bluuebunny/crossref_metadata_2025_split huggingface dataset:
Managing an Export Manifold To Ensure Gas Deliverability
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 14425, ’Managing an Export Manifold To Ensure Gas Deliverability,’ by A. Priambudi, R.N. Baraba, N.W. Tranggono, and B. Aryanto, Vico Indonesia, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, rescheduled to 7-9 February 2012. The paper has not been peer reviewed.
The Badak Export Manifold (BEM) is a complex system for gathering all gas delivered from upstream fields and for delivering hydrocarbons to a liquefied-natural-gas (LNG) plant and to commercial sites for the manufacturing of fertilizers and chemicals. The export manifold must maintain pressure, distribute gas flow, implement offtake logic during shutdown, and coordinate gas delivery. Much effort has been invested to improve export-manifold operations. Now, almost all of the BEM parameters can be monitored remotely to support better operation.
Introduction
Vico Indonesia produces approximately 405 MMscf/D of natural gas and 18,000 B/D of oil and condensate from four fields. The company also coordinates gas production, is pipeline custodian for all producers in East Kalimantan, and is responsible for delivering approximately 2.9 Bscf/D of natural gas gathered from many fields.
The company maintains, operates, and inspects more than 1000 km of pipelines, with a diameter range of 3 to 42 in. The East Kalimantan pipeline net-work is designed to transfer hydrocarbons from outlying processing facilities to the Bontang LNG facility and to other commercial sites in the Kaltim Industrial Estate (KIE).
The BEM (Fig. 1) is the beginning of two 36-in.- and two 42-in.-diameter pipelines that work in parallel toward Bontang. The BEM enables flexibility of gas delivery and maintains gas composition within acceptable specification. The pressure stability and gas specification are the most important aspects of the export-manifold operations. These operations become challenging with changing upstream-field conditions. When the pressure is decreased, the gas composition becomes richer and the gas sup-ply is reduced to a level that is less than the demand for gas and less than pipeline capacity. A quick decision and field action are required immediately to avoid LNG-plant shutdown and gas composition getting out of specification.
In addition to gas composition becoming richer, the pipelines cross hilly terrain that causes liquid holdup (LHU) in the pipelines. The LHU increases the backpressure on the upstream field, which, in turn, restricts natural-gas flow to the plant. Despite the supply flexibility, parallel operation of the pipelines makes the gas tend to flow to the line with less backpressure. The BEM attempts to sweep liquid in the parallel mode by segregating gas flow into a particular pipeline.
Sustainable Development With First CDM Project in Thailand
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146681, ’Sustainable Development With First CDM Project in Thailand E&P,’ by Chiratthakan Getwech and Lawan Pornsakulsakdi, PTT Exploration and Production plc, prepared for the 2011 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 20-22 September. The paper has not been peer reviewed.
A clean-development-mechanism (CDM) project takes aim at recovering and then using associated gas from the oil wells of Sao Thian-A field in Sukhothai Province, Thailand. Without a CDM project, this associated gas would continue to be flared. The CDM project involved the installation of a gas-treatment system to filter out hydrocarbon droplets from the associated gas before its internal use and sale to an external facility.
Introduction
The CDM project is one of three flexible mechanisms that allow Annex-I Parties* to implement projects that reduce emissions or increase removals by sinks in the territories of non-Annex-I Parties. The carbon credits generated by CDM projects are “certified emission reductions” (CERs) that can be claimed by the project investor. Thailand is classified as a non-Annex-I Party and is not obligated to meet any emission-reduction targets. Instead, Thailand is eligible to participate in the CDM project as a host country, and possibly attract environmentally friendly investment from governments and businesses of developed countries.
Sustainable development is a pattern of resource use aiming to meet human needs while preserving the environment so that such needs can be fulfilled now and in the future. There is interdependence among the three concepts of sustainability: environment, economics, and socio-culture. On the basis of this approach, sustainable development can occur only where the environment, the economy, and the social needs meet.
The Thailand Greenhouse Gas Management Organization (a public organization), or TGO, is an autonomous governmental organization with the specific purpose of reducing greenhouse-gas emission, reviewing CDM projects for approval, and performing its role as the Designated National CDM Authority in Thailand. CDM-project development in Thailand must function in accordance with TGO guidelines, as well as with its sustainable-development criteria.
*According to the United Nations Framework Convention on Climate Change, countries are divided into two main groups: those that are listed in the Annex I, known as Annex-I Parties, and those that are not, known as non-Annex-I Parties. The Annex-I Parties are industrialized countries that are obligated to respond to climate change by lowering their greenhouse-gas emissions to an average of approximately 5.2% below their 1990 levels over the 2008–2012 period.
Successful Discovery of Light Oil From an Unsuccessful Well Through Re-Entry
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 147247, ’Successful Discovery of Light Oil From an Unsuccessful Paleozoic Well Through Re-Entry - A Case Study of an HP/HT Well,’ by Haifa Al-Bader, SPE, Yousef Zaid Al-Salali, SPE, Vidya Sagar Duggirala, SPE, A. Manimaran, and S. Packirisamy, SPE, KOC, prepared for the SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November 2011. The paper has not been peer reviewed.
An exploratory well, the second deepest in Kuwait, had been drilled in the Mutriba field to 22,094 ft. Two formations, Kra-Almaru and Khuff, were perforated and tested. The tests revealed the presence of sparse gas, and it was decided to test and complete this well in the Jurassic formation through re-entry. The re-entry in this ultradeep well was full of challenges; however, by overcoming all the challenges, this well was successfully perforated, stimulated, and tested, which led to the first commercial discovery of oil and gas within the Jurassic reservoir in the Mutriba field.
Introduction
Two zones in Paleozoic and Triassic sections were perforated and tested separately to evaluate the presence of hydrocarbon between 18,500 and 21,500 ft. The well was completed in 2004. After undesirable results were obtained from the Triassic and Paleozoic formations, exploration teams studied the feasibility of testing Jurassic formations in this well through re-entry. Testing Jurassic formations in the Mutriba field from an existing well will be more economical than drilling a new well. A snubbing unit was deployed in 2008. In 2009, a suitable workover rig was deployed to test Jurassic formations in this previously drilled well. The location of the Mutriba field is shown in Fig. 1.
A snubbing unit had been used to isolate the open perforations of the Triassic zone with cement. Subsequently, a workover rig was deployed to test the prospect of a Jurassic reservoir. Testing the Jurassic reservoir behind two heavy-walled casings (7 in. 46.4 lbm/ft and 8⅝ in. 40 lbm/ft) combined with extreme sour and high-pressure/high-temperature (HP/HT) conditions warranted high health, safety, environment, and technical precautions.
Challenges for re-entry to this well included HP/HT conditions, a high surface pressure, and well-killing issues. Testing of the formation fluid revealed the presence of an unexpectedly high concentration of H2S (20%) and CO2 (2%), which presented challenges for coiled-tubing (CT) operations, stimulation, flowing the well, and fluid disposal.
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.