bluuebunny/crossref_metadata_2025 huggingface dataset:
Post-Macondo BOP Safety Upgrades
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 22407, ’Post-Macondo BOP Safety Upgrades,’ by Benton F. Baugh, John Vozniak, SPE, and Nathan Schmidt, Radoil, prepared for the 2011 Offshore Technology Conference Brazil, Rio de Janeiro, 4-6 October. The paper has not been peer reviewed.

Before the Macondo blowout, the offshore industry had an impressive safety record, especially considering the complexity and magnitude of the work performed in relatively harsh conditions. The failures and spillages of Macondo indicated that several safety areas have not experienced appropriate progress, in large part because there had never been a major failure of a blowout-preventer (BOP) stack at that water depth. This study addressed several areas of technology that can be implemented to increase safety on new deepwater drilling-BOP systems or retrofitted on current BOP systems in the field.

Depth-Compensated Accumulators

Depth-compensated accumulators represent a major safety improvement, and they were seeing market acceptance before Macondo. The problem with accumulators on subsea stacks is that more than 100 accumulator bottles would be needed instead of approximately seven for the depth-compensated version. Additionally, the depth-compensated accumulators can be retrofitted on the ocean bottom by use of multiple frictionless controls, another major safety upgrade.

The basic concept of a depth-compensated accumulator, as shown in Fig. 1, is that a dumbbell-shaped piston has pressurized nitrogen above it in the top chamber and working fluid below it in a second chamber. The second chamber is divided from the third chamber by a central stationary bulkhead. The third chamber is maintained at environmental pressure, typically through an intermediate fluid for corrosion reasons. The fourth chamber is empty or at a vacuum. Therefore, the pressure in the third chamber is not supported from below, but rather is mechanically added to the pressure in the second chamber. At any depth, the pressure in the second working chamber exceeds environmental pressure by the amount of the nitrogen charge.

Vacuum-Enhanced Accumulator

When a shear ram moves forward, the accumulator pressure declines. There is never as much accumulator pressure available at the point of shear as was available in the accumulator when the shear command was given. In some cases, the accumulator pressure can be regulated down such that the shear-ram pistons always see the same pressure, but this simply dumps the excess pressure that may otherwise have been useful. Deepwater operations happen in a high-pressure environment. Therefore, if one is operating in 10,000 ft of seawater, the ambient pressure is 4,650 psi, and when it appears that 5,000 psi of pressure should be on one side of the piston and zero on the other, there actually is 9,650 psi on one side and 4,650 psi on the other.
Effluent Treatment in a Gas-To-Liquid Plant
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 14215, ’A Novel Approach to Effluent Treatment in Gas-To-Liquid,’ by C.G. Enyi, M. Nagib, SPE, and G.G. Nasr, Salford University, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, rescheduled to 7-9 February 2012. The paper has not been peer reviewed.

In a gas-to-liquid (GTL) plant, a large amount of reaction water is produced and various chemicals are used as intermediate treatment chemicals. The reaction water is contaminated by these chemicals. A laboratory-scale effluent-neutralization unit for pH control was designed and built to demonstrate the feasibility of the use of carbon dioxide (CO2) produced by reforming reactions in both the synthesis and the hydrogen-production units in the GTL plant for in-situ effluent treatment.

Introduction

Deep saline formations appear to offer potential to store several hundred years’ worth of CO2 emissions. Wider international collaboration and consensus are needed to ensure the viability, availability, and permanence of CO2 storage. However, carbon capture/sequestration faces both technical and economic challenges. Therefore, there is the need to explore other methods to deal with CO2 emissions. Transformation to chemical feedstock such as methanol is a commercially proven technology; however, CO2 captured from furnace flue gas will not be economical for this purpose because of its low pressure. Compression is required before the CO2 could be processed into methanol.

Another process, the Sabatier reaction, converts CO2 to methane. This methanation process could prove to be less capital intensive, provided that reaction hydrogen is available from a low-cost source.

This work focused on the in-situ use of produced CO2 from the reforming and Fischer-Tropsch (F-T) reactions in a GTL plant for effluent treatment instead of the conventional use of sulfuric acid, which is not produced in the GTL-plant complex. Because the objective of this work is to reduce CO2 emissions, modifying the entire effluent-treatment system (e.g., corrugated-plate interceptor separators, aeration equipment, clarifiers, dissolved-air flotation separators, and chlorination and equalization units) will not be required. Only the neutralization unit, which controls the pH of effluent, will be modified.

