bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Contract Between Management and the Petrotechnical Professional
Authors: Edmundson Henry , Bamford David
Published: February 2015

Talent & Technology

The continued search for oil and gas relies in equal measure on good management and superior petrotechnical expertise. The key is ensuring that the two worlds mesh smoothly and create a working environment that motivates both parties to succeed. This is less obviously achieved than might be thought for a number of factors.

First is the scarcity of top-quality petrotechnical professionals (Fig. 1). This used to be blamed on the famous “crew change,” which described the paucity of recruits during the oil price crash of the 1980s. But things have now changed. The past few years have seen abundant recruiting by both operators and the service industry, and the crew change problem has morphed into the challenge of accelerating the development of thousands of young professionals to fill the still prevalent mid-career gap. The result is an industry obsessed with accelerating employee development.

Second is the market force generated by the continued lack of midcareer petrotechnical professionals. These lucky individuals command a price in excess of their equivalent managers, and so even do the young aspirants joining their ranks. With the oil price robust around USD 100/bbl and global upstream activity buoyant, there remains an extraordinary lack of competent geoscientists, drilling engineers, and petroleum engineers. And they know it. Never has it been so easy to jump ship, hoping for a better future.

Third is the meeting point between management and the petrotechnical expert. Both obviously aspire to business success, but beneath broad corporate goals lurk important differences. In companies of any reasonable size, managements must ensure that their machine to find and extract oil and gas is properly assembled, well lubricated, and working to maximum efficiency. Standards and discipline are important; within well-defined limits, employees are expected to conform.

The technical expert, however, marches to a different tune, motivated by quite different criteria. When it comes to creativity and improving technical knowledge, petrotechnical professionals prefer less rather than more management, or even no management. The ideal state is being self-directed; satisfaction comes from solving tough technical problems. When it comes to their career, peer recognition and involvement is as important as management input. In short and at risk of working an analogy beyond breaking point, the square peg that is the technical expert may not always fit the round holes of the smooth-running business machine. How to manage this less-than-exact fit requires some unusual strategies.
Technology Focus: Reservoir Simulation (July 2014)
Authors: Bailey William
Published: February 2015

Technology Focus

As the development of shale oil and gas becomes increasingly significant, so does the need for modeling tools for their accurate and timely forecasting. The basic question then arises: Are the simulation tools that we have suitable for the job? Can they explain, and ultimately forecast, the contribution to flow from natural or hydraulically induced fractures? Ultimately, we need to be confident that the results from such models are sufficiently reliable for decision-making purposes. As Alexandre Emerick stated in JPT (April 2014), “The goal is to generate models for production forecasting aiding the decision-making process involved in the development and management of petroleum reservoirs.”

The ability to model this increasingly important asset class is one of the primary issues facing reservoir and simulation engineers today. Our existing arsenal of simulation tools is certainly time-tested for conventional assets, but can they deliver reliable forecasts for this emergent class? Recent literature is rich with relevant studies ranging from fundamental laboratory experiments to entirely empirical, data-driven, approaches for predictive reservoir management. These articles raise numerous questions, including the possible oversimplification of a complex problem, the very nature of the production mechanisms, and the role played by any pre-existing discrete fracture networks.

Additional concerns relating to accuracy and reliability of the underlying data used to populate such models have also been raised. Keeping an open mind on this topic is, I feel, appropriate. One needs to balance the very real need for such predictive tools today with the recognition that future evidence may disrupt certain preconceptions. To this end, four articles have been selected that span a spectrum of ideas. One considers practical applications and solutions, while another covers the emerging technique of molecular simulation. Another eloquently probes various notions in our current state of understanding of shale assets and examines issues in interpreting the forecasts furnished by our simulation models. The fourth article demonstrates some creative thinking by representing a planar fracture by use of a proxy comprising a coupled flowing network model, a concept that may prove flexible and warrants further investigation.

Conventional modeling tools used to predict flow in tight, fractured shales (e.g., dual-porosity models, local grid refinements, tartan grids) may, indeed, provide reliable forecasting. Analytic and data-driven approaches are also acceptable in some circumstances. However, as our knowledge in exploiting these assets deepens with new theory, laboratory experiments, and field and operational experience, we should be prepared to reconsider some of today’s axioms in the future.
A Critical View of the Current State of Reservoir Modeling of Shale Assets
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165713, ’A Critical View of Current State of Reservoir Modeling of Shale Assets,’ by Shahab D. Mohaghegh, SPE, Intelligent Solutions and West Virginia University, prepared for the 2013 SPE Eastern Regional Meeting, Pittsburgh, Pennsylvania, USA, 20-22 August. The paper has not been peer reviewed.

