors, advocates of UAVs claim they are not simply cheaper alternatives to fixed-wing aircraft and helicopters, but in many ways are more capable and, without question, safer to operate.

Last fall, BP completed an experimental flight in Prudhoe Bay, Alaska, using a quadrotor UAV developed by Canadian-based Aeryon Labs. Quadrotor UAVs, also called quadcopters, use four rotors to lift and move the aircraft and are known for their maneuverability. At the time, US authorities were only issuing flight certificates to determine the airworthiness of UAVs without allowing commercial operations. BP completed the test run to determine how Aeryon’s UAV could inspect oilfield equipment and pipelines to assess maintenance needs.
Developing Flank Areas in a Giant Carbonate Field With Horizontal-Well Placement
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 161591, ’Development of Flank Areas in a Giant Carbonate Field With Optimal Placement of Horizontal Wells,’ by Sameer Khan, SPE, Ali Al-Shabeeb, Zankar Jani, Yousef Azoug, Nguyen Minh, and Harshad Patel, SPE, Zakum Development Company, prepared for the 2012 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed.

Successful development of flank areas depends on accurate reservoir characterization—in particular, water-saturation distribution—in addition to the optimal areal and vertical placement of wells. In relatively thin reservoirs, horizontal wells are generally preferred to increase reservoir contact; the proper spacing and vertical placement of these wells are critical. To test the initial concept in the field, two existing producers were converted into injectors, and pressures were monitored at the offset producers.

Introduction

The subject oil field is one of the world’s largest offshore carbonate reservoirs and has a production life in excess of 100 years. The field was historically developed with wellhead tower platforms made of steel structures and a combination of vertical and 1-km-long horizontal wells in a five-spot pattern. A new development plan was proposed in 2008 that deployed artificial islands as drilling centers and used extended-reach- drilling technology. In addition, well counts were significantly reduced by deploying longer (3-km) horizontal laterals, referred to as maximum-reservoir-contact (MRC) wells. The development plan comprised both surface and subsurface components, which were effectively integrated to provide maximum flexibility in terms of development options as well as handling of reservoir uncertainties. Because the aquifer support for the subject field is weak, the development consists of a waterflood with line drive to be followed later by gas injection. This island-based plan was approved by shareholders in 2008, and implementation began soon thereafter.

The development plan includes a comprehensive subsurface development scheme based on the available data and prediction tools. Development-plan optimization soon began as more data were being acquired and new reservoir models were built. This work is focused on development-plan optimization of two large flank areas of the largest reservoir in the subject field (south and east flanks in Fig.  1). These flank areas contain very large capillary transition zones that, although only a few hundred feet high, extend to several kilometers areally because of very low reservoir dip (1 to 2°) in a 150-ft-thick reservoir. Therefore, appropriate areal and layer placement of MRC wells in flank areas is a critical task that requires careful attention.
Fracturing-Treatment Design and Reservoir Properties Impact Shale-Gas Production
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16400, ’Analysis of the Impact of Fracturing-Treatment Design and Reservoir Properties on Production From Shale-Gas Reservoirs,’ by C.E. Cohen, C. Abad, X. Weng, K. England, A. Phatak, O. Kresse, O. Nevvonen, V. Lafitte, and P. Abivin, Schlumberger, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.

This paper sheds light on the nonlinear physics involved in the production of shale-gas reservoirs by improving the understanding of the complex relation between gas production, reservoir properties, and several treatment-design parameters. The authors ran 28 simulations to cover the 2D parametric space of proppant size and fracturing-fluid viscosity for a range of parameters (detailed in the complete paper). More than 1,400 simulations were run in this parametric study, and the results provide guidelines for optimized treatment design.

Introduction

Production from shale-gas reservoirs depends greatly on the efficiency of stimulation. The accumulated experience in our industry with the technique of hydraulic fracturing has led to best practices in treatment design that have contributed to the rapid increase in productivity of shale-gas wells over the last decade.

The objective of this paper is to present a parametric study on the relation between the parameters of a treatment design and the production outcome based on numerical simulation. To generate an extensive number of simulations, the workflow is automated with a script that sequentially runs all the simulation cases, archives the results, generates visualization outputs, and creates a simulation report. This method enables more than 100 simulations overnight, depending on the complexity of the cases.

The methodology used in this study begins with constructing a base case built from the Marcellus shale data. The outputs for each set of simulations are accumulated production after 6 months, 1 year, and 3 years; total propped length and average propped conductivity are regarded as a function of both proppant size and fluid viscosity. A total of 1,467 cases was simulated for this parametric study (see the complete paper for a full discussion of results of these simulations).

Base Case

For the base case of this parametric study, permeability is 200 nd and the horizontal stress anisotropy is 1%. The conductivity of unpropped fractures is fixed at 0.001 md-ft. The completion is a horizontal well, and the base case is a single stage of pumping through four perforation clusters that are 100 ft from each other.

