bluuebunny/crossref_metadata_2025 huggingface dataset:
Thermal/Stress-Loading Analysis for Tubulars in HP/HT Wells
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24852, ’Importance of Thermal/Stress-Loading Analysis for Tubulars in HP/HT Wells,’ by Norman Shahreyar, SPE, and Douglas Finley, SPE, Halliburton, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25-28 March. The paper has not been peer reviewed.

This paper provides an overview of an engineering-design methodology that can be followed for tubular-equipment sizing and selection for use in complex wells. A typical list of reservoir and well parameters required to set up the well model for thermal and stress-loading analysis is presented. Furthermore, a full well-casing and tubing-design-integrity analysis is performed on a complex, high-rate, high-pressure/high-temperature (HP/HT) example well with various anticipated operating loads.

Introduction

The purpose of tubular-design analysis and validation is to analyze tubing loads, design integrity, and buckling behavior under complex mechanical- and thermal- loading conditions, as well as fluid pressure effects. It is very important to perform thermal and pressure analysis for a well and then to use estimated temperature and pressure profiles in a tubular- stress analysis in well-completion designs. This is true for any well completion and is especially important in HP/HT wells, deepwater wells, and subsea wells (with emphasis on recognition of annulus fluid expansion). Thermal and stress analysis helps to estimate whether the proposed or existing completion for the well is fit for purpose when subjected to varying well-operating conditions during the life of the well. Therefore, for a proper completion design, it is critical that this analysis be performed while the completion is still in the planning stage.
Technology Focus: EOR Operations (June 2014)
Authors: Bonet-Cunha Luciane
Published: February 2015

Technology Focus

Enhanced-oil-recovery (EOR) methods have been increasingly positioned into the mainstream of project planning these past years as conventional, highly productive, and large reservoirs have become more difficult to find. As a result, in recent years, various innovative EOR techniques seeking to maximize total reservoir recovery have gained renewed interest and attention. However, despite the wealth of knowledge already available and heavy investments made from a number of operators, it is certain that the potential of EOR solutions has not been fully realized.

One key area that can boost EOR projects’ results and challenge the professionals involved is the pursuit of EOR operational excellence. Although it can be seen as a trivial target, it is in fact a quite complex goal. Besides experienced management, it involves a well-prepared multidisciplinary team in the planning phase, definition, controlling of the contracts, and the safe and precise execution and monitoring of the operation. Integration is key to the implementation of efficient and safe operations with minimization of operational costs. Like a winning World Cup football team, victory will depend as much on a good coach as on well-prepared and integrated players. They have different roles to play during the game, but they all target the same goal.
Continuous Seismic Reservoir Monitoring of Thermal Enhanced Oil Recovery
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165428, ’Continuous Land Seismic Reservoir Monitoring of Thermal EOR in the Netherlands,’ by Julien Cotton, Laurene Michou, and Eric Forgues, CGG, and Kees Hornman, Shell Global Solutions International, prepared for the 2013 SPE Heavy Oil Conference Canada, Calgary, 11-13 June. The paper has not been peer reviewed.

A reservoir-monitoring system has been installed on a medium-heavy-oil onshore field in the context of redevelopment by gravity-assisted steamflood. The challenge was to monitor the lateral and vertical expansion of the steam chest continuously with seismic reflection. The high sensitivity of the buried acquisition system allows the tracking and monitoring of very small variations of the reservoir’s physical properties in both the spatial and calendar domains. A daily 4D “movie” of the changes allows proposing a scenario that explains the unexpected behavior of the production.

Introduction

The Schoonebeek field is in the northeast of the Netherlands with 1 billion bbl of stock-tank oil initially in place. Between 1948 and 1996, the oil was produced with several small-scale thermal enhanced-oil-recovery pilots with vertical wells. Today, the oil is produced by gravity-assisted steamdrive. A permanent seismic system including 2D and 3D phases was installed in 2010 to monitor the reservoir’s evolution during steam injection. The monitoring lasted 2 years. During this time, the propagation of the steam plume injected into a horizontal well located between two horizontal producer wells was tracked in order to understand the 4D behavior of the steam and possibly update the dynamic production model.
Analyzing, Optimizing Frac Treatments By Means of a Numerical Simulator
Authors: Soliman M.Y. , Grieser W.
Published: February 2015

Technology Update

Hydraulic fracturing and refracturing has become an integral part of completing wells, especially in unconventional reservoirs such as tight gas formations, shale, coalbed methane, and tight oil reservoirs. Practicing reservoir and production engineers now require access to a well-completion simulator. This completion simulator should have the ability to simulate productivity of complex reservoirs and wells, not only to design an optimum fracturing treatment but also to analyze production results. For a practicing engineer, the prediction of productivity of fractured wells requires a balance between accurate representation of the physical process of reservoir fluid flow and the time required to simulate that process. Because unconventional reservoirs and associated wells can be complex, analytical solutions are usually not capable of providing an adequate prediction of the well performance. The need for a comprehensive, yet easily accessible, numerical simulator for well-completion processes has become a necessity.