GTL Technology

GTL technology comprises a chemical conversion of natural gas to a stable liquid by means of the F-T process. This conversion makes it possible to obtain products that can be consumed directly as fuel (e.g., diesel, kerosene, and gasoline) or special products such as lubricants.
Technology Focus: High-Pressure/High-Temperature Challenges (April 2012)
Authors: Payne Mike
Published: February 2015

Technology Focus

Step Changes Ongoing in the High-Pressure/High-Temperature World

Exciting operations are ongoing on the shallow-water US offshore continental shelf (OCS) that will influence the entire high-pressure/high-temperature (HP/HT) community going forward. McMoran and their operating partners are actively drilling, evaluating, testing, and bringing to production several deep HP/HT plays. These prospects are named in the Treasure Island theme with identities such as Davy Jones, Blackbeard, and Lafitte. The Davy Jones 1 is in the completion phase, incorporating multiple Eocene Wilcox sands, and it represents the first 25,000-psi completion of its kind in the world. The Davy Jones 2 encountered confirmed pay and is progressing well. The original Blackbeard well was taken to 32,997-ft total depth, and operations on Blackbeard East have been permitted to 34,000 ft. As with Davy Jones, these wells represent substantial extensions to or step changes in current HP/HT technologies.

To address the substantial engineering challenges associated with these wells, the operator formed a significant project team and is drawing on the expertise of several vendors in a collaborative manner to make the many advances necessary in HP/HT drilling and completion procedures and in production equipment and procedures. Downhole tools have been upgraded to 30,000 psi and 500°F. It will take considerable effort to catalog all of the “industry firsts” and “Serial-Number 1s” associated with these ongoing operations. Both Davy Jones wells are expected to be flow tested and put on production later this year.

HP/HT continues to be of international interest, with global operations ongoing from the North Sea, to Latin America, to the Middle East, and of course in the “ring-of-fire” regions in Southeast Asia. Operators, service companies, equipment suppliers, drilling contractors, and other involved parties share a common goal of addressing the many HP/HT challenges successfully and in a safe and efficient manner. These goals create a need to exchange information effectively, openly share lessons learned, and embrace a collaborative spirit that respects the competitive nature of business while valuing the shared interest that we all have in safe and reliable operations. Thus, the industry looks forward to learning more from the success of these HP/HT step changes in the US OCS ventures and from advances in other HP/HT operations around the globe.

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

IPTC 15175 Deep Workover Challenges of an HP/HT Sour-Gas Well—Case History of Mutriba 12 by M.J. Al-Saeedi, SPE, Kuwait Oil Company, et al.

SPE 142772 The Acorn Discovery: An Innovative Appraisal of an Offshore, Low-Deliverability, HP/HT Reservoir by P. Wood, Centrica Energy, et al.

SPE 148433 Feasibility Study of Casing-Drilling Application in HP/HT Environments: A Review of Challenges, Benefits, and Limitations by Amr Radwan, SPE, Cairo University, et al.
Managed-Pressure Drilling: Beyond the Conventional Limit in a Deepwater HP/HT Well
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142312, ’Managed-Pressure Drilling Enables Drilling Beyond the Conventional Limit in a Deepwater HP/HT Well,’ by F. Kernche, D. Hannegan, SPE, E. Sammat, and M. Arnone, SPE, Weatherford, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed.

Managed-pressure drilling (MPD) was used successfully on an offshore high-pressure/high-temperature (HP/HT) well. Wells in this field and other offset wells in the area had faced many problems including inadequate mud management resulting from depleted or overpressured zones, influxes, mud losses, and differential sticking. This well was drilled with a proprietary MPD system that is a closed-loop method of monitoring and controlling flow and pressure.

Introduction

MPD uses a closed and pressurized drilling-fluid (mud) circulating system that facilitates drilling with precise management of the wellbore-pressure profile. The primary objective of MPD is to optimize drilling processes by decreasing nonproductive time (NPT), mitigating drilling hazards, and enabling the drilling of otherwise technically or economically undrillable highly complex prospects.

Because MPD addresses NPT, the technology is of greatest potential benefit to expensive offshore-drilling programs. Although MPD was been practiced safely and efficiently from all types of offshore rigs, yielding the desired results, it still is considered a relatively new technology to many offshore drillers. The uptake in offshore MPD applications is, in part, because drilling is taking place in greater water depths, through depleted zones or reservoirs, and into narrow or relatively unknown equivalent-mud-weight (EMW) drilling windows.

Technical Justification

The application of MPD technology can optimize the drilling process by decreasing NPT and mitigating drilling hazards associated with conventional drilling techniques. Most importantly, the MPD system reduces drilling costs and limits drilling-cost uncertainty by:

Avoiding conventional-drilling NPT problems, such as lost circulation, shale instability, kicks, nuisance-gas zones, and differential sticking.

Increasing the rate of penetration, increasing bit life, and decreasing trip frequency.

Enabling access to potential assets/reservoirs previously believed to be undrillable by improving health, safety, and environmental (HSE) conditions.