The treatment is made up of 224,576  gal of fracturing fluid and 183,700 lbm of proppant pumped at 80  bbl/min. The schedule begins with 18% of pad followed by slurry with a proppant concentration of 1 ppa. For simplicity, the fracturing fluid is assumed to have Newtonian rheological behavior.
Hands-On Teaching for Petroleum Engineers in the Twenty-First Century
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 160017, ’Hands-On Teaching for Petroleum Engineers in the Twenty- First Century: A Balance Between High-Tech and Simple Demonstrators’ by Catalin Teodoriu, SPE, ITE/TU Clausthal, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed.

Several years ago, a new concept of teaching undergraduate and graduate students was introduced at the Clausthal University of Technology (CUT) based on the implementation of hands-on teaching systems that not only expose the students to physical models but also require them to build such models or to generate experiments using existing models. The results show an improved learning capability in combination with better knowledge transfer between teacher and students. This paper presents the results of student competitions held at CUT.

Introduction

Several governmental associations have reported that the teaching process in engineering schools is too theoretical. In the 3-year program implemented at CUT, hands-on teaching is focused on simple demonstrators that are designed and built by students under faculty and staff supervision. Petroleum engineering is one of the sciences that cannot always be experimentally shown in a straight-forward fashion (for instance, imagine reservoir engineers trying to show a replica of the reservoir in full scale!). Drilling and production systems and processes are easier to model. Field trips are always welcome, but they take time and the students have to give up other important courses.

The mentoring process has been identified by SPE and the industry to be a key in preparing future engineers. But are the students ready for the mentoring process? During the CUT project, students are not only involved in their design project, but are also guided toward the acceptance of mentoring and preparation for a career.

When teaching freshmen, the focus is on providing them the basics for their future career in terms of applied mathematics or physics. They are expected to calculate and estimate complicated processes, but sometimes we forget to ask them such basic questions as, “Do you know what a drillstring looks like?”

Goals of the Hands-On Teaching Initiative

The objectives of the hands-on teaching initiative include the following:

Development of hands-on and visual tools to enhance learning opportunities

Integration of theoretical and hands-on experiences into lectures

Determination that the equipment developed has an impact on core courses in drilling engineering, advanced drilling engineering, completion, and workover

Improvement of critical thinking and problem-solving skills of students by involving them in the learning process, allowing individual experimentation, and providing for tool interchangeability

Development of visual aids for students and young people visiting the department
Technology Focus: Sand Management and Frac Pack (October 2013)
Authors: Azeemuddin Mohammed
Published: February 2015

Technology Focus

Sand production is an unintended consequence of oil and gas production from unconsolidated and semiconsolidated reservoirs, causing damage to surface and subsurface well equipment and reducing the hydrocarbon productivity. Sand production has been one of the major challenges facing the oil and gas industry for decades. It continues to be so, despite many advances in the modeling and predictive capabilities, deployment of sophisticated measurement and sand-control devices, and improved surface handling capabilities. 

The challenge keeps growing as we move into more-complex and -mature reservoirs involving high development costs and lower recoveries. Sand production has traditionally been minimized through active means, such as installing appropriate sand-control devices, limiting drawdown (rate of production), or both. Another approach to limiting the damaging effect of sand production is to allow it to take place at a controlled rate along with hydrocarbon production. The produced solids then are removed at the surface upstream of the choke. This will allow a sustained rate of oil and gas production, simultaneously minimizing sand production’s negative effects on surface facilities. The choice of additional costs of installing sand-control equipment must be weighed against the incremental benefit derived from it, not only at the current reservoir conditions but also throughout the life of the well or field, considering depletion and associated stress change. 

Safe and economical field exploitation calls for continued efforts and advancement in the understanding of rock behavior under in-situ conditions, both current and expected; accurate modeling of downhole conditions through fit-for-purpose failure models and modeling techniques and tools; and effective implementation of field strategies.

The papers I have selected touch upon some of the ongoing efforts in these areas and by no means represent a full coverage of the wide spectrum of efforts under way. Additional interesting papers involving field applications and case studies, in no way less important, have also been identified.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 158922 Unraveling the Myths Associated With Selecting Standalone Screens and a New Methodology for Sand-Control Applications by Rajesh A. Chanpura, Schlumberger, et al.

SPE 158371 Workflow To Evaluate Maximum Allowable Treating Pressures, Tubing Movement, and Tubular Limits for Deepwater Subsea and Dry-Tree Frac Packs by Marshal Strobel, Halliburton, et al.

SPE 165206 Significant Increase in Sand-Control Reliability of Openhole-Gravel-Pack Completions in ACG Field, Azerbaijan by Yoliandri Susilo, BP, et al.