The basic philosophy behind such a simulator is that it would

Emphasize prediction of a small number of wells, including the capability of predicting single-well production and performing related analysis.

Provide higher speed in both simulation and turnaround rate. This goal can be achieved through the use of a graphical user interface. Some of the more complex features may be accessible to more sophisticated users by means of special file handling to enhance analysis capability.

Automate the simulation of specialized features that may be crucial to stimulation. These features include the following:

Consideration of the fracturing-fluid filtrate as a separate aqueous fluid

Linkage to a commercially available proppant library

Ability to import fracture geometry and properties, including proppant concentration and type, fracture width, and amount of fluid leakoff into the formation for each fracture grid from commercially available fracture-design simulators—specifically, the 3D design programs StimPlan (NSI Technologies) and GOHFER (Barree and Associates)
Statoil: A Journey Across Energy Frontiers
Authors: Sheehan John
Published: February 2015

Editor’s note: This is the first in a series of profiles of leading operators, including key international and national oil companies, around the globe. The focus is on the company’s strategic direction, relationship to its government, major upstream activity, and significant technology challenges and applications.

As the Norwegian Continental Shelf (NCS) matures, Statoil is trying to earn maximum value from its home patch, while at the same time repositioning itself for future growth internationally.

Originally formed in 1972, Statoil merged with rival Hydro in 2007 to create StatoilHydro, before the Statoil name was reclaimed last year when the company was rebranded. The new Statoil adopted a star-shaped logo, inspired by the starry skies of the north, to symbolize its aspiration to be a “pathfinder” in oil, gas, and other energy forms.

The merger of the two Norwegian energy giants strengthened the new company organizationally, technologically, and financially, says company Chief Executive Officer Helge Lund.

“We are a larger company, more competitive in an international context. Since the merger we have been able to attack more business opportunities in more countries,” he said. “Entering the Shtokman partnership in Russia, taking over as operator of Peregrino in Brazil, acquiring a substantial shale-gas position in the US, and delivering a winning bid in Iraq are some of the business opportunities we have captured since the merger.”

Statoil is the largest operator on the NCS, with approximately 60% of its total production. It also operates oil and gas fields in Algeria, Angola, Azerbaijan, Brazil, Canada, China, Iran, Libya, Nigeria, Russia, the United States, and Venezuela.

In the long term, as well as garnering maximum potential from the NCS, Statoil is looking to its international asset base to allow it to grow and become more diversified, both in geographical terms and in types of production.

The company also has ambitions to develop profitable midstream and downstream positions as well as a strong renewable base, particularly in wind power. In offshore wind, Statoil is in a partnership to develop the Sheringham Shoal project in the UK, with 88 turbines coming on stream in 2011. The Forewind consortium, in which Statoil participates, was awarded the largest development area in the UK’s third licensing round for offshore wind farms. Meanwhile, off the western coast of Norway, Statoil is testing a prototype of the world’s first full-scale floating wind turbine, Hywind, designed for operation in deeper waters.

Upstream Priorities

Traditionally, Statoil’s focus has been on its upstream activities and the company has identified four priority growth areas moving forward: deep water, gas-value chains, harsh environments, and heavy oil.
Technology Focus: Reservoir Simulation (July 2010)
Authors: Crick Martin
Published: February 2015

Technology Focus

At the 2009 SPE Annual Technical Conference and Exhibition held in New Orleans, I discovered at the Editorial Committee meeting that this Reservoir Simulation feature led the league table in terms of numbers of papers to review. This is a great indicator of the dynamism and innovation going on in our discipline, even if it did also make a pretty daunting task for your reviewer! We, therefore, agreed to spin off a separate feature on History Matching, which appeared in the April issue of JPT: Go back and check it out if you missed it. Despite this, I still had a large number of papers to choose from.

Developments in our discipline cover a wide frontier, ranging from the physics of shale-gas reservoirs, to many approaches for improving computational efficiency, through workflow approaches for keeping models up to date and consistent. The underlying aims can be summed up best on the one hand as the relentless pursuit of more-predictive models through better physics and accuracy of reservoir description, and on the other hand as trying to achieve this aim ever more efficiently in terms of engineering and computational resources.

As I mentioned last year, optimization continues to be a major topic, not just in history matching but also in prediction workflows. This is hardly surprising: Making optimal reservoir-management decisions is the main reason for doing reservoir simulation. Applying automation to the task can reduce the drudgery involved in trying many scenarios manually. Some operators are working toward a vision of integrating simulation models into systems that make operational decisions automatically or semiautomatically. Other operators prefer to gain general insight from more-general representative models and then make their decisions relying on engineering judgment.