MPD System

The MPD system used in this specific application consisted of a proprietary control algorithm to identify influxes and losses on a real-time basis and a choke at surface to apply backpressure to maintain well control. The system allows making drilling decisions on the basis of actual pressure and flow data rather than by use of predicted downhole parameters based on hydraulic models, and it provides real-time monitoring of the well-bore parameters while drilling.
Well-Testing Operations in High-Temperature Environments - Experiences and Best Practices
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148575, ’Challenging Well-Testing Operations in High-Temperature Environments - Worldwide Experiences and Best Practices Learned,’ by Alejandro Salguero, SPE, Edgar Almanza, and Josmar Haddad, SPE, Halliburton, prepared for the 2011 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Muscat, Oman, 24-26 October. The paper has not been peer reviewed.

High-temperature (HT) wells are classified as those with bottomhole temperatures in excess of 300°F. New technologies and advances in the industry (e.g., gauges, downhole equipment, and samplers) have been applied to improve decision-making capabilities and to increase well-testing-evaluation success, even in extreme and challenging environments. These enhancements enable improved economics and operational efficiency along with better safety conditions for the involved personnel and lower environmental risk during testing operations.

Introduction

Well testing is a reliable, dynamic method of retrieving and collecting a variety of information from the reservoir, including permeability, formation damage, bottomhole pressure and temperature, fluid samples, and production quantification. The methods and equipment used to collect these data have evolved as exploration has moved into more-demanding and -challenging environments.

In recent years, high-pressure/high-temperature (HP/HT) wells have become more common, and they required new techniques that support the environmental challenges. Proper planning and personnel and qualified equipment are key to achieve successful well-test results, especially considering that well and reservoir conditions can change easily from one region to another, adding challenges to the evaluation operation. HT prospects are defined as wells having bottomhole temperatures in excess of 300°F, and extreme HT wells are prospects having bottomhole temperatures of 350 to 400°F. The chart in Fig. 1 depicts designations for each pressure and temperature definition. Most HT cases have required the use of a deep-well simulator to test and qualify/certify equipment for the expected well-test conditions. 

The complete paper details three cases of testing wells with temperatures ranging from 340 to 430°F. These cases were carried out in different geographical locations. These wells were chosen because different bottomhole configurations of full-scale downhole assemblies were used.

It is important to mention that special tools and equipment are available to perform operations under extreme conditions (e.g., 450°F and 20,000 psi). Currently, electronic memory gauges used in drillstem-test (DST) equipment are designed and tested to work in conditions of 400°F and 30,000 psia. Real-time gauges are available that have been tested to 350°F. However, when more-challenging conditions are encountered, mechanical pressure and temperature gauges must be used.
Estimating Facies Fields Using the Ensemble Kalman Filter and Distance Functions
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 143031, ’Estimating Facies Fields Using the Ensemble Kalman Filter and Distance Functions - Applied to Shallow Marine Environments,’ by Rolf J. Lorentzen, SPE, Geir Nevdal, SPE, and Ali Shafieirad, SPE, International Research Institute of Stavanger, prepared for the 2011 SPE Europec/EAGE Annual Conference and Exhibition, Vienna, Austria, 23-26 May 2011. The paper has not been peer reviewed.

The ensemble Kalman filter (EnKF) is a promising tool for assisted history matching of reservoir models, and it works well for cases in which petrophysical properties are modeled by use of Gaussian random fields with variogram models. Many reservoirs have complex geological structures, which can have rapid spatial variations in the petrophysical properties (e.g., permeability and porosity). Applying the EnKF directly on such reservoirs can lose characteristics of the fields (i.e., sharp gradients are smeared). A method is proposed in which distance functions are used to estimate an arbitrary number of facies types.

Introduction

The goal for using the EnKF on complex reservoirs is to ensure that the updated fields are facies realizations, or at least approximations, and that a good history match is obtained. Truncated pluri-Gaussian methods are used for updating facies fields. Here, two Gaussian random fields are defined on the model grid. These fields then are updated by use of the EnKF, instead of updating the petrophysical properties directly. A truncation map then is used to assign specific combinations of the two Gaussian fields to a particular facies type. A different approach is to extend the EnKF to sample from Gaussian mixture models. The Gaussian mixture models can have multimodal distributions and are, thereby, more suited for facies fields. The distributions are obtained by computing a weighted sum of standard Gaussian distributions. The extension of the EnKF involves computation of the weights, conditional mean, and conditional covariances.