The coupling of hydraulic fractures and natural-fracture networks and their interaction with the shale matrix remains a major challenge in reservoir simulation and modeling of shale formations. This article reviews methods used to understand the complexities associated with production from shale to shed light on the belief that there is much to be learned about this complex resource and that the best days of understanding and modeling how oil and gas are produced from shale are still ahead.

Introduction

Preshale Technology. The phrase “preshale” technology aims to emphasize the combination of technologies that are used to address the reservoir and production modeling of shale assets. In essence, almost all of the technologies used today for modeling and analysis of hydrocarbon production from shale were developed to address issues that originally had nothing to do with shale. As the shale boom began, these technologies were revisited and modified in order to find application in shale.

Conventional Discrete Fracture Network. The most common technique for modeling a discrete natural fracture (DNF) network is to generate it stochastically. The common practice in carbonate and some clastic rocks is to use borehole-image logs to characterize the DNF at the wellbore level. These estimates of DNF characteristics are then used for the stochastic generation of the DNF throughout the reservoir.

The idea of the DNF is not new. It has been around for decades. Carbonate rocks and some clastic rocks are known to have networks of natural fractures. Developing algorithms and techniques to generate DNFs stochastically and then couple them with reservoir-simulation models was common practice before the so-called “shale revolution.”

A New Hypothesis on Natural Fractures in Shale

What are the general shapes and structures of natural fractures in shale? Are they close to those of the stochastically generated set of natural fractures with random shapes that has been used for carbonate (and sometimes clastic) formations? Or are they more like a well-structured and well-behaved network of fractures that have a laminar, plate-like form, examples of which can be seen in outcrops (such as those shown in Fig. 1)?

Shale is defined as a fine-grained sedimentary rock that forms from the compaction of silt and clay-sized mineral particles commonly called mud. This composition places shale in a category of sedimentary rocks known as mudstones. Shale is distinguished from other mudstones because it is fissile and laminated.
Technology Focus: Artificial Lift (July 2014)
Authors: Noonan Shauna
Published: February 2015

Technology Focus

The digital repository of our valuable SPE papers was first launched as the SPE eLibrary in 1997 and subsequently was updated as OnePetro in 2007. This great collection has become a valuable resource for our global industry. However, several years ago, I noticed that many of the great case studies and technological advancements related to artificial lift were being presented at industry events but not published and captured within OnePetro. I made it a personal mission to change that.

Within SPE today, there are more opportunities for authors to present and publish their work related to artificial lift. For example,

The Progressing Cavity Pump (PCP) Workshop was converted to a conference format, which now offers a call for papers.

The SPE Digital Edition series “Getting Up to Speed” for both electrical-submersible- pump and PCP technology provided an invitation to authors who previously gave presentations only at industry events to document their work as an SPE paper in these editions and in OnePetro.

The Artificial Lift Conference and Exhibition (ALCE) series in the Middle East, South America, and North America was created to bring together the regional artificial-lift experts and document their work as SPE manuscripts. Note that SPE is still working to coordinate these events so that their schedules do not conflict with one another.

The ALCE North America event in 2014 focused on seeking out authors with outstanding presentations at regional events (SPE or not), as well as bodies of work that needed to be documented in OnePetro for the benefit of the global artificial-lift community.

The history of artificial-lift technology and the story of its outstanding contributors and innovators have been missing within the SPE realm; however, this is about to change. At the ALCE North America event to be held 6-8 October in Houston, two special events are taking place. The Artificial Lift Historical Exhibit and the Legends of Artificial Lift Awards will be documented and placed in SPE’s historical archives.

The primary and additional papers selected for this feature, with the exception of one Offshore Technology Conference paper, were presented at international events that did not exist a decade ago. The void of artificial-lift information that existed within OnePetro is beginning to be filled and will disappear if we work collectively to seek out our peers and encourage them to publish their outstanding accomplishments and lessons learned as SPE papers.
Integrating True Valve Performance Into Gas Lift Design and Troubleshooting
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 16656, ’Integrating True Valve Performance Into Production-System- Analysis-Based Gas Lift Design and Troubleshooting for Dukhan Field, Qatar,’ by Sanjay K. Singh, James W. Hall, SPE, Eraky Khalil, Balsam Al-Marri, and Reem Al-Abdulla, Qatar Petroleum, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.

Production-system-analysis methods have been used and are currently used for gas lift design and troubleshooting. These methods, however, have been found to be inadequate in several cases for achieving optimum design or troubleshooting problems. To make up for the inadequacy, a new approach has been applied that uses the Valve Performance Clearinghouse (VPC) database. The new approach joins well performance from production-system analysis and true valve performance from the VPC database to form an integrated system performance tool.