Whichever approach you take, the pressure to make every well pay in the current downturn means that there is renewed interest in many companies in applying higher levels of engineering and science. The challenge to us as reservoir engineers is to ensure that increased sophistication of engineering remains relevant and contributes to better field-management decisions.

Reservoir Simulation additional reading available at OnePetro: www.onepetro.org

SPE 127853 • “Uncertainty Evaluation in Emerging Gas Projects in North Africa Using Geological Modeling, Reservoir Simulation, and Experimental Design” by M. Vicente, Repsol YPF, et al.

SPE 125568 • “Ensuring Water-Saturation Consistency Between Static (Fine-Grid) and Dynamic (Upscaled) Models—A Case Study of the North Kuwait Jurassic Complex” by Kassem Ghorayeb, Schlumberger, et al.

SPE 125559 • “Upscaling in Partially Fractured Oil Reservoirs Using Homogenization” by Hamidreza Salimi, SPE, Delft University of Technology, et al.
Modeling CO2 Storage in Aquifers: Assessing Key Contributors to Uncertainty
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 123582, ’Modeling CO2 Storage in Aquifers: Assessing the Key Contributors to Uncertainty,’ by W. Sifuentes, SPE, Schlumberger; M.J. Blunt, SPE, Imperial College; and M.A. Giddins, SPE, Schlumberger, prepared for the 2009 SPE Offshore Europe Oil and Gas Conference & Exhibition, Aberdeen, 8-11 September. The paper has not been peer reviewed.

The influence of different physical properties on the effectiveness of CO2 storage in aquifers was studied. A numerical sensitivity analysis based on experimental design was used to quantify and compare the contribution of the most important parameters to the trapping of CO2. The work focused on the effects of dissolution and residual trapping. Reservoir simulations with properties and geometries representative of the Stuttgart formation in Ketzin, Germany, demonstrated how different trapping mechanisms are influenced by gravity segregation, fingering, and channeling.  

Introduction

This focus was on CO2 storage in aquifers because this storage option is emerging with great potential, having a high estimated capacity to store CO2 in geological formations (estimates range from 400 to 1000 Gt of CO2). Several CO2-storage projects are under way or planned (pilot, research, commercial projects), and many of the commercial projects are related to major gas-production facilities, at which gas-production streams contain high levels of CO2 (e.g., Sleipner in Norway, In Salah in Algeria, and Gorgon in Australia). The first commercial project related to CO2 storage in aquifers was the Sleipner project in Norway, where approximately 1 Mt/a of CO2 captured from the gas-production stream has been injected since 1996 in the Utsira saline formation.

The efficiency of long-term storage in aquifers is related directly to the efficiency of each of the trapping mechanisms involved. In the context of CO2 storage, particularly in aquifers, there are four major trapping mechanisms.

Hydrodynamic (structural or stratigraphic) trapping—caprock prevents mobile CO2 from flowing back to the surface.

Residual or capillary trapping—capillary forces and relative permeability effects contribute to converting the CO2 injected into an immobile phase.

Solubility trapping—CO2 dissolves in the aqueous phase.

Mineral trapping—chemical reactions between CO2 and rock minerals form a solid carbonate.

During the injection phase, structural or stratigraphic trapping is the main contributor preventing CO2 from escaping to the surface. Mineral trapping is the safest long-term way to trap CO2 because it transforms CO2 into an immobile solid. However, this process can be very slow. The focus here was on capillary and dissolution trapping, which are likely to be effective on an intermediate time scale.
Europe Gears Up for the Shale Gale
Authors: Sheehan John
Published: February 2015

The European shale gas revolution is still in its infancy and though its commercial potential could rival that of North America, significant challenges lie ahead. France has put a moratorium on shale gas activity while a comprehensive study into its environmental impact is being carried out, and its National Assembly has voted in favor of a ban on hydraulic fracturing.

The potential for shale gas production in Europe is undoubted, as consultancy IHS CERA estimates that Europe’s total shale gas in place could be 6,115 Tcf. Among the key challenges that will determine the ultimate productivity in Europe is a regulatory environment that is currently ill-suited to unconventional gas, the company said. “Regulations designed for traditional exploration and production in Amsterdam. “We expect Europe to be a significant part of future activity.”

Poland Leads the Way

Poland plays host to Europe’s largest known reserves of shale gas. Leasing activity in the country’s three main basins—the Baltic Basin, the Podlasie Basin in the east, and the Lublin Basin to the south—is well under way. The country is keen to push forward with shale gas production as it looks to break away from its reliance on Russian gas supplies.

The US Energy Information Administration (EIA) estimates that Poland has 792 Tcf of risked shale gas in place, with 514 Tcf in the Baltic Basin, 222 Tcf in the Lublin Basin, and the remainder in the Podlasie Basin. Chevron and ExxonMobil have been joined by a large number of smaller players such as DPV Service, Cuadrilla, EUR Energy, and Mazovia Energy in securing acreage across the country.

