bluuebunny/crossref_metadata_2025 huggingface dataset:
Big Data Is a Big Deal
Authors: Anand Pradeep
Published: February 2015

Guest editorial

The global population is forecast to grow to about 10 billion people by the middle of this century. While this population growth will generate a growth in global GDP, it will also create significant stresses on resources needed to feed the population and fuel its economic growth, with the demand for food-water-energy creating a “stress nexus.” 

The Food and Agriculture Organization of the United Nations predicts that by 2030 demand for food will increase by 50%. The International Food Policy Research Institute expects demand for water to increase by 30%. And the International Energy Agency forecasts that energy demand will surge by 50%, despite projected progress in improving consumption efficiencies.

Alternative fuels are forecast to find ready markets and increase their percentage of the energy mix, yet oil and gas are still expected to deliver about 60% of the energy needs of the future. For example, in 2040 the exploration and production (E&P) sector is projected to be faced with delivering about 30% more oil production liquids, about 110 million b/d of oil equivalent, than it does today. The E&P industry is expected to find and develop new types of resources through innovations in technology used in deep water, the Arctic, oil sands, tight oil, unconventional gas, biofuels, and other areas. However, two major issues will mute and limit that success:

Manpower. As demand increases, the need for manpower increases and manpower availability decreases. Simultaneously, experienced people will retire and exit the industry in record numbers.

Data and knowledge. Our current knowledge of existing reservoirs and our practices are based on partial data. It is a truism in the business world that 80% of business-relevant information originates in unstructured forms. In the E&P industry, where “natural data” cannot be ordered and constricted to the confines of “manmade” databases, the percentage of unstructured data can be substantially higher.

In the domain of criminal justice, The Innocence Project has shown that partial data can lead to partial truths, in some cases leading to incarceration of innocent people. In many of those cases, DNA evidence not considered in earlier jury trials has exonerated innocent people who spent decades in prisons. Partial data can lead to partial truths.

The E&P industry has had success working with partial data and partial truths but it is imperative that it work with more and better data, or “Big Data,” to get closer to the whole truth, and to ensure greater success so vital to meet projected future demand of a growing global population.

Both challenges mentioned above could be met by focusing attention on creating a unified data store that is a ready platform to apply computational algorithms and analytics to extract patterns from both structured and unstructured data. These patterns can then be used to create models with forecasting, anticipatory, or predictive capabilities that reduce the cones of uncertainty or increase the probabilities of success of actions in the E&P industry.
Floating Compressed-Natural-Gas System Provides Simpler Path to Monetization
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23615, ’Floating CNG: A Simpler Way To Monetize Offshore Gas,’ by David Stenning, SPE, John Fitzpatrick, and Mark Trebble, Sea NG, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.

Monetizing offshore gas by compressing and shipping it in floating compressed-natural-gas (FCNG) carriers is simpler and, in most cases, less expensive than liquefying and shipping it in floating liquefied-natural-gas (FLNG) carriers. Seaborne compressed-natural-gas (CNG) transport requires essentially the same infrastructure as pipeline export, except that the gas is compressed into a ship rather than a pipeline. FCNG provides a new way to add to the world’s natural-gas supply by allowing smaller offshore gas fields to be exploited economically.

Introduction

Many offshore gas fields are too small or too remote to produce by pipeline to shore. The liquefied-natural-gas (LNG) industry has advanced to fill the need with respect to larger gas fields by creating an FLNG production concept where an LNG processing and refrigeration plant, complete with LNG storage, is integrated into a ship or barge and moored at a gas field. LNG ships are then used to offtake the LNG and deliver it to markets, where it is stored and regasified as needed. A simpler and less expensive way to produce gas from many fields is to avoid liquefaction altogether and instead compress the gas into CNG ships, which then deliver it to regional markets.

Virtually all floating production, storage, and offloading (FPSO) ships in operation today treat and compress natural gas, either to reinject associated gas or to export it by pipeline. This is the same technology required to produce CNG offshore.

CNG vs. LNG

To transport natural gas efficiently, its density must be increased. The principal way to achieve this is by decreasing temperature or increasing pressure. Decreasing the temperature to −162°C causes it to condense to a liquid at ambient pressure and results in a volume ratio of 600:1. Compressing the gas to 275 bar at ambient temperature squeezes the gas to a dense gaseous phase with a volume ratio of 300:1.

For many projects, CNG is a lower cost solution. In the past, no CNG ships were developed or approved, so this more-economical CNG solution was ignored. A decade of work on the regulations, engineering, and full-scale fatigue testing has paved the way for the first commercial CNG ships.