Introduction

Qatar Petroleum’s Dukhan field is onshore Qatar approximately 80 km west of Doha. The number of wells in this field requiring artificial-lift assistance has increased over the past few years, and the trend is likely to continue because of reservoir-pressure decline and rising water cut. The availability of gas coupled with compression and distribution-facility availability has made gas lift a natural choice among various artificial-lift methods. The increasing number of wells using gas lift makes gas lift design and troubleshooting key factors in achieving crude-oil-production targets.

Production-System-Analysis-Based Procedure

Production-system analysis determines a well’s inflow and outflow performance and combines them at a solution node to obtain the well’s system performance. The purpose of gas lift is to lighten the flowing production gradient by injecting gas into the production string of a well. Gas injection into the production string improves the well’s outflow performance by increasing the gas/liquid ratio (GLR) of the production stream from the formation GLR to an objective GLR (OGLR). There are two phases to gas lift operation: unloading and production.
High-Power ESP Tubing-Hanger Connector for Deepwater Downhole Applications
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 24138, ’Reliable High-Power ESP Tubing-Hanger Connector Systems for Deepwater Downhole Applications,’ by Sami Spahi, Teledyne Oil and Gas, and Pamela Parsley, Chevron Energy Technology Company, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed.

Reliability of subsea equipment is an indispensable requirement in deepwater applications. Tubing-hanger (TH) -connector systems can be a critical failure mode for electrical submersible pumps (ESPs) in high-pressure/high-temperature (HP/HT) environments. Through use of reliability tools such as fault-tree analysis (FTA), failure-mode effect and criticality analysis (FMECA), and systems reliability block diagrams (RBD), it was established that improving the reliability of the TH-connector system has a direct effect on the unintervened life of the ESP electrical system.

Project Basis of Design

A joint development project between the operator and the connector-system supplier focused on the design, installation, and intervention of downhole ESPs in deepwater subsea wells in the Lower Wilcox developments in the Gulf of Mexico. The system design encompasses the ESP completion, subsea wellhead, tree, TH, and power and control system. The system design criteria are for 8,000-ft water depth and a 14-mile tieback (Fig. 1).

Connector-System Reliability Overview

At the start of the project, the operator, the connector-system supplier, and other equipment vendors met and agreed to align their reliability plans. Common reliability tools, including FTA, FMECA, and systems RBD, help all collaborators to have a better understanding of the relationship and sensitivity between subsystem reliability and the unintervened life of the ESP electrical system.

FMECA. The FMECA process is typically performed by the present multiple teams to capture different backgrounds and benefits for a wider range of feedback. In this process, each component and subsystem is considered and its corresponding functions are identified. The purpose is to consider the conceivable failure modes associated with each component and function on the basis of prior art, knowledge, and industry experience and then develop plans to mitigate such failure modes in a hierarchy that is based on the criticality.
Gelled Emulsions of CO2, Water, and Nanoparticles
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166072, ’Gelled Emulsions of CO2/Water/Nanoparticles,’ by Fawaz M. Al-Otaibi, Sunil L. Kokal, Yun C. Chang, Jassi F. Al-Qahtani, and Amin M. Al-Abdulwahab, Saudi Aramco, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.

Enhanced oil recovery (EOR) by carbon dioxide (CO2) injection is an effective method for recovering additional oil beyond waterflooding. However, the CO2-EOR process is handicapped, especially in thick reservoirs, by CO2 gravity override. Because of density differences between the injected CO2 and resident fluids in the reservoir, the lighter CO2 tends to rise to the top of the reservoir, thereby bypassing some of the remaining oil. This paper investigates the use of gelling CO2/water emulsions, stabilized by silica nanoparticles, to control the mobility of CO2.

Introduction

The CO2-EOR process, while increasingly important, is handicapped by several challenges. The first challenge is the gravity override of the injected CO2 because of density differences between the injected CO2 and resident fluids in the reservoir. The second is viscous fingering caused by the lower viscosity of the injected CO2. Typical dense CO2 viscosity at reservoir conditions is in the range of 0.05–0.1 cp, which is much lower than the viscosity of resident oil and brine. The resulting unfavorable mobility ratio leads to viscous fingering, causing early CO2 breakthrough, high CO2-usage factors, poor sweep efficiency, and low overall oil recovery. The third challenge associated with CO2 EOR is reservoir geology and heterogeneities, including high-permeability streaks and fractures that can impact the sweep efficiency of a CO2-EOR flood. Most of these challenges have been countered by use of water-alternating-gas (WAG) processes. Although the WAG process improves the mobility of CO2, it loses its effectiveness in controlling CO2 mobility deep into the reservoir and beyond a certain distance from the wellbore.