Talisman is carrying out seismic acquisition on con-cessions in the Baltic Basin and it is on track to spud its first two shale gas wells in the fourth quarter of this year, the company said. It moved into the Polish plays through a farm-in arrangement with San Leon Energy for a 60% interest in San Leon’s three concessions. Talisman is committed to drilling a minimum of three wells—Gdansk-W, Braniewo-S, and Szczawno—which cover 600,000 acres. Three optional wells with horizontal sections will be drilled after a successful first phase of testing. San Leon is also engaged in a five-year exploration and development program on its two concessions, Nowa Sol and Wschowa in the Permian Basin South. Both concessions are on trend with prolific Rotliegendes gas and Zechstein oil production.

Nexen recently entered into an agreement with Marathon to jointly explore 10 concessions in Poland’s Paleozoic shale play and it says it will pump USD 100 million into shale-related activities. Nexen will acquire a 40% working interest in the concessions, which encompass more than 2 million acres. Marathon is acquiring 2D seismic this year and plans to drill one or two wells in the fourth quarter and potentially seven or eight wells during 2012.
Shale Gas: Promising Prospects Worldwide
Authors: Beckwith Robin
Published: February 2015

Shale gas is everywhere. China's estimated technically recoverable shale gas resources, at 1,275 Tcf, are almost 50% greater than those touted in the US. Argentina, with 774 Tcf, contains 150 Tcf more than all of Europe. These numbers were spelled out in “World Shale Gas Resources: An Initial Assessment,” a study released April 2011 under the auspices of the US Energy Information Administration (EIA), which commissioned the study from Advanced Resources International (ARl).

China, in fact, ranks first in shale gas resources, followed by the US, Argentina, Europe, Mexico, South Africa, Australia, and Canada. Although the study is preliminary and excludes areas like Russia and the Middle East, there is no doubt shale gas resources exist in abundance worldwide. The numbers ARl arrived at are rough. With more extensive data and more time to assess it, ARl stated, the amounts would be higher.

However, Donald L. Gautier, chief of the US Geological Survey (USGS) World Petroleum Project, introduced a note of caution regarding the EIA study's figures. The USGS is in the midst of its own assessment of global continuous accumulations, including technically recoverable gas from source rock systems such as gas shales. Initial results from the first basins assessed will be released within the next few months. According to Gautier, the USGS approach, which is geologically based, probabilistic, and emphasizes application of well performance data from analog shale plays in North America, is quite different from that of ARI. “I wouldn’t be at all surprised if the results are as different as the methodology,” he said.

Shale Gas Economic Requisites

While shale yields approximately 20% (4.8 Tcf in 2010, according to the EIA) of US natural gas consumption, this resource has yet to contribute more than negligibly in regions elsewhere. Yet many countries, buoyed by and in some cases participating in US shale gas exploitation, appear poised to initiate shale gas development within their borders. However, with a lack of shale drilling and completion services, as well as gas production and transportation infrastructure, promising shale gas reservoirs need at least five to 10 years before production would be economic.
Three Steps to a Risked Revenue Forecast
Authors: Schulz Rodney , McCormack Don
Published: February 2015

Management

For many reasons, different assets have different levels of risk/uncertainty associated with a decline curve forecast. Failing to quantify these differences in uncertainty is the equivalent of disregarding a significant piece of the business equation because one must include risk and uncertainty when forecasting production.

Similarly, failing to quantify the risk associated with a product price forecast—or arbitrarily assuming “high,” “medium,” and “low” cases—is also ignoring a piece of the equation that is not only scientifically/statistically possible to assess, but also quick and easy to calculate. Moreover, to understand and plan for the business situation based on decline curve forecasts, one needs to combine the uncertainties of both the decline curve forecast and the product price forecast.

Using low-cost personal computer software, one can quantify the uncertainty spread surrounding the situation to determine the risk associated with a revenue forecast. Because decline curves represent physical systems from the reservoir through the sales meter or stock tank, different decline curves have differing amounts of volatility. Hence, assuming the physical system around the asset does not change, one can systematically quantify the differing degrees of certainty in the forecast (Figs. 1a and 1b).

Having quantified the uncertainty associated with the production forecast (Step 1), the professional or manager then turns to the uncertainty associated with product prices (Step 2). Previous analysis and research indicate that oil and natural gas markets are “efficient,” i.e., prices reflect all available public information almost instantaneously and price movements follow a “random walk” model (Figs. 2a and 2b). The random walk premise also suggests that the best forecast of tomorrow’s price is today’s price. Therefore, using a given starting price, one can easily quantify the product price uncertainty going forward.