FCNG: A Shuttle Tanker Operation

An FCNG production vessel is a traditional gas floating production and offloading (FPO) unit with a high-pressure gas transfer system to load Coselle CNG shuttle ships instead of a subsea pipeline. CNG is transferred at near-ambient temperatures, so the hoses and transfer systems are the same as those used to transfer high-pressure gas and well fluids onto an FPO unit.
Handling Jurassic Field Sour Gas Creates Challenges Upstream and Downstream
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 154452, ’Challenges in Sour-Gas Handling for Kuwait Jurassic Sour Gas,’ by Bader Nasser Al Qaoud, SPE, Kuwait Oil Company, prepared for the 2012 SPE Middle East Unconventional Gas Conference and Exhibition, Abu Dhabi, 23-25 January. The paper has not been peer reviewed.

Kuwait Oil Company started free gas production from its Jurassic sour-gas field in May 2008 with the commissioning of Early Production Facility (EPF) 50. The field produces sour gas and light crude from a deep high-pressure/high-temperature naturally fractured carbonate reservoir with low permeability and low porosity. The well fluid is characterized by high hydrogen sulfide (H2S) (5%) and carbon dioxide (CO2) (5%) content. Handling such highly corrosive well fluid creates a wide range of challenges, from upstream at the wellhead to downstream at the processing facility.  

Upstream Challenges

Upstream challenges for the Jurassic gas field have been related mostly to subsurface corrosion of tubing, unplanned well downtime because of hydrate formation during winter, and failure of automated chokes for some wells.

Subsurface Tubing Corrosion. A moderate to severe corrosion rate has been indicated by corrosion logs in the production tubing because of the high H2S and CO2 content of the well fluid. Plans exist for existing carbon-steel tubing for four wells to be replaced by corrosion-resistant alloy material, and regular corrosion logs are being run for other suspect wells.

Hydrate Formation in Flowlines. Hydrate formation has been observed in flowlines during winter for 11 wells when flowline temperature drops to 65°F. This has resulted in unplanned production loss and substantial well downtime. The best mitigation option implemented was the injection of kinetic hydrate inhibitor (KHI) at the wellhead at the onset of winter for the identified wells, and a good degree of success has been achieved. However, KHI is not very effective in controlling hydrates at temperatures below 4°C, and this is a problem that needs to be addressed as a priority.

Flowline insulation at the point of restriction and heat tracing also have been implemented for four wells, with a fair amount of success.

Challenges With Automated Chokes. Automated chokes were first installed in the field in April 2011. The purpose of automation was to improve control of remotely located wells, enhance safety, and ensure better control of field production. Sixteen Jurassic wells are currently on automated chokes of three different makes—M1, M2, and M3.

Challenges With Make M1. The factory-set choke opening did not match actual choke opening. Choke adjustments had to be made with flowing wellhead pressure (FWHP) as a reference, and this leads to inaccurate settings. Scale formation also has been observed in-side the choke body, causing restricted flow and inaccurate FWHP readings and, therefore, poor monitoring of well performance.
Offshore HP/HT Gas Well: Drilling and Well Testing
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 155320, ’Offshore Drilling and Well Testing of an HP/HT Gas Well: A Case Study,’ by Prerak H. Shah, SPE, Harsh T. Pandya, SPE, Harsh Sharma, and Arpit Saxena, SPE, Gujarat State Petroleum Corporation, prepared for the 2012 SPE Oil and Gas India Conference and Exhibition, Mumbai, 28-30 March. The paper has not been peer reviewed.

With exploration in harsh environments and consequent high-pressure and high-temperature conditions, calculating reservoir properties has become complex and changes in pressure-transient response need to be understood and appreciated by taking appropriate measures. The challenges arising with drilling and testing of high-pressure/high-temperature (HP/HT) gas wells that produce hydrogen sulfide (H2S) and carbon dioxide (CO2) in the Krishna Godavari basin are discussed.

Introduction

In the exploration campaign in the Krishna Godavari basin off the east coast of India, four wells were drilled, discovering a very tight gas reservoir with an average pressure of 12,000 psi and an average re-corded temperature of 360°F and classified as an HP/HT reservoir, as shown in Fig. 1. This paper discusses the experience drilling four wells with a jackup rig in average water depth of 60 m.

Well-A was the first well. Well-B dis-covered and flowed gas from stratigraphy below the section encountered in Well-A. Well-C encountered the same sands found in Well-A, and additional shallower sands not encountered in Well-A or Well-B were discovered. The reservoir section is overlain by shale. Well-A was drilled in six sections because it was the first exploratory well; the other three wells were drilled in five sections. All wells had sections of 36-, 26-, 17½-, 12¼-, and 8½-in. hole and Well-A had an additional 6-in. section. These sections were cased with 30-, 20-, 13⅜-, 9⅝-, and 7-in. liner casings, respectively, and Well-A included a 5-in. liner. The reservoir section expected in 8½-in. hole from seismic and log data was proved while drilling Well-A and was appraised in Well-B, Well-C, and Well-D. Well-A and Well-B were drilled to total depth with water-based mud (WBM). The 12¼-in. section of Well-C was drilled with WBM, while the 8½-in. section was drilled with synthetic-oil-based mud (SOBM). The shale sections and reservoir section in Well-D were drilled using SOBM. The mud program was designed on the basis of the pore-pressure-leakoff-test (LOT) vs. depth chart shown in Fig. 2.
Shale Gas Drives Vertical Integration
Authors: Rao Vikram
Published: February 2015