The method presented here introduces one level-set function for each facies type. The result is several distances at each gridblock with the same sign; therefore, the maximum of the distances in a given gridblock is used to determine the facies type. This method presents no restrictions on the structure of the facies field to be estimated, and any type of facies field may be estimated. A problem with this approach is that it is unlikely that the two functions change sign in the same gridblock, which makes it difficult to estimate fields if all types of transitions between facies types occur (i.e., it is difficult to estimate fields in which Facies 1 borders against Facies 4, or Facies 2 borders against Facies 3).
The Yarega Heavy Oil Field - History, Experience, and Future
Authors: Chertenkov M.V. , Mulyak V.V. , Konoplev Y.P.
Published: February 2015

Russia's Yarega Heavy Oil Field

In 1664, a grand embassy traveled from Holland to Russia. Nicholaas Witsen, a scientist and traveler, was a member of that party, and in 1687, he published, “The North and Eastern Tartary.” He wrote in that book, “The Ukhta River is a one-day travel from the Pechora River. There is a shallow place on the Ukhta River 18 miles from the portage where the water is stained with fat, appearing to be black oil.” In 1721, Gregory Cherepanov discovered an oil spring on the Ukhta River, and Tsar Peter the Great issued an order to inspect the oil spring and take samples for analysis. On 18 November 1745, the Mining Board of Russia granted Fedor Savelievich Pryadunov permission to build an oil plant on the Ukhta River. This was the beginning of the oil industry in Russia, in what is now the Yarega field.

The Yarega heavy-oil field was dis-covered in 1932. The field is located in Komi Republic, 20 km from the city of Ukhta. A prominent Soviet geologist, I.N. Strizhev, was a pioneer in discovering the field. The top of the terrigenous reservoir at the Yarega field is at 200 m true vertical depth (TVD). The rock properties have high permeability, oil saturation, and porosity. A dominant characteristic of the field is its high oil viscosity, 16000 mPa·s at the initial reservoir temperature of 6°C. The oil is heavy; in-situ density is 933 kg/m3, 945 kg/m3 at the surface. The gas ratio is 10–13 m3/ton.

At the initial field-development stage, attempts were made to drill wells from the surface to produce oil without any formation stimulation. Sixty-nine wells were drilled from two sites according to a 75- and 100-m triangle well-spacing pattern covering 43.4 hectares. The recovery factor after 10–12 years of development was only 0.017. Reservoir development from the surface without stimulation proved to be economically unjustified.

In 1934, the geologist A.V. Kulevsky proposed the idea of hot-water stimulation. Laboratory test results were encouraging, but insufficient technical and engineering support prevented the implementation of the thermal-stimulation technique in the field.
Openhole, Multistage Fracturing Holds Big Potential in Argentina
Authors: Lezama Pedro
Published: February 2015

Technology Update

Almost a century after its first oil discovery, Argentina is making headlines again through reports of the potential of the Vaca Muerta Shale in the Neuquén Basin—the most prolific basin in Argentina (Fig. 1). The existence of Vaca Muerta, which means “dead cow,” has been known for years, but the formation received little attention until the development of shale plays in North America. Vaca Muerta is virtually a virgin play with only a few operators involved. Yet with Argentina’s need to increase production and reduce dependence on foreign oil and gas, change is clearly in the air.  

Expanding Reserves and Production

YPF has reported reserves and resources in the Vaca Muerta formation to be an estimated 22.8 billion BOE (YPF 2012). Encouraged by the estimate, YPF and several other Argentinean operators are continuing exploration activity to define the extent and productivity of the Vaca Muerta, particularly to identify the oil, wet gas, and dry gas areas. Early results suggest that Argentina has an opportunity to replicate the unconventional resource revolution of the United States and eventually meet domestic oil and gas demand through internal production. 

Argentina has the potential to increase oil and gas production by 50% in 10 years, which would reverse the negative trend that turned the country into a net importer in recent years. Yet this potential does not come easily, as preliminary estimates indicate the need for more than 1,000 wells to be drilled as a first step and 40 additional rigs to accomplish the goal. Besides the investment challenge that the Vaca Muerta now faces, there is an immediate challenge that needs to be dealt with: What is the best way to produce Vaca Muerta?

Maximizing Production in Shale, Other Tight Plays

In North America, the production of oil and gas from shale has increased greatly since 2007, with the development of several key plays such as the Bakken in North Dakota, the Barnett and Eagle Ford in Texas, and the Marcellus in the eastern United States, which have helped to reverse the declining production of the past few decades. The US and Canadian oil and gas industries were prepared for shale development. While these plays were not new to them, the use of new, unconventional exploitation technologies has been critical to success. In particular, as several studies have proved and is widely known in the industry, the challenge in these shale plays is connecting productive channels and creating fractures that will allow proper fluid movement and endure through the production cycles.
Turning a Scientific Tool Into an Engineering Machine
Authors: Rassenfoss Stephen
Published: February 2015

Rock Tester

Nobody knew where the oil and gas was trapped inside shale until a scanning electron microscope (SEM) showed the pores within the organic material inside.

Now there are a growing number of machines creating three-dimensional (3D) digital replicas of these rocks by combining SEM imaging with a focused ion beam (FIBSEM), which cuts off ultra-thin slices like a meat slicer, revealing multiple layers within.