This paper discusses another technique that provides an excellent alternative to WAG to control CO2 mobility: the CO2/foam emulsion. The main purpose of using CO2 foams is to increase the viscosity of the CO2 and therefore reduce its mobility through the reservoir. This emulsion is generated with water-soluble surfactants, CO2-soluble surfactants, or nanoparticles. This paper investigates the use of gelling CO2/water emulsions, stabilized by silica nanoparticles, to control the mobility of CO2.
Mapping CO2 in Real Time With Downhole Fluid Analysis in the East Irish Sea
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166497, ’Mapping CO2 in Real Time in Hydrocarbon Reservoirs With Downhole Fluid Analysis: First Successful Experience in the East Irish Sea, UK Continental Shelf,’ by B. Quayle, S. James, and M. Quine, Centrica Energy, and I. De Santo, P. Jeffreys, and J.Y. Zuo, Schlumberger, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.

This paper describes the first successful attempt on the continental shelf offshore UK to map carbon dioxide (CO2) in real time while logging during a drilling campaign in the East Irish Sea. Reservoirs in this sea’s basin contain varying proportions of CO2, nitrogen (N2), and hydrogen sulfide (H2S), in addition to oil and methane. Two of these wells develop the Rhyl gas field. Downhole-fluid-analysis (DFA) technologies were deployed with a wireline-formation-testing (WFT) tool to measure CO2 content accurately downhole.

Introduction

The Rhyl field was discovered in 2009 and received development approval in 2012. It is located 11 km north of the North Morecambe field. The North and South Morecambe fields were discovered in the 1970s, with some 7 Tcf of gas initially in place. Production from the Rhyl field extends the longevity of these assets.

Vertical and horizontal variations in CO2 content in the Rhyl field were assessed across the Triassic Ormskirk sandstone, the upper member of the Sherwood sandstone group. The Ormskirk sandstone formation represents the principal reservoir target in the East Irish Sea, comprising high-porosity aeolian and fluvial sandstones with variable grain size and playa mudstones.

Gas Composition in the Rhyl Field

The composition of the gas found in Rhyl includes both hydrocarbon and nonhydrocarbon components such as N2 and CO2. The N2 is derived from late-stage hydrocarbon generation, while isotope data indicate that the CO2 has a magmatic origin. It is believed to have been exsolved from the magma of a series of Tertiary dolerite intrusions into the Ormskirk sandstones in close proximity to the Rhyl field. The samples collected during the drillstem test conducted on exploration Well 113/27b-6 provided several qualitative indications of a higher CO2 content than was originally expected from the correlation with the nearby North Morecambe field: a high gas density measured at the separator and difficulty in sustaining a flare.
Conversations: Not the Beginning of the End, But the End of the Beginning
Authors: Fattahi Behrooz
Published: February 2015

President's column

This is my last JPT column as SPE president, and I am writing it with mixed feelings. I am grateful for having the opportunity to serve, to visit with many of you around the globe and make so many friends, and to have our monthly conversation through this column. But I am also sad that this grand experience is coming to an end.

As I have met with members across the globe this past year, I have focused our conversations on the new and unique challenges posed by the fast-paced changes in our lives.

These challenges are global, and complex. Some of the most critical of these are clearly impacting us today. They include management of human assets, and its associated issues of an aging workforce; recruiting young talent, and developing their skills; intensifying effort for technology development, and speeding deployment in the field; incorporating process optimization, and promoting collaborative efforts to reduce waste, needless duplication, and cost; and the equally important issue of the industry’s public image. These are not new issues, but they have risen to the top and become, in my view, the most critical to the future of oil supply. I have urged our members not to be threatened by these challenges. Challenges create opportunities, and our industry has to constantly show the ability to redefine itself and meet the adversities.

At the end of my term, I believe more strongly than ever that as the largest, most global, and most prestigious professional society supporting our industry, SPE is well positioned to help the industry address many of these challenges. However, to play our role effectively, SPE must continue to face its own challenges. We must maintain the alignment of the vision and the purpose of the organization. We will have to maintain or improve the quality and integrity of our services, and to deliver them to all members wherever they may be. We will have to continue our globalization effort.

We also must continue to initiate and facilitate industry’s discussions of critical technical and professional issues of the future. I initiated creation of an SPE committee that brings together experts on the topics of sustainability to advise SPE on how we can support the industry. I have also formed a task force to examine issues surrounding our industry’s engagement of women in the workforce. SPE will play an important role in providing a forum for a renewed emphasis on safety and environmental protection, and to addressing what changes are needed in operations, equipment, technology, and training in light of the Deepwater Horizon incident.
NORM: Innovative Thinking With Decommissioning and Radioactive Waste
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 125661, ’NORM: The Lessons To Be Learned, New Challenges and Innovative Thinking With Decommissioning and Radioactive Waste,’ by A.L. Smith, SPE, Risk Management Systems, originally prepared for the 2010 SPE International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Rio de Janeiro, 12-14 April. The paper has not been peer reviewed.