Guest editorial

The November issue of JPT quotes the views of Mary Van Domelen, senior engineering advisor at Performance Technologies, given in her presentation “The Pros and Cons of Vertical Integration” in shale gas-related operations. All her examples of current activity are in the realm of the vertical with the operator and a service company offering fracturing and other drilling or completion services. Her presentation was part of the SPE Liquids-Rich Basins Conference, held in September 2013 in Midland, Texas. Interestingly, both dry and wet gas can benefit immensely from a different form of vertical integration provided certain new technologies take hold. This is a vertical involving the producer and a service that monetizes low-value portions of fluids in unique ways.

Wet Gas

Today, almost all the profit is in the wet gas component. But a subplot is that ethane usually makes up nearly half the volume of natural gas liquids (NGLs). Unlike the bigger molecules, such as propane and butane, ethane has no direct use until cracked to make ethylene. Thirty-three of the 36 crackers in the United States are located on the Gulf Coast, about 1,200 miles from the Marcellus shale in Pennsylvania. Consequently, there is an ethane glut, resulting in low prices. Dow Chemical’s David Bem reported in December that ethane dropped to natural gas price levels in 2013 and had begun to track with it (Fig. 1). This would be a windfall for ethylene producers except that the crackers are located at a distance.

Local cracking seemed to be where matters were headed. However, early in November 2013, Shell announced that it had shelved plans to build a cracker in Pennsylvania. This leaves the ethane stranded absent a pipeline to transport it down to the Gulf of Mexico. A better solution would be small crackers, 50 to 100 times smaller than conventional plants, distributed close to the production. Development is in progress to realize this “GTL Lite” concept. The definition of liquid in this context is broad: It could be any high-value liquid, not just diesel that traditionally comes from larger GTL plants.

Security of supply is much simpler with small units, particularly because a lot of the producers themselves are small. And it is immensely simpler if the producer and cracking process owner are vertically integrated. Even long-term pricing would not be a contractual hurdle. But true vertical integration is hampered by the fact that the producer has no domain understanding of the other area, which is essentially downstream in character.

For unconventional hydrocarbons, including heavy oil, a blurring of the upstream, midstream, and downstream sectors is occurring. Small footprint processing, when commonly available, will only serve to hasten this blurring.
Research Funded by DOE/RPSEA Advances Ultradeepwater Technology
Authors: Long Roy
Published: February 2015

Technology Update

A number of research projects awarded by the Research Partnership to Secure Energy for America (RPSEA), with funding and oversight by the United States Department of Energy’s National Energy Technology Laboratory (NETL), have shown solid potential to advance deepwater and ultradeepwater (UDW) oil and gas development.

The DOE/RPSEA projects are among more than 15 to be featured in a session on funding new E&P technologies on 7 May at the Offshore Technology Conference (OTC) in Houston. Chairing the session will be James Pappas, vice president of ultradeepwater at RPSEA. Nine of the technologies developed through this research are discussed herein.

One of the projects, highlighted on the cover of the January 2014 issue of JPT, is the Lockheed Martin Marlin autonomous underwater vehicle. This system has the following advantages over remotely operated vehicle (ROV) systems: 3D model generation in hours vs. days; the use of smaller vessels with fewer crew members; no need for umbilical management; realtime change detection, enabling on-site assessment of survey results and structural anomalies; rapid assessment capability of potential environmental damage; and the ability to generate accurate, geo-registered models for structural integrity assessment.

Also under consideration is the inclusion of high-resolution visual imaging to enable accurate subsea measurement of flow rate from a blowout or from ocean floor seeps for predrilling site investigations. The project is in its final phase of development and scheduled to be complete by June.

Another interesting set of projects deals with metocean issues that affect UDW development. Studies in this area have continued since the early days of UDW research and development within RPSEA. The first efforts studied the US Gulf of Mexico (GOM) loop currents to develop a better hurricane forecasting model, because these relatively warmer currents often increase hurricane intensity.

The goal of these projects was to develop a better long-range forecast (of up to 90 days) of hurricane activity in the GOM. The newer models with higher resolution potentially could better describe the density of the spiral rain bands caused by higher wind velocities farther from the center of the storm. The spacing of these bands appears to have a greater influence on the extent of damage sustained by an offshore vessel than hurricane classification or size, as the spacing more directly affects seawater wave height.
Techbits: Workshop and Survey Focus on SPE Petroleum Resources Management System
Authors: McMillan Don
Published: February 2015

Techbits

An SPE workshop titled “Application of the SPE Petroleum Resources Management System (Unconventional Resources),” was held 14 November, the day after the 2013 SPE Unconventional Resources Conference and Exhibition–Asia Pacific in Brisbane, Australia. The workshop attracted 83 participants from nine countries and speakers from the exploration and production sector, the finance sector, service companies, consultancies, and academia.