Price volatility ebbs and flows over time. However, looking at historical price volatility will give one a reasonable estimate of the future volatility that one’s organization should be prepared to accommodate. Hence, rather than assuming a price and basing the business model on it, one can proceed with a known price—today’s price—and proceed with a price volatility estimate that is reasonable and scientifically/statistically derived.

Having quantified the uncertainty associated with the production (Step 1) and with product prices (Step 2), it is a matter of using statistical analysis to quantify the uncertainty associated with forecasting revenue (Step 3), which is the product of the two. Doing this will yield a revenue forecast that may be alarming when one sees the uncertainty.
Experimental Investigation of Two-Phase-Flow Patterns and Hydraulic Performance of Electrical Submersible Pumps
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper CSUG/SPE 134089, ’Experimental Investigation on the Viscous Effect on Two-Phase Flow Patterns and Hydraulic Performance of Electrical Submersible Pumps,’ by F.E. Trevisan, SPE, and M.G. Prado, SPE, University of Tulsa, originally prepared for the 2010 Canadian Unconventional Resources & International Petroleum Conference, Calgary, 19-21 October. See Journal of Canadian Petroleum Technology, April 2011, page 45.

Using a visualization prototype built from original electrical-submersible-pump (ESP) components and with minimal geometrical modifications, an experimental procedure was developed and conducted to address the viscous effect on liquid/gas two-phase flow through ESPs. On the basis of dimensionless groups that govern centrifugal-pump single-phase performance, two-phase experiments were conducted at different shaft speeds, nonslip void fractions, and viscosity values while liquid rates were kept constant at 60% of the maximum rate at the defined shaft speed.

Introduction

An ESP is one of the many existing artificial-lift techniques used in the petroleum industry. It consists of a series of small-diameter diffuser-type casing centrifugal pumps, mainly known for their capacity for handling high volumes. Their applications vary from producing high-productivity oil wells onshore and offshore to dewatering coalbed-methane and gas wells.

The use of ESPs in liquid single-phase applications is well understood. However, the presence of a compressible phase, such as natural gas, will modify the hydraulic performance of this type of pump. The presence of a second phase often will degrade the ability of the pump to deliver pressure, and depending on the amount of gas flowing through the system, instabilities may occur. These, also referred to as surging, eventually lead to extremely low pressure generation, also known as gas lock.

Experimental Description

An ESP visualization prototype was designed, built, and installed in a closed-circuit loop. Fig. 1 in the full-length paper provides a graphical representation of the experimental facility. This closed circuit consisted of a 65-gal tank to store the liquid, from which the fluid passed through a booster pump and a liquid-measuring unit before flowing to the ESP prototype. Air was provided by a 1-hp compressor delivering pressures up to 10 psig and flow rates up to 10 scf/hr. Gas was injected at the liquid line close to the prototype intake and measured by rotameters. After passing through the ESP prototype, the fluids returned to the liquid storage tank that also acted as an open-air separator. Both ESP and booster-pump motors were controlled by individual variable-speed drives linked to the acquisition system. This system also received information the differential-pressure and temperature transducers.
CO2 EOR: Nanotechnology for Mobility Control Studied
Authors: Jikich Sinisha (Jay)
Published: February 2015

Technology Update

Most domestic conventional oil resources have been produced using primary and secondary recovery techniques, with an average recovery factor estimated at 35%. Additional recovery is possible by using innovative enhanced oil recovery (EOR) techniques. One of these, carbon dioxide (CO2) miscible flooding, is the fastest growing EOR technique in the United States because of the many reservoirs amenable to the process. Current production is almost 310,000 B/D (EOR Survey, Oil and Gas Journal, April 2012), representing approximately 5% of total US oil output.

A revised national resource assessment for CO2 EOR conducted by the National Energy Technology Laboratory (NETL) of the United States Department of Energy (DOE) in 2011 indicated that “next generation” CO2 EOR can provide 137 billion bbl of additional, technically recoverable domestic oil, with about half (67 billion bbl) economically recoverable at an oil price of USD 85 per bbl. CO2 EOR has the benefit of sequestering CO2 in oil producing formations and is seen as a critical component of future greenhouse gas management programs. This facet of CO2 EOR produces valuable synergies with the carbon capture, utilization, and storage research program with the DOE’s Office of Fossil Energy.

The CO2 EOR process is limited by technology, cost, and the geographic availability of CO2. Technology improvements are needed to increase the displacement efficiency of the process. Not only would advances in displacement efficiency increase oil recovery, it would also lead to the sequestration of additional CO2 volumes.

Background

The Office of Fossil Energy has historically supported a large number of laboratory and field tests in an effort to improve oil recovery processes. A majority of the projects were related to advanced reservoir characterization, mobility control, and conformance of CO2 flooding. In September 2010, the NETL awarded a number of new research projects to further development of the next generation of CO2 EOR, encouraging applicants to pursue small field or pilot testing. Two of the awarded research projects are related to mobility control in CO2 flooding using nanoparticle technologies.