New challenges arising during decommissioning and with radioactive waste may be addressed through a combination of current best practice and innovative thinking, provided the les-sons learned and progress over the last century are remembered.  

Naturally Occurring Radioactive Material (NORM)

Opinions differ on what exactly is meant by the term NORM. Reports of the occurrence of significant concentrations of radionuclides of natural origin in the oil and gas industry go back more than 100 years. When radioactive deposits were found on offshore installations in the early 1980s in the UK North Sea, they were initially known as low specific activity (LSA). The term NORM was first coined by this industry in the US during the late 1980s because of the negative connotation of LSA when referring to the radium-rich scales deposited inside well tubulars, surface piping, vessels, pumps, and other production and processing equipment. Since then, the term has become adopted widely beyond the oil and gas industry and now tends to be associated with almost any type of mineral or mineral-processing activity where the presence of radionuclides of natural origin is of interest.

The term NORM now has become firmly entrenched in our technical vocabulary, but as an acronym for “naturally occurring radioactive material” it is actually a misnomer. The descriptor “naturally occurring” refers to the radionuclides in the material and not necessarily to the material itself, which may well be a product of a physical, chemical, or thermal industrial process. Because radionuclides of natural origin are ubiquitous in the environment, it could be argued that all materials are effectively NORM. So this would include all types of minerals (rocks and soil) and all vegetable and animal matter including the food we eat, the water we drink, and even our own bodies.

Use of the term “technologically enhanced naturally occurring radioactive material” (TENORM) could be more accurate; however, its use does not solve the problem and indeed can be misleading because it implies that the materials of concern are limited to those in which the radionuclides have become concentrated as a result of an industrial process. This often is the case, but not always. Materials in their natural state are in principle no less important to consider than materials with activity concentrations enhanced by some form of processing, and any distinction between the two for the purposes of radiation protection is artificial and without any scientific foundation.
Automation and Surveillance Improve Progressing Cavity Pump Performance
Authors: Fryer A.
Published: February 2015

This article is based on paper SPE 136690 by the same author, which was presented at the 2010 SPE Progressing Cavity Pumps Conference, Edmonton, Canada, 12-14 September.

To extend the run life of the pump while producing all available fluid is the goal of all progressing cavity pump (PCP) operators. The primary challenge is to do so without starving the pump and causing damage to the stator. The petroleum industry has been searching for years for a reliable way to control PCPs for pump-off. Several methods have been used, from monitoring torque to manual fluid levels. To date, none have been commercially successful. A method for controlling these wells has been developed combining wedge meter flow technology and microprocessor control of both electric motors through the use of variable frequency drives (VFDs) and hydraulic motors using proportional control valves. This method has proved accurate and reliable, extending run life while producing all available fluids.

Combining this automated technology at the well with a web-based system that feeds back real-time data to a dedicated supervisory control and data acquisition (SCADA) host allows PCP technical experts to diagnose problems, and operators to respond quickly to changing well conditions.

This article discusses the advances in automation and optimization of PCPs.

The acceptance of PCPs in the oil and gas industry has grown worldwide. A major concern is potential damage to the stator if the well is pumped off. The most common prevention is to ensure that there is a substantial amount of fluid level above the pump. Operators taking manual fluid level shots and adjusting pump speed has been the most widely used method to maintain a safe fluid level. With advancements in fluid flow measurement and proven algorithms, the PCP controller has eliminated this concern, while producing all the available fluid from the wellbore without damaging the pump.

With this automated technology and a web-based SCADA system, it became possible to monitor several data trends and discover additional control algorithms. Further development of these algorithms is ongoing.

Pump-Off Control for PCPs

Two main objectives were defined when the theory of the PCP controller was introduced. The first objective was to reduce premature pump failure. The most common failure is stator damage due to pump-off. Pump-off is defined as a lack of fluid entry into the pump. This causes a lack of lubrication to the stator, resulting in extremely high temperatures being generated. The high temperature ultimately burns the elastomer in the pump. The stator’s rubber surface becomes hard, brittle, and cracked. In severe circumstances, the stator contour is torn up, producing rubber at surface. This may be caused by one or a combination of the following problems: plugged pump intake, poor inflow, or production rates exceeding inflow.
Multidomain Data and Modeling Unlock Unconventional Reservoir Challenges
Authors: Ganguly Utpal , Cipolla Craig
Published: February 2015

Technology Update

Completion strategy and hydraulic fracture stimulation are important keys to economic success in low- permeability and unconventional reservoirs such as tight sand and shale. Therefore, engineering workflows in unconventional reservoirs need to focus on completion and stimulation optimization, just as they do well placement and spacing.