The goal of the workshop was to highlight the challenges faced by the industry in estimating unconventional resources. The SPE-PRMS, published in March 2007, endeavors to encompass the full life cycle of all types of petroleum resources. Since 2007, the industry has experienced remarkable growth in unconventional resources. Unconventional plays challenge the fundamental conventional definitions of reserves and resources estimation, including the definitions required to demonstrate a discovery and commerciality. Within the investment and regulatory community, the growth and importance of unconventional reserves and resources have fueled discussion on the credibility and dependability of oil and gas estimates. To assist in the application of the SPE-PRMS, a second document called Guidelines for Application of the Petroleum Resources Management System was published by SPE in 2011. Based on discussions I have noted in the industry, it seems there is a need for further clarification in the interpretation and application of the PRMS.

The workshop gave an opportunity to gauge participants’ perception of the SPE-PRMS. A survey was sent to the 83 participants; 37 responded. The results of this small survey are set out below. The demographics and experience level of the respondents were not captured and, therefore, the results are conditional. The comments are the author’s interpretation of the survey results. As with all surveys, it is possible that how the respondents answered questions may apply to a broader population. The goal here, though, is to provoke discussion and debate that could contribute to future improvements in the SPE-PRMS.

The survey asked the participants to indicate agreement, disagreement, or neutrality to a series of statements. Respondents’ answers were intended to provide insight into how clear the SPEPRMS is, how well understood it is, and respondents’ level of confidence in it.

Ideally, interpretation and implementation of the SPE-PRMS in estimating reserves/resources is independent of the reserve estimator. The first two survey statements endeavor to gauge the perception of consistency between reserve estimators in estimating conventional and unconventional reserves.
Q&A: Qatar's Oil and Gas R&D Push
Authors: Saleh Youssif
Published: February 2015

Youssif Saleh, general manager of Qatar Shell Research and Technology Centre in the Qatar Science and Technology Park, discusses the R&D strategy of the center and in Qatar.

What are the main drivers behind the decision to establish an R&D center in the Middle East?

We are pleased about the role that Qatar plays in Shell’s overall technology strategy through our world-class research and development program based at the Qatar Shell Research and Technology Centre (QSRTC). This makes QSRTC a member of Shell’s wider R&D community, which includes technology centers in cities such as Amsterdam and Houston. QSRTC’s mandate is to provide a home for research that adds value both to the state of Qatar, to Shell, and to our partners. Therefore, our work is focused on the development and implementation of technologies that support Qatar’s specific needs, as well as support Qatar’s role as the world’s largest liquefied natural gas exporter and the gas-to-liquids (GTL) capital of the world. Moreover, we work with many of Qatar’s universities and academic institutions abroad, and provide training in R&D to Qatari national staff as part of Shell’s support for Qatar’s journey toward a knowledge-based economy.

When was QSRTC established and on what specific areas of R&D does it focus its efforts?

We have been an anchor tenant at the Qatar Science and Technology Park (QSTP), a home for technology-based companies from around the world, since 2008 with a USD-100-million funding commitment over 10 years. That was also the year we became the first tenant of QSTP to file a patent based on research conducted in Qatar. The center’s current activities build upon Shell’s extensive experience in the GTL field and focuses specifically on catalyst testing, product development, and GTL byproduct research, including water treatment and reuse. Catalysts are a key focus area since they are essential to the process that converts natural gas into liquid fuels and other products at our Pearl GTL facility, the largest GTL plant in the world. Our researchers have also worked on developing new uses for sulfur, a coproduct of the GTL process, and are collaborating with scientists from around the world on improving the understanding of carbonate reservoirs.
Technology Focus: Offshore Drilling and Completion (April 2014)
Authors: Rylance Martin
Published: February 2015

Technology Focus

As the saying goes, “Necessity is the mother of invention.” And never were truer words spoken regarding the oil field and new frontiers. Indeed, as the industry significantly increases the number of work fronts in both the established and the new deepwater frontiers, ever-more-innovative approaches are being developed to address the challenges faced.

However, innovation in isolation is not sufficient. As we push the envelope of application, it is a necessity that the equipment and approaches being applied be fit for purpose, robust, and engineered. In support of this, while a model is a useful tool and plays a role as part of a development process, such complex engineering can best be implemented efficiently through obtaining actual performance data, which may then be used as a basis for improvement and expanded qualification.

Data play a key role in two distinct and principal areas of technology development: data that are obtained and used to demonstrate the initial qualification (surface) and in-situ performance (deployed) data that are used to calibrate simulations and models and to allow further efficiencies to be securely achieved.