These 3D digital images are incredibly detailed, but they are based on cubes whose longest side is 10–20 micrometers—millionths of a meter—making them small enough to fit into the spaces in porous sandstone. When it comes to building reservoir models, it leaves engineers wanting more.

“The real challenge is we are creating micron-sized images and dealing with square miles of resources,” said Carl Sondergeld, a professor at the Mewbourne School of Petroleum and Geological Engineering at the University of Oklahoma (OU). “If we can transcend those scales we can do a better job of characterizing reservoirs.”

In the pursuit of more, he and Chandra Rai, professor and director of the Mewbourne School, have built up one of the largest unconventional rock research laboratories, backed by 12 oil companies. The focus has been on understanding the workings of the nearly impermeable rocks, which has changed how some properties are measured.

The large lab displays Sondergeld’s constant hunt for improved tools for analyzing how rocks and reservoirs perform. The laboratory recently added the latest generation of scanning electron micro-scopes from one of the biggest makers of these instruments, FEI.

One thing that sets this FIBSEM machine apart is its ability to stitch together thousands of micron-scale images to create 2D pictures covering rock surfaces measured in millimeters rather than micrometers.  These hyper-detailed pictures offer an overview of an area, with the option of zooming in for a closer look to see if low-resolution impressions are correct. They often are not.

Another plus is its ability to create images using extremely low power—as low as a 100 V compared with 30,000 V for older machines—creating images that may offer better ways of measuring critical details, such as the amount of kerogen—the organic material that is the source of the oil and gas.
Technology Focus: Offshore Drilling and Completion (April 2013)
Authors: Santos Helio
Published: February 2015

Technology Focus

We all know that things have changed significantly for offshore drilling and completion in the last 3 years. Regulations have been reviewed, and operational procedures and requirements have changed. Requirements for the well design to be reviewed by independent parties and new equipment testing procedures and certification were just a few additions that regulators brought to the scene. Several initiatives were launched to develop equipment to cap flowing wells offshore, new ways to record and control testing of critical equipment, and new systems to assess and monitor the barriers present in the well more effectively.

The industry has shown a significant creativity, as usual, to demonstrate to society in general that we can continue to drill and produce hydrocarbons offshore in a responsible manner. And, by offshore, we now mean wells located in waters as deep as 10,000 ft. In the industry’s move toward these challenging environments, most of the time we use technology known and proved for shallow waters and just resize the equipment. However, the challenges are not restricted to a deeper column of water. Many wells are facing additional challenging situations such as being subsalt or pre-salt, having high-pressure/high-temperature prospects, and having total depths in excess of 25,000 ft. Many specific conditions must be addressed in these new environments, and simply extending the envelope of current solutions to more challenging conditions may not be enough or suitable anymore. The lack of riser margin and the challenges posed by a long chokeline during well control operations are just two examples of the new conditions that did not exist 30 years ago and, therefore, require a shift in the thinking process to allow wells to be drilled and completed more economically in these new challenging environments.

After a period of uncertainty for offshore operations, wells are now being drilled again, albeit under more strict rules and guidelines. Most of the new rules and guidelines have been applied to well design and the preoperational phase. It is important also that operations be conducted under proper conditions, providing people on the job with all the means and tools necessary for them to conduct their jobs successfully.

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

SPE 152861 A Solution to the Problems Associated With Tight-Clearance Boreholes: The Close-Tolerance Press-Fit Stop Collar by J.A. Wimberg, Chevron, et al.

SPE/IADC 151182 Blowout Preventer Health Monitoring by Jim McKay, BP, et al.

SPE/IADC 150047 Successful Qualification and Deployment of a High-Pressure Drillpipe Riser in West Africa by Mathieu Camus, Total, et al.
Proposed Cluster Liquefied-Natural-Gas Production System Raises Tolerance of CO2
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23261, ’Development of CO2-Tolerant LNG-Production System,’ by JungHan Lee, Jeheon Jung, and Kyeongmin Kim, SPE, Daewoo Shipbuilding and Marine Engineering, prepared for the 2012 Offshore Technology Conference, Houston, 20 April-3 May. The paper has not been peer reviewed.

During natural gas liquefaction, CO2 must be removed to prevent icing and plugging in the system. The CO2-removal system may be the most important part of the gas-treatment system. CO2 removal systems require complicated amine contactor and regeneration systems with substantial heat sources. The CO2-tolerant natural-gas-liquefaction system called cluster liquefaction accepts approximately 1% of CO2 for the liquefaction and related systems. The CO2-tolerant characteristics of this liquefaction process will provide a multifold safety margin against CO2 problems in cryogenic systems and valves.