The University of Texas at Austin (UT) is evaluating inexpensive alternative nanoparticles (microscopic particles with at least one dimension less than 100 nm) to provide the large volumes needed for foam stabilization in field-scale CO2 floods. The study entails using low-cost, commercially available “bare” nanoparticles (e.g., silica, fly ash, and iron oxide) and applying a polyethylene glycol (PEG) or other in-house coating to produce low-cost alternatives to develop CO2 foam.
China's Shale Gas Potential Looks Bright, But Development Raises Questions
Authors: Rassenfoss Stephen
Published: February 2015

Shell is evaluating shale gas prospects in the Sichuan basin in hopes of replicating its success in the Changbei field, a tight gas project with PetroChina, that required advanced exploration and production technology.

China ranks first in the world in shale gas in the ground, based on just two massive basins. But the estimate in a report from the US Energy Information Administration (EIA) is based on what is technically possible, not when, or if, anyone will produce that gas.

“The time dimensions are up to infinity. It is a technically recoverable number without a time constraint,” said Vello Kuuskraa, the president of Advanced Resources International, which conducted the World Shale Gas Resources study for the EIA, part of the US Department of Energy.

China’s plan to aggressively tilt its coal- and oil-based economy toward natural gas by exploiting its shale resources is on the scale of what the US did to shift from a shortage to a glut of gas. But some question whether China will be able to reach its goal of leaping from virtually no shale gas production now to 60 billion–100 billion m3/a by 2020, equal to 6–10 Bcf/D.

The exploration business there is worlds different than the US model that allowed independent gas companies to quickly lease and explore large blocks of land with the support of service companies providing advanced drilling and fracturing services.

In China, international companies must partner with government-controlled Chinese ones that control the prospects, and multiple layers of government permission are needed to get things done.

High population density and tight water supplies are an issue in one of those basins, the Sichuan. In the other, the Tarim, there are few people to consider, but it is a remote region far from markets.

On the plus side, the EIA study estimated that the Sichuan and Tarim basins hold 1,275 Tcf of technically recoverable gas, assuming that about 25% of the gas in the ground can be produced. “These are two massive world-class basins with multiple formations,” offering stacked layers of shale gas, Kuuskraa said. They are in a country with a voracious appetite for energy and a plan to increase its reliance on gas, which represents only 4% of Chinese energy consumption.
Why Asset Integrity Implementation Often Fails
Authors: Ciaraldi Stephen W.
Published: February 2015

Management

Compare the approaches of the top 10 operating companies around the world to tackling the asset integrity challenge and you will find many similarities. Whether in the models used to identify risks or the approaches used to manage them, the industry thinking has evolved to a point at which most agree on the fundamental elements of how to approach integrity management.

Look closer and you might find some more commonalities. The reasons asset integrity management strategies often fail to achieve the expected results are also often the same from operator to operator.

So what are these reasons, and how can you ensure you are building them into your implementation strategy to ensure that you do not repeat them? There are 10 reasons why integrity management implementations often fail.

Trying to tackle integrity in isolation.

Perhaps the most common reason asset integrity strategies fail is integrity specialists trying to achieve integrity in isolation. Integrity is not a subject that thrives in a silo—it requires the entire business to be aware, on board, and supporting of a unified effort. Staffers need to know how integrity affects their daily job, and they need to be encouraged, cajoled, instructed, and motivated to ensure that they are working together. Different groups have different goals, but not caring about others’ goals and complaining about having to do others’ work demonstrates a silo mentality. If that type of silo mentality exists, there will be problems in implementing integrity management.

Losing sight of process, people, and plant.

It may seem obvious, but an asset integrity plan is an extremely complex undertaking with many moving parts and even more stakeholders involved in its successful execution. Recognizing that there are many reasons why asset integrity implementations do not achieve the results expected of them is an important starting point. Problems are not confined to one particular area of an integrity implementation and can just as easily emerge in either the process, the people, or the plant components that make up an integrated integrity management program. Focus too narrowly on one area and you can be sure problems will emerge elsewhere. The key to implementation is the effective working together of these three components and ensuring that checks and balances exist at every stage.
Ormen Lange Hydrodynamic-Aquifer Model
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 153507, ’Predicting Water in the Crest of a Giant Gas Field: Ormen Lange Hydrodynamic-Aquifer Model,’ by M. Boya Ferrero, S. Price, SPE, and J. Hognestad, Shell, prepared for the 2012 EAGE Conference & Exhibition/SPE Europec, Copenhagen, Denmark, 4-7 June. The paper has not been peer reviewed.