As a technical advisor in hydraulic fracturing and unconventionals, I fully appreciate the plan/do/measure/learn cycle because this is fundamental to our overall efficiency. However, deepwater drilling and completion operations are quite different from those in unconventionals. With few wells and much higher costs, the statistical multiwell approaches taken onshore with unconventionals simply do not apply to deepwater efforts. While approximately 20,000 unconventional wells are drilled per year in North America, fewer than 200 deepwater wells have been drilled in the Gulf of Mexico to date. This makes each opportunity to gather data in deep water particularly valuable. And the key to maximizing industry efficiency will be to make sure that data gathering is part of our everyday business. Of course, this is best achieved by embedding the opportunities to gather such data within our standard practice. In this way, we improve incrementally.

The following papers provide just a small snapshot of the areas in which incremental improvements are being achieved, allowing the deepwater drilling and completions envelope to be pushed further. It is very likely that such data-driven innovation will continue to be the lifeblood of the business. JPT

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

OTC 24275 Real-Time Drilling-Data Diagnosis Implemented in Deepwater Wells—A Reality by R.A. Gandelman, Petrobras, et al.

OTC 24081 Concept Alternatives and Feasibility Analyses of Deepwater Dual-Gradient Drilling-Riser Systems by Atul Ganpatye, Stress Engineering Services, et al.

SPE 166554 Low Cycle Fatigue Analysis of Threaded Connectors for Subsea Drilling and Production by B. Zhu, GE Oil and Gas, et al.

SPE 166589 Structural Response Monitoring of Huntington HP Drilling and Completion Riser by A. Rimmer, 2H Offshore Engineering, et al.
Case Study: Foaming During Startup of Karan Nonassociated Gas
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 17175, ’Khursaniyah Gas-Plant Experience With Foaming During Startup of Karan Nonassociated Gas,’ by Mohammed Hussain Al-Qahtani, Saudi Aramco, and Paul Garland, INEOS, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission.

All amines are subject to foaming in industrial applications given certain conditions and circumstances. Methyl diethanolamine (MDEA) is like other types of amine that can experience major foaming upset, especially in high-pressure sweetening units. However, MDEA is one of the most popular solvents for gas treating, with several advantages over other amines, particularly its ability to remove hydrogen sulfide (H2S) and slip carbon dioxide (CO2) from sour gas. This paper describes Saudi Aramco’s efforts to eliminate early foaming incidents during the commissioning stage of the Karan nonassociated (NA) sour-gas field.

Introduction

The Karan field was discovered by Saudi Aramco in 2006. This newly developed offshore field is located 120 km northwest of Jubail Industrial City in eastern Saudi Arabia. Produced sour gas is coblended at a tie-in offshore platform through five 20-in. subsea flowlines. From the tie-in offshore platform, the gas is sent through a 38-in. subsea pipeline to the onshore gas-treatment facilities at the Khursaniyah Gas Plant. Karan facilities consist of three gas-treatment-processing trains, each designed to process 620 MMscf/D of NA sour gas, producing sales gas and acid gas.

Karan NA sour gas is a CO2-rich stream. Formulated MDEA was selected for sweetening in Karan gas-treating facilities to enhance the H2S / CO2 ratio in acid gas and to meet the required sales-gas specification before sending the gas to the Saudi Master Gas System.

The Problem of Foaming

Karan’s three gas-treating trains have a total rated capacity of 1.86 Bcf/D of sour feed gas. Each train consists of an MDEA-based acid-gas-removal (AGR) unit, a triethylene-glycol (TEG) dehydration unit, and an acid-removal (AGE) unit (Fig. 1). In addition, propane is used for process-stream cooling at various points throughout the process, where temperatures of less than 140°F are required. A dedicated propane-compression system runs continuously to cool each process train.
Modeling and Analysis of Salt-Cavern Natural-Gas Storage
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164489, ’Modeling and Analysis of Salt-Cavern Natural-Gas Storage,’ by P. Barajas and F. Civan, SPE, University of Oklahoma, prepared for the 2013 SPE Production and Operations Symposium, Oklahoma City, Oklahoma, USA, 23-26 March. The paper has been peer reviewed and published in the February 2014 SPE Production & Operations journal.

A rigorous modeling approach is developed for effective management and inventory analysis of natural-gas storage in underground salt caverns. Computational-fluid-dynamics and heat-transfer modeling approaches are implemented to simulate the strongly coupled fluid-mechanics and heat-transfer problems involving cavern gas storage. Accurate prediction of natural-gas storage performance and inventories made on the basis of the present comprehensive simulation approach can be instrumental in effective management and balancing of natural-gas supply and demand.

Introduction

Gas-storage caverns are typically developed through drilling of a wellbore to reach the salt formation and subsequently injecting and circulating hot water to dissolve and remove the salt and create a cavity intended for gas storage by a process known as solution mining. Gas-storage-cavern facilities consist of three subsystems: the wellbore that connects surface facilities with the cavern, the cavern itself, and the surrounding salt formation enclosing the cavern (Fig. 1). Accurate prediction of cavern-gas pressure is important for avoiding improper gas-storage-operation parameters and thus the fracturing and failure of the salt formation (and hence cavern-roof collapse, which can lead to catastrophic incidents where the stored gas migrates toward the ground surface and causes harm to field personnel and the nearby population or damage to surface facilities). On the other hand, loss of volume caused by creep closure can occur when the cavern-gas pressure drops below the minimum allowable cavern pressure. Effective management and inventory analyses of underground natural-gas storage are generally accomplished by modeling and simulation of the gas conditions in the storage media.