The primary obstacles associated with optimizing completions in these reservoirs have been the absence of hydraulic fracture models that properly simulate the complex fracture propagation common in many reservoirs, the lack of efficient methods to create discrete reservoir simulation grids to rigorously model hydrocarbon production from complex hydraulic fractures, the lack of automated fracture treatment staging algorithms, and the lack of ability to efficiently integrate microseismic mapping measurements with geological and geophysical data.

This article details a novel approach for enabling efficient multistage completions, new complex fracture models, unstructured gridding-based reservoir simulation, and a comprehensive integrated workflow developed within single reservoir-centric stimulation design software. Though primarily focused on unconventional reservoirs, this efficient full-cycle seismic-to- simulation workflow is applicable also for conventional reservoirs.

Seismic-to-Simulation Through Stimulation

In recent years, an increasing amount of hydrocarbons in North America have been produced from unconventional reservoirs, with a similar trend expected worldwide. The International Energy Agency projects the hydrocarbon reserves in unconventional reservoirs to be as high as 8 trillion BOE. Most of these low-permeability reservoirs must be hydraulically fractured to produce. In unconventional reservoirs, stimulation is the key step in the seismic-to-simulation workflow.

For unconventional reservoirs, detailed reservoir characterization plays a fundamental role in completion design, affecting the staging strategy, location of perforations or fracture ports, and stimulation design. Properly modeling the interaction of induced fractures with the rock fabric and coupling the hydraulic fracture geometry and conductivity with subsequent well performance is an essential element in this comprehensive workflow. The unconventional reservoir simulations include a detailed geologic description. The modeling is focused on the well and the specifics of the completion (i.e., the hydraulic fracture treatments). In contrast, this information can be significantly scaled up for conventional reservoirs, shifting the focus to large-scale reservoir behavior (i.e., multiwell and full-field simulation models).
Reelwell Drilling Method Makes Use of Dual-Conduit Drillstring
Authors: JPT staff _
Published: February 2015

Young Technology Showcase

The Reelwell drilling method (RDM) is a drilling solution using a unique flow arrangement. RDM employs drillpipe where an inner string is installed to form a dual-conduit drillstring. This allows the fluid and cuttings from the bottom of the well to return to the surface through the inside of the drillstring. RDM enables improved hole cleaning, reduced possibility for washouts, and improved downhole pressure control. RDM has unique features for managed-pressure drilling (MPD) and extended-reach drilling (ERD). A special feature of RDM is that it allows MPD and underbalanced operations (UBO) to be performed with a heavy fluid in the well annulus by means of the Reel-well multigradient system. This implies that MPD and UBO can be performed with two well barriers and, thus, improved safety.

RDM started its development in 2004 and has been through several full-scale tests. In 2009, the system was used for the first time for directional drilling with MPD in a land well in Norway. In 2010, RDM was used for the first time in a live shale gas well in Canada. These operations have validated RDM and its features and are important steps proving its potential.

Arrangements and Rig Description

Fig. 1 presents a schematic of the system. The system is based on a dual-channel drillstring, where one flow path is used to convey the drilling fluid into the well down to the bit and the other channel is used for the return fluid from the bottom of the well. This arrangement implies a modification of the drilling fluid flow arrangement.

The following special tools and arrangements are used.

Dual Drillstring (DDS). The DDS can be manufactured in various sizes; the current size used consists of 6⅝-in. drillpipe adapted with 3.5-in. inner pipe that has been fitted with stab-in innerstring connectors. The DDS is handled on the rig floor as conventional drillpipe.

Topdrive Adapter (TDA). A dual-conduit swivel connects the rig’s topdrive unit to the dual drillstring and enables rotation of the drillstring by the top drive. The TDA is connected to the surface flow control unit through an additional separate stand pipe and mud hose.

Flow Control Unit (FCU). The FCU is a control valve arrangement equipped with pressure and flow sensors and permits accurate control of the in/out flow in the RDM system. The control unit connects to all the flow paths of the system, as shown in Fig. 1.

Dual-Float Valve (DFV). The DFV is a device located at the bottom of the DDS. The DFV includes a flow cross-over from the well annulus into the return channel of the DDS. The DFV incorporates valves that isolate the drillstring from the well during connections. In the fail-safe default position, the DFV closes both channels of the DDS. A conventional BHA is made up below the DFV.
Production Method for Methane Hydrate Sees Scientific Success
Authors: Parshall Joel
Published: February 2015

The testing flare burns brightly during a methane hydrate production test of the Ignik Sikumi No. 1 well on the Alaskan North Slope.