Simulation showed that hydrodynamically tilted/stepping contacts depend on the rate of water flow across the aquifer, stratigraphic baffling and faulting, effective aquifer area, and reservoir quality. The role of sealing faults over geological time was downplayed in terms of justifying the fluid distribution. However, baffling during production is expected. At Ormen Lange, the hydrodynamic aquifer has pushed gas from the crest of the structure into the south of the field, leaving behind a northward-thickening prism of residual gas, which was imaged with a seismic direct hydrocarbon indicator (DHI). Confirmation of the hydrodynamic aquifer in this field was achieved after drilling an appraisal well in the north of the structure that corroborated fluids (water with residual gas) and pressures as predicted by the hydrodynamic-aquifer model.

Introduction

The Ormen Lange gas field was discovered in 1997, with first production in 2007. It is a large (8×40-km) deep-water reservoir 125 km offshore Norway at 700- to 1100-m water depth. Ormen Lange sands have excellent reservoir quality, with 26 to 30% average porosity and 500- to 1,000-md permeability. The field was developed with four subsea templates and 10 high-rate large-borehole wells.

The initial field-development plan was based on a stratigraphic trap filled to spill point, with the gas accumulation being delineated by a seismic DHI, which was postulated to indicate perched water on the edges of the structure. The field-development plan was defined on the basis of information available from only four exploration and appraisal wells. The need to understand the field’s charge history became apparent when, in 2008, an appraisal well in the northern part of the field encountered only residual-gas saturations in the crest of the structure and in the middle of a high DHI. Therefore, the DHI could not be used as a proxy for the current free-water level (FWL) because seismic cannot distinguish between mobile-gas and residual-gas saturations. Subsequently, three additional appraisal wells confirmed elevated contacts, residual gas, and gas communication across the field.
Offshore ESP-Selection Criteria: An Industry Study
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146652, ’Offshore ESP-Selection Criteria: An Industry Study,’ by Michael C. Romer, SPE, Mark E. Johnson, SPE, Pat C. Underwood, SPE, and Amanda L. Albers, SPE, ExxonMobil, and Russ M. Bacon, R.M. Bacon Engineering, prepared for the 2012 SPE Deepwater Drilling and Completions Conference, Galveston, Texas, 20-21 June. The paper has not been peer reviewed.

Most offshore wells that require artificial lift are gas lifted because gas typically is readily available and, compared with other lift systems, gas lifting is relatively inexpensive and low maintenance. However, electrical submersible pumps (ESPs) can increase oil production and reserves recovery efficiently and economically under the appropriate operating conditions. ESPs can lower the abandonment pressure and, in the long term, possibly reduce the total number of wells required to deplete an asset. Because few ESPs are installed in offshore wells, ESP-screening “rules of thumb” were formed as a simple guide to prioritize offshore ESP candidates.

Introduction

Pumps typically achieve higher drawdowns than gas lift under appropriate operating conditions. Early in the life of the pump, greater production is achieved with its higher drawdowns. Note that increased production over the long term must be supported by good reservoir management and voidage-replacement practices. Lowering the flowing bottomhole pressure can improve a well’s access to reserves in stratified reservoirs. Pumps also reduce the burden on the gas-compression system and enable selling gas or reallocating it to other gas lift wells.

ESPs have a small topside footprint, do not impair subsurface-safety-valve operation, can achieve high production rates, and can aid fluid processing on production facilities because high-pressure power fluid or gas is not required. However, it can be difficult to determine the best ESP candidates when faced with numerous opportunities, limited resources for reserves studies or artificial-lift analyses, and finite installation capital. ESPs can help maximize an asset’s profitability, and screening criteria can streamline the candidate-selection process.

These screening criteria were developed for dry-tree offshore applications. The high complexity, cost, and risk involved with subsea ESP installations and workovers typically have limited subsea pumping to seafloor technologies such as subsea separation, multiphase pumps, cartridge ESPs, and caisson ESPs. This trend may change with continued progress in alternative ESP-deployment/-retrieval technologies and/or run-life and reliability improvements.
Technology Focus: Unconventional Resources (July 2012)
Authors: Chipperfield Simon
Published: February 2015

Technology Focus

“Geology drives technology,” and “the best solutions are multidisciplinary.”

Understanding the best way to develop an unconventional reservoir requires an understanding of the rocks and a close interaction between the geosciences and engineering. Without this base understanding and creative tension, unlocking the full potential of any play will not be achieved. Some of the greatest results in my career have come when working in a cross-functional team where all members were sufficiently aware of the geology to then apply the most appropriate technology for extraction. Interaction was open, robust, and balanced, and amazing results were produced.

The most successful field developments that are being proposed today in unconventional gas use this model. For example, horizontal wells with multistaged stimulation that use image logs to identify and target existing rock fabrics highlight the close working relationship between drilling, geology, stimulation, and geomechanics.

“Geology drives technology,” and “the best solutions are multidisciplinary”—this has never been more true than when developing and appraising on the challenging unconventional frontier.