The increasing popularity of salt caverns is attributed to their flexibility to switch quickly from gas injection to gas production. The void space of the cavern does not cause pressure loss from flow restrictions in contrast to depleted reservoirs or aquifers. Ideally, stored gas cannot leak into the surrounding naturally fractured salt formation because of the essentially negligible porosity and permeability of the formation. Thickness of salt formations can vary typically from a few meters in salt beds to thousands of meters in salt domes.
Challenges in Testing and Completion of an HP/HT Reservoir in Kuwait
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 167647, ’Challenges in Testing and Completion of Highly Sour HP/HT Reservoirs in the State of Kuwait,’ by Y. Al-Salali, H. Al-Bader, V. Duggirala, M. Ayyavoo, P. Subban, A.R. Al-Ibrahim, and A. Rajkhowa, Kuwait Oil Company, prepared for the 2013 SPE Kuwait Oil and Gas Show and Conference, Mishref, Kuwait, 7-10 October. The paper has not been peer reviewed.

Recently, a new structure located in northwestern Kuwait was drilled and tested with a deep-drilling rig. Formations in this deep structure have very low porosity and permeability. During short-term testing, wells produced oil and gas with, unexpectedly, the highest hydrogen sulfide (H2S) content of any reservoir so far discovered in Kuwait. Because the reservoir was rated as high-pressure/ high-temperature (HP/HT) and sour, it was a challenge to test the wells safely and successfully.

Introduction

Jurassic carbonate reservoirs in Kuwait fields are deep, low-permeability, and HP/HT and generally contain sour volatile oil/condensate and gas. Formations containing these deep reservoirs are tight and naturally fractured carbonates. Najmah (NJ), Sargelu (SR), Upper Marrat, Middle Marrat, and Lower Marrat are the five formations proved to hold hydrocarbon- bearing reservoirs. NJ and SR formations are tighter than the three Marrat formations.

The NJ formation consists of limestone at the upper part and shale at the bottom. The SR formation consists mainly of shale and limestone. Both are naturally fractured reservoirs, so fractures play an important role in production. The Marrat formations consist mainly of limestone, occasionally with streaks of anhydrite at the top and with streaks of shale at the bottom. The core analysis of the Middle Marrat formation shows that dolomitization plays a major role for matrix-porosity enhancement, which is responsible for good reservoir character.

As part of an exploration strategy, a new structure in northwestern Kuwait was drilled to deep Jurassic formations. This new structure is a northwest/southeast- trending doubly plunging anticline and is intersected by a number of longitudinal- and transverse-fault sets. Earlier, a significant discovery of light oil and gas from the new deeper structure was made from an unsuccessful Paleozoic well through re-entry. After the discovery of light oil and gas, three more exploration/delineation wells were drilled to confirm the reserves potential of this structure. Some of the wells are located near the crest of the structure, whereas some are 1.5 km from the crest (Fig. 1).
Harvesting Oil in India's Rajasthan Desert
Authors: Kulkarni Pramod
Published: February 2015

The Thar Desert in India’s western state of Rajasthan is a desolate region characterized by wind-blown sand dunes. The state is a major tourist attraction, drawing millions of visitors annually to tour forts of medieval kingdoms and visit camel fairs. It is here that Cairn Energy, a Scottish oil company, took over a production-sharing contract (PSC) from Shell in 2003 and developed a major oilfield that has recoverable reserves of at least 1 billion BOE.

The major oil companies have conducted little wildcat exploration in South Asia. From 1980 to 1991, the majors drilled 8,000 wells in Southeast Asia, but only 12 in South Asia. Indigenous exploration in Rajasthan began with an inconclusive exploration attempt by the government of India in 1955. In 1988, Oil India discovered natural gas near the town of Jaisalmer and has been producing 0.6 million sd m3/d since 1996.

Floated on the London Stock Exchange in 1988, Cairn Energy first entered South Asia by signing a PSC with the government of Bangladesh. In 1997, during a swap of properties with Shell, Cairn acquired a 10% interest in the Rajasthan PSC, which Shell had initially signed with the government of India in 1995. The PSC covered block RJ-ON-90/1 consisting of an initial area of almost 12 000 km2—3111 km2 is now included in the development area, with India’s public sector oil company, Oil and Natural Gas Corporation, holding 30% ownership.  After the discovery of the Guda field in 1999, Cairn increased its participation to 50% and eventually took over Shell’s remaining share in 2003 at a cost of USD 7.25 million and became the block’s operator.