A production method that could unlock large reserves of methane hydrate in sand-dominated reservoirs was tested successfully from a scientific and operational standpoint in a recent research experiment on the Alaskan North Slope (ANS). The experiment was conducted by the National Energy Technology Laboratory (NETL) of the United States Department of Energy (DOE) in partnership with ConocoPhillips and Japan Oil, Gas, and Metals National Corporation.

A proof-of-concept test was conducted between 15 February and 10 April at the Ignik Sikumi No. 1 well in the Prudhoe Bay field operated by ConocoPhillips. The production technique featured the injection of carbon dioxide (CO2) to exchange and release methane (CH4) from the hydrate, a method developed through laboratory collaboration between the University of Bergen in Norway and ConocoPhillips. The released gas was then produced by means of reservoir depressurization.

“The test objective was to perform injection and flow-back from a single well to validate that the CO2/CH4 exchange mechanism demonstrated in laboratory tests will occur in a reservoir of natural methane hydrates,” said Ray Boswell, technology manager for gas hydrates at the NETL. It was the first field-level trial of a production method involving the exchange of CO2 with the methane molecules contained in a methane hydrate structure. “The focus of the test, including the design of the well, was on the technical feasibility of this new technology, rather than an attempt to produce gas at commercial rates,” Boswell said.

CO2 Mixture Injected in Reservoir

The Ignik Sikumi well test was equipped with downhole fiber-optic distributed temperature and acoustic sensing, three downhole pressure gauges, and full surface instrumentation, including high-resolution in-line gas chromatography. Over a 13-day period, a carbon dioxide/nitrogen mixture was successfully injected into the 30-ft-thick reservoir interval, saturated with methane hydrate, without loss of injectivity. This was followed by a production stage in which the pressure was held above the stability pressure of the in-situ methane hydrate. CH4 was produced during this stage, and initial data analyses indicated that CO2 exchange was achieved. Ongoing analyses of the extensive datasets acquired at the field site are under way to determine the overall efficiency of simultaneous CO2 storage/CH4 production from the reservoir.

As part of the demonstration, the depressurization phase of the test extended for 30 days. The longest previous field test of depressurization to extract gas from hydrate lasted 6 days as part of a Japanese-Canadian testing program at the Mallik well in Canada’s Northwest Territories during 2007 to 2008.
Technology Focus: Formation Evaluation (August 2012)
Authors: Harrison Bob
Published: February 2015

Technology Focus

A little bit of knowledge is not always a dangerous thing.

Recently, I was reviewing some simulation models with a client’s subsurface team. They were taken aback when I asked them if they were happy with the petro-physical inputs they had been provided with. “It’s not our job to question the petrophysics,” they replied in unison. However, it was obvious that they were struggling to get the simulation model to match the observed reservoir performance and could do so only by dramatically changing the input rock properties. It transpired that their employer had recently bought the asset and the team had inherited the previous operator’s interpretations, which, “to save time,” had simply been imported into their model.

After much cajoling, the team agreed to review the raw core and log data and opened a Pandora’s box. The older wells had poor borehole quality with large washouts, usually in shaly zones, that adversely affected the logs so that they indicated porosity in shales. The net-pay count was, therefore, optimistic. Closer inspection of the permeability/porosity transform revealed that the core data had not been corrected for the Klinkenberg effect or for compaction or even checked against test values. Finally, the computed Corey coefficients for the relative permeability curves looked very low for the oil-wet carbonate they were supposed to characterize, which was because of unstable flooding of the core plugs in the laboratory.

With these revelations in mind, the team members decided that the petrophysics for the field had to be reinterpreted, and they collaborated closely with their company petrophysicist during the review. A new simulation model was built that was more coherent, more consistent, and more realistic and that gave much better results than before.

There is no harm in developing a petrophysical side to one’s discipline. As I mentioned in my Focus column in August 2009, petrophysics touches all the subsurface disciplines in one way or another. Being able to converse intelligently with log analysts and ask them pertinent questions can only be good news for employers and subsurface project managers. It can also save time that may have been wasted creating simulation models that do not reflect reality.

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

SPE 153537 A Study of Differences in Array-Induction and Multi-Laterolog Responses in a Well Drilled With High-Salinity Water-Based Mud by Bill Corley, Baker Hughes, et al.

SPE 153593 A New Method for Estimating Waterflood Oil-Recovery Efficiency Using Post-Waterflood NMR and Dielectric Well Logs, Belridge Field, California by Daniel A. Reed, Aera Energy, et al.