CO2-Tolerant Liquefied-Natural-Gas (LNG)  Production System

Considerations. Natural gas liquefaction at higher pressures and equivalent higher liquefaction temperatures has the advantages of reducing liquefaction energy and adopting more-efficient refrigerant. Despite the advantages, the higher-pressure storage requirement for the produced LNG has been a cost burden in overall LNG chains. For that reason, natural gas liquefaction at higher pressures has not been adopted by the industry.

The specific weight ratio (SWR) of natural gas, defined as the natural gas weight divided by the containment system weight, is an important indication of capital expenditures. The typical SWR of conventional LNG is approximately 10–20 times that of compressed natural gas (CNG). Even for the increased- pressure LNG, the SWR is typically 10 times that for CNG. Hence, storage as a liquid after cooling and insulation is far more efficient than CNG.

For increased-pressure LNG, the main cost contributor has been the cryogenic material for the higher pressure. However, if a cost-effective solution for increased-pressure containment is developed, it may become a viable option.

Examples. Intermediate-Pressure LNG (20 bara, 1% CO2). Substantial CO2 can be dissolved in LNG produced at increased pressure. CO2 in the LNG should be liquid, not solid or as two phases. During cool down at a predetermined pressure, the feed gas can pass through the solid formation region in the interim stage. Hence, this region should be avoided by liquefying the natural gas at a higher pressure before reducing the pressure. If the CO2 level is sufficiently lowered during the gas treatment, the solid formation can be avoided regard-less of the liquefaction temperatures and processes.
Data Gathering to Smooth the Bumpy Path to Optimization
Authors: Rassenfoss Stephen
Published: February 2015

Fracturing

Noble Energy has had powerful motivation to invest in learning how to maximize the return on its wells in the Wattenberg field in Colorado—its biggest current investment and key to the company’s aggressive growth program.

Over the past 3 years, the independent oil company has drilled nearly 600 wells in extremely tight Niobrara formation rock. The company plans to go from 320 wells per year in 2014 to 680 wells in 2018, according to a recent Noble Energy investor presentation. This effort is needed as it works to double its daily production over the next 5 years.

For the team working to maximize production and profits in that field, one of the biggest questions has been, and continues to be, how many wells to drill per square mile.

This is a common question in the industry, but the company has done something uncommon to help answer it: Noble created an “Underground Laboratory.” It is in a section of land with nine horizontal wells, spaced at varying intervals. The “Laboratory” includes a pair of horizontal wells with multiple fiber-optic and pressure sensors amid a cluster of vertical monitoring wells and provides a multidisciplinary team of geoscientists and engineers a rare and unusually detailed look at oil production in the Niobrara on a meter-by-meter basis.

“What we are trying to do is essentially bring the equivalent of high-definition television down underground to directly observe what is happening and then come back and figure out, how do we explain what we see,” said Dave Koskella, exploration and reservoir systems manager at Noble.

What looks like a geoscientist’s fantasy come true—a list of diagnostic tools included in a presentation at February’s SPE Hydraulic Fracturing Technology Conference in The Woodlands, Texas, consisting of 13 items, some with subheads—was created to answer critical questions facing the business. “It is a laboratory that is challenging our insights and beliefs about why and how things are working in our wells,” he said.

While Noble’s investment in diagnostics is exceptional, the problems it is trying to solve are common for the companies focusing their exploration and production program on developing unconventional formations in the United States and Canada.
E&P Notes (April 2014)
Authors: Jacobs Trent
Published: February 2015

E&P Notes

Why Global Shale Development Drags

While shale unproved technically recoverable resources have been identified around the world, development has been limited to North America. At the SPE Hydraulic Fracturing Technology Conference in The Woodlands, Texas, in early February, service company executives offered reasons why international development could be years off.

Even in countries where there is an urgent need for more oil and gas, such as India and China, there are obstacles to development ranging from electrical code incompatibility issues to the lack of equipment needed for factory-like development to questions about rock properties and mineral rights. A sample of the barriers to development in Australia, China, Saudi Arabia, and India shows why it takes time to develop a country’s shale gas or oil potential.

Controlling BOP Downtime

Shell and Transocean formed a partnership to work on designing a more reliable control system for blowout preventers (BOPs). Their goal is “eliminating BOP control system downtime” with a 3-year project to design fault-resistant and fault-tolerant control systems that could be used to retrofit BOPs currently in use.

Using Lasers in the Arctic

Using laser beams to send high-speed streams of data, a technique that has been used by the US Navy for secure submarine communications through ice, is being offered as an option for offshore oil operations. The possibilities range from using pulsed laser signals to both measure the thickness of ice sheets and detect oil leaks beneath them in the Arctic, to providing data links for autonomous underwater vehicles (AUVs) harvesting data from wireless seismic sensors on the ocean floor.