“Drill Till You Drop” Strategy

The geology of the block in Rajasthan’s Barmer basin consists of channel sands stacked on top of one another to create a fluvial reservoir that has high permeability (1–25 darcy) and high porosity. From 2004, Cairn adopted a “drill till you drop” strategy. In January 2004, the company made its initial Mangala discovery with the 16th well in the basin. Following the drilling of appraisal wells, 3D-seismic-data analysis, and well tests, Mangala was confirmed as the largest oil discovery in India since 1985. The Mangala reservoir has a 150 m oil column of medium gravity (20–28°API) viscous crude (9–17 cp) with sulfur content of about 0.1%. The crude has high paraffin content that makes it suitable as a secondary feedstock for refineries, but pipelines and trucks carrying the crude require heating and insulation. Up to 2005, the company drilled more than 140 wells in Rajasthan with a yield of 25 discoveries. In addition to Mangala, Cairn’s major discoveries are Bhagyam and Aishwariya, with 22 other fields including Guda, Saraswati, Raageshwari, Greater Raageshwari, and Kameshwari. In August 2009, the Prime Minister of India, Manmohan Singh, joined Cairn Energy Chief Executive Bill Gammell in inaugurating oil production from the Mangala field.
An Industry Upturn with a Downside: Talent Needs Still Loom Large
Authors: McCormack Greg
Published: February 2015

Talent & Technology

The oil and gas industry faces many challenging issues, now and in the future. Most industry participants are acutely aware of what they are. The knowledge gap created by “The Great Crew Change” that exists in most companies has been well documented and discussed. The problem is not one of filling the gaps. There are sufficient numbers of people entering the workforce to do that. The problem is one of “experience attrition,” and it is a challenge that must be addressed (Fig. 1).

The characteristics and expectations of “generation Y” or the “new millennials” have been examined and debated. The real issues at hand are the growing multigenerational aspects of the workforce with its mix of four distinct generations with disparate life experiences, varying ways of communicating, and distinctly different goals for their professional careers. The first of the baby boomers reached age 60 in 2008. In perspective, the average age for retirement in the oil and gas industry is 59. Along with the recent global economic slow-down has been a rise in the average retirement age. These three impacts—boomers, industry retirees, and economic changes—are all interrelated and impacted by the cyclical nature of the oil and gas industry.

This cyclicality is our industry’s hurdle in trying to resolve issues surrounding the employment of top talent going forward. Cyclicality is also the area over which the industry has least control. It is inevitable that the industry will be cyclical because it is based, quite simply, on supply and demand.

Why is cyclicality so important? The answer becomes clear from the perspective of career time spans and talent management. Most employees in the oil and gas industry are responsible for developing a career spanning an average of 35 to 40 years. During the last 40-year time span, there have been seven business cycles. Driven by Wall Street and shareholder interests, the industry has always reacted to these cycles by reducing fixed costs as they would in any downturn in the economy. However, the main element of fixed costs is employee expense. So if the oil and gas industry is driven by quarterly earnings, as are many other industries, then it will respond by driving down fixed costs and therefore, employee costs.
Techbits: SPE Summit Addresses Hydraulic Fracturing Issues
Authors: Veil John
Published: February 2015

Techbits

The first SPE Technical Summit, titled “Hydraulic Fracturing: Ensuring Groundwater Protection,” was held in conjunction with the SPE Hydraulic Fracturing Technology Conference in the Woodlands, Texas, in January. About 80 people representing industry producers and service companies, consulting firms, academia, national laboratories, state and federal government, and national governmental organizations (NGOs) participated.

The discussion focused on the impact of fracturing on groundwater. The summit began with a keynote presentation by a state regulatory official on how state oil and gas agencies are evaluating and regulating hydraulic fracturing. Organized into four 90-minute sessions, each session had two or three short presentations by experts who provided information and stimulated discussion. The themes were:

What is hydraulic fracturing?

What are the issues?

Environmental risks and issues—facts vs. perception

How to move forward?

State Regulations

US states have the lead role in regulating most oil and gas activities, including hydraulic fracturing. Among the approximately 30 oil- and gas-producing states, there is a range of requirements and levels of detail regarding the type of hydraulic fracturing information that must be reported to the agencies.

One presentation introduced the collaborative efforts of a nonprofit, multi-stakeholder group known as the State Review of Oil and Natural Gas Environmental Regulations (STRONGER) that provides critical reviews of state oil and gas programs and offers suggestions for improvement. Teams made up of members from states, industry, NGOs, and others periodically conduct detailed reviews of state oil and gas regulatory programs. The group developed guidelines for hydraulic fracturing in January 2010. They set forth general principles such as:

Wells should be properly designed and constructed.

Water, wastewater, and waste management should be planned and conducted in a careful manner.

Information on the chemicals used in hydraulic fracturing operations should be disclosed and reported.

