bluuebunny/crossref_metadata_2025_split 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 The paper has not been peer reviewed.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.