So far, the most concrete version of this idea is the simulation provided by defense-contractor-turned-offshore-oil- technology-company Qinetiq (pronounced kinetic). It presented its ideas about laser communication and testing at OTC’s Arctic Technology Conference in Houston, Texas, this February. The company is also working on options for communication links in deep water, where there are a lot more potential users.
SPE Nominations: Nominees Announced: 2016 SPE President and 2015 Slate of Directors
Authors: Beckwith Robin
Published: February 2015

SPE Board Nominations
Surface-Controlled Formation-Isolation Valves Used for Temporary Well Suspension
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 23997, ’Case Study: Surface-Controlled Formation-Isolation Valves and Their Application as a Barrier for Temporary Well Suspension,’ by Oguzhan Guven, Joao Mendonca, and Dan Thai, Schlumberger, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.

To increase deepwater-drilling-rig availability, operators have adopted the strategy of transferring subsea-tree-installation responsibility from offshore drilling rigs to subsea-equipment- support vessels (SESVs). The installation from a rig can take 1 to 3 weeks; transferring this responsibility to the support vessel enables the rig to move to the next well sooner and offers significant time savings. This paper introduces a fit-for-purpose surface-controlled formation-isolation valve (SFIV) designed for the temporary well suspension required for this strategy.

Introduction

One of the deepwater subsea-field-development operations being transferred to SESVs is the vertical-tree installation employing the “tree-by-wire” technique. One of the key components of this technique is the use of two remotely operated formation-isolation valves that suspend the well after installation of the tubing hanger. Once the well is suspended, the rig can be moved to the next well. The tree is then installed by use of a heave-compensated wire from an SESV.

A new generation of SFIVs has been designed to enable the well suspension involved in this technique (Fig. 1). Several critical requirements were considered in the development of these valves:

Reliable bidirectional sealing.

Repeatable remote operation.

Fail-as-is: In case of a failure in the control system or the valve itself, the valve must not change its position.

Ability to open under high differential pressure.

High debris tolerance.

Two sizes of SFIVs were developed that meet these requirements. These were fully field tested in 2011 and 2012 in 11 different field installations.

Design and Key Features

The ball section of the SFIV is designed to tolerate the debris common in harsh well environments. The SFIV uses a nontranslating ball valve with bidirectional sealing, which is the ideal valve system for high-debris environments. The ball-valve primary seal is a gastight seal and sustains its integrity even after repeated actuations under pressure differentials.

To allow for increased setting depth, the SFIV actuation section uses a displacement-based fail-as-is mechanism, which functions independently of the setting depth. Most other lubricator valves use a holding system that counteracts the hydrostatic pressure in the event of a control-line leak. At extreme depths, the hydrostatic force acting on the actuation piston creates a large force, increasing the holding force for the valve position as well. This can create operational issues.
Inshore Floating LNG for Liquefaction of Onshore Shale Gas
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24091, ’Development Options for North American LNG Export: The Merits of Inshore-Deployed FLNG for Liquefaction of Onshore Shale Gas and Examination of Principal Technology Drivers,’ by Joe Verghese, WorleyParsons Europe, and Nancy Ballout, WorleyParsons Houston, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.

The advent of shale-gas production onshore North America, the resulting overhang of gas supplies, and the downward pressure on gas prices have led operators to consider the possibilities of liquid-natural-gas (LNG) liquefaction plants for the export of LNG from coastal locations to international markets. Several proposals for onshore liquefaction relate to the conversion of existing LNG regasification sites. The paper assesses the technology implications of migrating LNG floating production, storage, and offloading (FPSO) concepts to inshore service.

Market Context

The energy markets have seen a remarkable evolution in gas developments driven by a number of factors including the relative abundance of this energy resource and its global availability, flexibility in use, and low carbon number. According to the International Energy Agency (IEA), gas will increase its share of the global energy mix from 21% in 2009 to 25% by 2035.

Against this backdrop, the shale-gas revolution in North America has already led to gas self-sufficiency, with North America poised to be a net exporter by 2016. According to the IEA, the introduction of horizontal drilling, hydrofracturing, and resource targeting technologies has led to a 27% increase in natural-gas production, from 2005 levels to 23 Tcf in 2011 (Fig. 1). A further increase of 44% from this 2011 level is foreseen by 2040. US natural-gas production has outpaced growth in demand by a ratio of 2:1 since 2005, leading to downward pressure on natural-gas prices.

These factors have prompted owners of existing LNG regasification terminals to sense a shift in the demand/supply balance, and to seek approval to install liquefaction facilities for export of LNG. By the end of May 2012, 15 applications had been submitted to the US Department of Energy for export authorization, amounting to a staggering 145 million t/a of capacity.