Focused reviews of state hydraulic fracturing requirements have been conducted in Pennsylvania and Ohio, and reviews of Oklahoma and Louisiana requirements are in progress. STRONGER also is an advocate for sufficient funding and training of state agency staff in order to provide a better oversight of oil and gas activities.

What is Hydraulic Fracturing?

This session discussed the history of hydraulic fracturing and its impact on the oil and natural gas industry both past and future. It laid out the foundation of horizontal wellbore construction and described the principles of hydraulic fracturing and its integral role in recovering natural gas.

The first use of the combination of horizontal drilling and hydraulic fracturing began in 1985 in the Austin Chalk in Texas. These efforts showed good results and were soon transferred to the Barnett Shale and later to other shale formations.
Digital Rocks Out to Become a Core Technology
Authors: Rassenfoss Stephen
Published: February 2015

The future of oil and gas exploration depends on rocks such as carbonates and shale that can be described as tight, complex, nearly impermeable, and even stubborn. On the production side, the goal has long been to get more of the oil out of the ground, but recovery percentages have hardly budged.

The search to better understand the inner workings of these rocks that challenge traditional laboratory testing has led to a new approach known as digital rock physics. It is a technological hybrid drawing on fields ranging from medical testing to microchip production. By marrying computerized tomography (CT) and other X-ray scanning technologies, pioneers in this emerging field are creating 3D images showing the internal structure—including pore spaces and how they connect—as well as the minerals and organic matter within.

Digital rock physics providers promise faster, better, lower-cost analysis. The potential payoffs could include wells targeting the most productive rock, more effective well completions, and simulations speeding the development of enhanced oil recovery (EOR) techniques.

The graphics are stunning. The attention to detail is exacting. But using imaging to directly measure reservoir properties is still a work in progress. Getting a clear look at the smallest details in some rocks requires scanning samples that are measured in microns. Finding ways to accurately scale up this data to provide telling details about a formation will define the future of this young business.

The oldest of the three fast-growing companies selling digital rock physics services for exploration and production (E&P) goes back four years. Even the name “digital rock physics” is not set in stone. The growth in demand is in difficult formations such as shale and carbonates, and for simulating EOR projects that are hard to analyze using traditional means. Chevron, Shell, Statoil and Schlumberger are among the users.

At Chevron Energy Technology Company, the digital rock work is led by Jairam Kamath, who organized a SPE forum to consider the future use of this technology. “The more you work with it, the more you are convinced,” he said. “It took me a couple years, but I am convinced this is how we will be doing business five or 10 years from now.”

Shell is working with Schlumberger on a digital rocks project. It is one of many research projects at Shell seeking new ways to increase the output from aging fields. “I do believe there are large opportunities” there, said Gerald Schotman, chief technology officer of Shell. He described it as a way to deal with anomalies, when indicators such as the production history are out of line with predictions by the reservoir model.
Building for a Strong Future
Authors: Parshall Joel
Published: February 2015

For the offshore heavy lift vessel industry, the market re-mains very challenging with a return to robust conditions likely to wait several years. Reflecting the lag in the way multiyear project activity responds to changes in the economy, it wasn’t until late 2009 that the sector’s utilization rate began to plummet. From a 70% rate in August 2009, as calculated by market research firm ODS-Petro-data, utilization sank to 46% by December and 37% by January 2010, edging up only to 42% by the end of the first quarter. With the delay or cancellation of several new vessel projects, as utilization tumbled, excess supply began to dwindle. Utilization stabilized and even pushed above 72% in August, before settling at 56% for the year—hardly a brisk pace but at least well off the early-year lows. While newbuild vessel activity did not disappear and continues this year, there have also been additional project delays and cancellations, according to Mark Rae, senior market analyst at ODS-Petrodata.       

“I think the industry is going to start to see an uptick in 2013, where heavy lift contractors are indicating that operator interest is increasing,” said Keith Smith, enterprise category manager for offshore installation and heavy lift at Shell International E&P. “Even with the newbuilds coming on, there appears to be a growing demand.”

A major question remains on how soon field development activity in the US Gulf of Mexico (GOM) will return to levels comparable to those seen before the Deepwater Horizon disaster. The effect of the US drilling moratorium, now lifted, was to displace vessels to other global markets. Some of those markets were already beginning to tighten, according to Smith. When GOM activity picks up again, he predicts “there will be a pull on resources.”

Bruce Gresham, vice president for North America at Heerema Marine Contractors US, said the utilization rate in the upper tier of the heavy lift market where his company operates “is still healthy, although we have gaps.” Looking at the GOM, he said, “This situation on drilling permits, or lack of drilling permits, without a doubt is going to have an impact on a steady stream of projects going forward. Whereas 2013 looks to be a busy year for us here in the Gulf with some major facility installations, the moratorium on drilling will cause some projects that would have otherwise been executed in 2014 to slip back a year. But the opportunities are there, certainly plenty of prospects in deep and ultradeep water that will create a significant amount of work in the future. We have a bump in the road right now.”