SPE 154426 Reducing Reservoir Uncertainties Using Advanced Wireline Formation Testing by D. Loi, Eni, et al.
Assessment of European Shale-Gas Play Takes Social Acceptance Into Account
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 152339, ’Assessment of an Unusual European Shale-Gas Play: The Cambro- Ordovician Alum Shale, Southern Sweden,’ by Wilfred Pool, Mark Geluk, Janneke Abels, and Graham Tiley, Shell International E&P, and Erdem Idiz and Elise Leenaarts, Shell Global Solutions International, prepared for the 2012 SPE/EAGE European Unconventional Resources Conference and Exhibition, Vienna, Austria, 20-22 March. The paper has not been peer reviewed.

In 2008, Shell obtained two licenses for unconventional gas exploration in the Skåne region of southern Sweden, with a total size of 2500 km2. The objective was the Cambro-Ordovician alum shale, one of the thickest and richest marine source rocks in onshore northern Europe. Concerns from the residents of Skåne regarding the visual impact of activities and potential impact of drilling activities on the aquifers and on the tourism industry have resulted in extensive engagements with stakeholders and specific requirements around seismic acquisition, site preparation, and operations.

Introduction

In 2006 and 2007, a screening study for potential unconventional basins was undertaken in Shell. The focus for this screening was to identify basins with excellent source rocks because unconventional gas systems require excellent, gas-prone source rocks in the right maturity window. Several source-rock systems were screened, one of which was the Lower Paleozoic system on the east European platform. This system has a considerable regional extent, stretching more than 1500 km from Denmark in the northwest to the Moesian platform in Romania and Bulgaria in the southeast.

The derisking strategy for this opportunity was based on both technical and nontechnical aspects. The aim was to collect geological and geophysical data to constrain depth and thickness of the shale and to identify potential dolerite dykes. In addition, well data were needed to establish rock properties and gas content.

Sweden does not have much exposure to hydrocarbon-related activities, and the application for the two licenses in Skåne resulted in nationwide press attention, especially when it was realized that these were so-called unconventional hydrocarbons. People in the Skåne region were concerned about the impact of the exploration activities in these licenses. The mindset in Shell from the start was to perform the exploration (and, in case of success, the appraisal and production activities) in a sustainable way with minimal impact to ensure social acceptance.
Value of Dispersants for Offshore-Oil-Spill Response
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 23359, ’The Value of Dispersants for Offshore-Oil-Spill Response,’ by Tim Nedwed, Tom Coolbaugh, and Greg Demarco, ExxonMobil, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.

Each oil-spill-response option must be evaluated for operational limitations (e.g., sea state), potential effectiveness, environmental effects of the response option, applicability under various oil-spill scenarios (e.g., size and location of the spill), and health and safety of the responders. Alternative response tools are available to assist mechanical recovery in treating large offshore oil spills more effectively. There are misperceptions and misunderstandings about dispersants and their use; therefore, a description of dispersant use during the Deepwater Horizon incident is presented.

Introduction

The primary goal of any oil-spill response should be to minimize environmental harm. Although one expectation may be complete physical containment and removal of oil from the environment, this often is not possible (especially with large offshore spills) because of physical limitations of mechanical-recovery systems. Recovery operations during previous offshore spills collected only a small fraction of the spilled oil, even under ideal conditions. The Deepwater Horizon incident was no exception, with estimates indicating that only 3% of the oil was recovered mechanically.

Recognizing significant limitations of mechanical recovery has led to developing alternative response tools—one of which is oil-spill dispersants. Oil-spill dispersants facilitate removal of oil from the environment by enhancing the natural biodegradation process. Dispersants break up a surface slick rapidly into micron-sized droplets that move into the water column. This action provides naturally occurring oil-degrading bacteria greater access to the oil by creating a dilute mixture of oil in water rather than a thick surface accumulation. Fortunately, oil-degrading bacteria exist in all marine environments, having evolved to degrade oil released by natural seeps. Dispersed oil dilutes rapidly, and concentrations above known toxicity thresholds persist for no more than a few hours after effective dispersant application.

During the Deepwater Horizon incident, the amount of damage to the shorelines was far less than expected initially by the public. In many locations where oil did enter, marsh-grass recovery was apparent soon after the spill. This, and other evidence, suggests that a key reason for the limited shoreline effects during the incident was use of dispersants and, in particular, the subsea injection of dispersants at the wellhead.

Oil Behavior During High-Flow Subsea Release

The lower the viscosity of the oil, the higher the flow rate, and vice versa. Also, the ability to disperse oil is inversely related to the fluid’s viscosity, and oils remain readily dispersible with viscosities up to several thousand centipoises.