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

SPE 152596 Hydraulic Fracturing 101: What Every Representative, Environmentalist, Regulator, Reporter, Investor, University Researcher, Neighbor, and Engineer Should Know About Estimating Frac Risk and Improving Frac Performance in Unconventional Gas and Oil Wells by George E. King, Apache Corporation. (See JPT April 2012, Page 34.)

SPE 148751 An Integrated Approach for Understanding Oil and Gas Reserves Potential in Eagle Ford Shale Formation by Li Fan, Schlumberger, et al.

SPE 150830 Assessment of Unconventional Shale Reservoir: The Fegaguira Formation, Chotts Basin, Tunisia by Nawel Rezouga, ETAP, et al.
Lacq Carbon-Capture and -Sequestration Pilot
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 157157, ’The Lacq CCS Pilot, a First,’ by Jacques Monne, SPE, Total, prepared for the 2012 SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11-13 September. The paper has not been peer reviewed.

Carbon capture and sequestration (CCS) holds promise for use on an industrial scale. Total has been involved in CO2 injection and geological storage for more than 15 years, in Canada (Weyburn oil field) for enhanced oil recovery and in Norway (Sleipner and Snohvit fields) for aquifer storage. In 2006, the company decided to set up an experiment for CO2 capture, transportation, and injection in a depleted gas reservoir. The pilot is in the Lacq basin in southwestern France, 800 km from Paris, and has been on stream since January 2010.

Introduction

This CCS project entailed converting an existing air/fuel-gas combustion boiler into an oxygen/fuel-gas combustion (oxy-combustion) boiler using oxygen delivered by an air-separation unit (ASU) to obtain more-efficient combustion and a more-concentrated flue-gas-CO2 stream. The 30-MW oxy-combustion boiler can deliver up to 38 t/h of steam to the high-pressure steam network of the Lacq sour-gas-production and -treatment plant. After quenching the flue-gas stream, the rich CO2 stream is compressed to 27 barg, dried, and transported in gaseous phase by use of existing pipelines to a depleted gas field, 29 km away, where it is injected into the deep Rousse reservoir. Over a 3½-year period, up to 90 000 t of CO22 could be injected.

The main objectives in this experiment were:

To demonstrate the technical feasibility and reliability of an integrated chain comprising steam production and CO2 capture, transportation, and injection into a depleted gas reservoir.

To acquire operating experience and data to scale up the oxy-combustion technology from pilot scale (30 MW) to industrial scale (200 MW) while reducing costs.

To develop on-site monitoring methods and technologies to serve future onshore storage-monitoring programs that will be larger in scale, longer in term, and economically and technically viable (i.e., microseismic and environmental monitoring).

Technical Description

The CCS pilot installation, shown in Fig. 1, consists of an ASU, an oxy-combustion boiler, a direct-cooling contactor, a CO2 compressor, a dryer system, a transportation pipeline, and an injection site (i.e., compressor, injection well, reservoir, and a subsurface-seismic network).

ASU. A dedicated ASU, the oxygen-production unit, was installed on the Lacq gas-treatment complex to produce 240 t/d of low-pressure oxygen (1.8 bara) at 95 to 99.5 vol% purity. Only 99.5% pure oxygen is used to feed the oxy-combustion boiler. The nitrogen rejected by the ASU is partially used for regenerating the dryer system.
BOP Monitoring Seeks To Reduce Downtime, Increase Insight
Authors: Jacobs Trent
Published: February 2015

Blowout Preventer Technology

A growing trend of heavy industries in the 21st century has been to marry computers and software with large machines to track their performance, and all the hiccups along the way. Known as condition-based monitoring, the process is used to enhance the reliability and performance of railroads, wind turbines, nuclear reactors, and jet engines, but not subsea blowout preventers (BOPs). However, that is slowly starting to change.

All three major BOP makers, as well as some other companies, have introduced BOP monitoring systems that seek to provide new insight into how these massive subsea machines work—and perhaps more important, why they sometimes do not. By improving system reliability, the offshore drilling industry stands to recoup millions of dollars it writes down each year because of BOP downtime.

Today, offshore drillers have little knowledge about the fatigue life of the more than 100 hydroelectric valves and regulators inside a BOP. Makers of BOPs acknowledge that this uncertainty forces companies to replace as much as 25% of the BOP stack each time it undergoes scheduled maintenance to mitigate breakdowns. The practice of arbitrarily replacing parts is only a stopgap measure as drilling contractors report that 50% of downtime on their drilling rigs are caused by problems with BOPs. While they have their differences, the BOP monitoring systems available today seek to completely change this status quo. “The holy grail is to detect a failure early and focus your maintenance efforts on that part, and not just a random part,” said Clayton Simmons, product line manager of BOP monitoring systems at National Oilwell Varco (NOV).