bluuebunny/crossref_metadata_2025_split huggingface dataset:
Feed-Gas Treatment Design for the Pearl GTL Project
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 10682, "Sustained Development in the Pearl GTL Treating Design," by H. Grootjans, Shell Global Solutions Intl. B.V., prepared for the 2005 International Petroleum Technology Conference, Doha, Qatar, 21–23 November.
Feed gas for Shell's gas-to-liquids (GTL) project in Qatar must be treated to meet the stringent contaminant specifications for a modern GTL process. This gas that contains hydrogen sulfide (H2S), carbon dioxide (CO2), several mercaptan species, and carbonyl sulfide (COS) requires a series of treatment processes. These processes must be selected and integrated to provide a cost-effective treating complex that removes contaminants in an environmentally friendly way. The full-length paper details the process selection method, indicating the process options available and the environmental benefits achieved.

Introduction
The Pearl GTL project in Ras Laffan, Qatar, will consist of two trains that together will produce 140,000 B/D of middle distillates and base oils from natural gas using Shell GTL technology. In addition, the plant will produce significant quantities of condensate and liquefied petroleum gas (LPG). Startup of the project is targeted for late 2009.
Feed gas is supplied from the North field. Before this sour feed gas can be processed in the downstream GTL units, it must be treated for deep contaminant removal to meet stringent specifications. Gas produced from the North field contains a range of sulfur components, such as H2S, COS, and several mercaptan species. The gas also contains CO2 and traces of mercury. Deep removal of all sulfur-containing components will be required as well as full removal of mercury. CO2 must be partly removed, and the gas will need to be dried to avoid freezing in the ethane- and LPG-extraction units. Because of the wide range of contaminants and deep level of removal required, it is not possible to treat the feed gas in a single unit. Fig. 1 shows an overall block scheme of the treating units.

Process Selection
For optimal treating-complex design, process selection for the individual units must be made on the basis of an integrated approach that considers interactions between units. Optimal process determination must consider the following.CO2 and sulfur dioxide emissions.Treating-unit operability over a range of feed gases.Treating-unit capital cost.Operating costs.
The full-length paper details the background of two key-process selection decisions. The selection of these two processes was done in parallel to account for interactions between the two processes.
Guest Editorial: SPE Meetings Provide Value at Affordable Price
Authors: Rubin Mark 
Published: February 2015

SPE has expanded the number of technical meetings it offers to around 90 workshops, conferences, and forums each year in locations around the globe. These meetings are critical to achieving our mission of technical-knowledge exchange that will advance the industry.
We have grown the number of workshops and conferences aggressively to meet our members' needs better by addressing more topics, and by organizing meetings in underserved geographic regions. Our goal is to provide our members with consistently high-quality content on a range of topics of interest, and to make more opportunities available in the regions where our members are located.
I occasionally receive feedback from members expressing concern that it costs too much to attend an SPE meeting. We recognize that attending an SPE meeting can be a stretch financially for some members, including those who are without a large company budget to support their attendance. Even with the dramatic expansion of our meeting schedule, SPE strives to keep meeting fees reasonable, while operating in a businesslike and fiscally responsible manner. Providing more services at a reasonable cost can be a difficult balance to achieve.
For most SPE meetings, fees are set to ensure that the event achieves financial breakeven or provides a small surplus. We are able to keep our fees low in comparison to commercial meetings because of the partnership between members and staff that exists for every meeting we organize. Members plan the technical sessions, which provides the best possible source of information about topics of interest to the industry. SPE's professional meeting planners arrange for the meeting locations and logistics and assist our program committees. These staff costs, as well as other costs such as the venue and meals, must be covered by meeting fees. Everyone pays to attend an SPE meeting—even the program committee members and authors.
Company sponsorships help defray some meeting costs, and SPE is very appreciative of the strong industry support our meetings receive. Exhibitions at the larger conferences provide significant revenues that offset the cost of the meeting.
When compared to industry meetings sponsored by commercial organizers, our fees are significantly lower. Commercial event organizers typically charge two to three times as much as SPE for comparable events. For example, SPE holds a number of workshops in North America with fees of USD 700 to 800; similar meetings held by commercial organizers cost USD 2,000 or more. In Malaysia, a commercial organizer's recent 2-day reserves-valuation conference cost USD 1,866 just to attend the event. SPE's 3-day reserves-valuation workshop, which also included three nights' accommodations and all meals, cost USD 1,950.
Air Drilling in the Presence of Hydrocarbons: A Time for Pause
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 108357, "Air Drilling in the Presence of Hydrocarbons: A Time for Pause," by K.P. Malloy, SPE, Stress Engineering Services, and G.H. Medley, SPE, and C.R. Stone, SPE, Signa Engineering, prepared for the 2007 IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Galveston, Texas, 28–29 March.
Drilling with compressed air continues to enjoy great popularity and is often the application of choice in dry, hard rock because the drilling-fluid medium is inexpensive and respectable rates of penetration can be achieved. In terms of economic considerations with respect to drilling-fluid expenditures, air drilling has virtually no equal. However, air drilling is not without its drawbacks, not the least of which is its reactivity with hydrocarbons.