The sweet spot for floating liquefaction units lies precisely in the greenfield phase of the LNG-export scenario. For greenfield developments, the atshore or inshore deployment of floating LNG (FLNG) can offer interesting advantages over its onshore counterpart. These include potential for faster permitting, a faster construction schedule, and significant potentials for standardization and redeployment.
Advances in OH Multistage Fracturing Systems - A Return to Good Frac-Treatment Practices?
Authors: Themig Dan
Published: February 2015

Technology Update

New developments in fracturing systems have returned focus to good fracturing practices that have been all but abandoned with the advent of horizontal wells. In major plays, such as the Barnett Shale of east Texas, operators have employed fracturing practices that are often inefficient and ineffective. Examples would include the massive overdisplacement of prop-pant and extended shut-in periods during a well’s completion phase, instead of initiating immediate flowback and load recovery.

One of the problems with resource plays is that field development moves at a very rapid pace. In addition, most of the work is designed to simulate a manufacturing assembly-line process, i.e., use the minimum number of technical people to complete the maximum number of wells. Much of the engineering used in completion design has been replaced with a one-size-fits-all process. In our view, good fracturing practices developed over some 40 years are being ignored in the field-development strategies of many of today’s resource plays.

Fortunately, there are now major developments in multistage fracturing technology that address many of these problems. One example is a new series of high-density, openhole (OH) fracturing systems that allow more than 20 fracture treatments to be performed in a single, seamless operation (JPT 2009).

High-Density Fracturing Technologies

The first OH multistage fracturing systems were installed in late 2001. At that time, it was believed that four to five stages would be sufficient to drain most horizontal wells. It would have been unimaginable to think that a few years later, the industry would be installing fracture liners with more than 40 OH packers. Key developments have taken place across a number of venues to make this possible. One item that was in question in the early days, but has now been clarified, is the ability to push long, high-density frac liners into a well. The industry now has the ability to accurately model installations of frac liners with OH packers with a high degree of certainty.

In addition, hardware developments have taken place to allow higher-density fracturing. Issues such as abrasion and erosion encountered in massive hydraulic fractures, with millions of pounds of proppant, had to be addressed. The primary activating method for these OH systems is a ball-actuated port mechanism. Continued advancement in the systems, including 8 years of R&D into materials and the mechanics of the process, has greatly enhanced industry capabilities. More than 10 types of ball materials now are offered, as well as numerous port-design options. The net effect is that capabilities have increased from four or five fracture stages per well to more than 20 stages, using this mechanism. Engineering work is under way to increase these numbers to more than 60 fractures in a single horizontal. (The current record for number of stages is 47, installed in a ~10,000-ft lateral in the Bakken Shale of North Dakota [Slawson Exploration/Packers Plus Energy Services, 2010].)
Techbits: Integrity Management Focus of Middle East Workshop
Authors: JPT staff _
Published: February 2015

Techbits

Abu Dhabi played host earlier this year to an SPE Applied Technology Workshop (ATW) titled “Sustaining Business Excellence and Process Safety Through Effective Facilities Integrity Management.” The goal: to provide the more than 80 professionals in attendance with various perspectives on managing the challenges of ensuring safe and efficient operations in the face of aging facilities and increasing economic constraints.

Over 3 days, the ATW provided integrity-management (IM) professionals from facilities across the value chain the opportunity to share their experiences and best practices in managing the above challenges while also facing increasingly stringent health, safety, and environmental (HSE) regulations and a more competitive business environment. It also served as a platform to present and discuss equipment-specific IM systems for oil and gas surface and subsurface facilities, both onshore and off.

Some of the main points raised by the speakers and participants over the 3 days follow, summarized by topic.

IM System

One of the first day’s major topics addressed the factors that make for a successful facility IM system.  Some delegates stressed that to be effectively implemented, an IM system must link to a corporation’s top objectives and be supported at all levels. The system needs to be driven in a top-down manner, with top management taking a leadership role and clearly communicating the system’s stated objective down the line to technicians and operators on the ground such that IM awareness becomes part of their daily activities, much like personal safety.

One delegate drew the analogy that just as a cake includes common ingredients, any IM system also includes common components, including management of change, competence, learning, risk management, and standards.

A successful system should envelop the whole life cycle of a facility and include assess/select phases at the earliest project stages, when maximum risk reduction could be achieved. Integral to this is a clear definition of the facilities’ physical boundaries and operating envelopes, as well as the establishment of key performance indicators (KPIs) to monitor the system’s effectiveness. These KPIs should be clearly linked to corporate objectives, consistent throughout a given industry to allow for bench-marking, and have the right mix of indicators for lagging vs. leading and effectiveness vs. efficiency.

Other delegates stressed that system implementation should not take a “one-size-fits-all” approach because different companies may have to take different approaches, even though they all have similar ultimate objectives in ensuring that their assets remain running safely and with a minimum of down time.  The system should be driven by an established mature framework, and should clearly define accountabilities by nominating competent persons and technical authorities for key roles.

Finally, an IM system should be developed as a system of continuous improvement.