Introduction
Historical Perspective. The first recorded use of compressed air in drilling was in the early 1860s when a piston-type compressed-air mechanical drill bit bored the 8-mile-long Mount Cenis Tunnel in the Alps. In the late 1940s and early 1950s, air drilling became a popular departure from standard rotary-drilling operations.
Safety Considerations. Drilling with compressed air provides many benefits, but misapplication of this technology has led to losses that include both downhole and surface equipment. More seriously, the most devastating of these losses are injuries to rig personnel.
For too long, some operators, drilling contractors, and rig and service personnel have been under the mistaken impression that air drilling is somehow an inherently safer operation than conventional drilling over a broad range of applications. While that can be true, the basic chemical concept of the classical combustion triangle (Fig. 1) often has been ignored or forgotten. Fire is an oxidative process, and combustion can occur only when the three legs of the combustion triangle are present.
Classical studies performed jointly in the 1920s by the US Department of Interior, Bureau of Mines, and the Safety in Mines Research Board of Great Britain describe the hazards of working in an oxygen-rich environment in the presence of hydrocarbons. As long as hydrocarbons are not present, air drilling can be just as safe as drilling with nonreactive fluids common to drilling operations, such as water and water-based, oil-based, or synthetic-based mud.

Chemistry
Air is a mixture of many gases with approximately 21 vol% oxygen. The minimum oxygen concentration needed for combustion of methane (CH4) is only 12 vol% at sea level (Fig. 2).
The primary constituent of natural gas is CH4. In the presence of an ignition source and sufficient oxygen, complete combustion of hydrocarbons occurs to create carbon dioxide (CO2), water, and heat. When there is too much fuel (CH4) or insufficient oxygen, the chemical reaction cannot oxidize the hydrocarbons completely to CO2 and water. The reaction yields carbon black, commonly known as soot, as a solid carbon product along with water and heat.
Techbits: Hydraulic Fracturing's Progress Reviewed in Workshop
Authors: JPT staff _ 
Published: February 2015

Techbits
Approximately 110 professionals converged on Cartagena, Colombia from 11 to 13 August for SPE's Applied Technology Workshop (ATW) titled "Hydraulic Fracturing in the Americas." The international audience, representing the US, Canada, Mexico, Argentina, Venezuela, Brazil, Colombia, Romania, and Indonesia, shared the latest information on how hydraulic fracturing has been applied to improve hydrocarbon recovery during various stages of field life.
Two full days of discussion included 21 high-level fracturing topics divided into six subtopics, including high-permeability and low-permeability fracturing, unconventional reservoirs and horizontal well fracturing, fracture design and diagnostics, and advances in fluids and proppants.
The ATW's first session on high-permeability fracturing featured discussions by representatives of Schlumberger, Halliburton, and Ecopetrol-ICP. Highlights of the session included an explanation of how the microannulus between cement and rock favor fracture initiation and propagation, and that a wide propped width is required to provide high fracture conductivity and offset embedment. The leakoff areas above and below a perforated interval help contain fracture height growth and facilitate tip screen out and it is important to consider the cool down temperature profile for proper design of fracturing fluids. Packerless multistage CT fracturing in Argentina using hydra-jet technology is performing well in high-permeability formations and in tight gas sands. Frac design in Colombia includes a procedure for selecting candidates considering reservoir and geomechanical data. Also, organic preflushes have shown excellent results when performed prior to main frac treatment.
The second session on low-permeability fracturing considered experiences in the East Kalimantan in Indonesia and the Burgos Basin of Mexico. At East Kalimantan, poroelastic hysteresis is severe, and special considerations need to be taken in fracturing these poroelastic sensitive formations. The main considerations are to follow a rigorous planning schedule and demand high-quality services for fracturing operations. Also, an analysis of the history of fracturing in the area is a must before designing new fracturing jobs.
Use of microemulsion technologies has showed good results in the Burgos Basin. Another parameter for success includes getting proper values for rock permeability, closure pressure, and rock mechanical properties from minifrac tests. Flowback tests using chemical tracers showed that the recovery of fracturing fluids after a treatment is in the range of 5–20% of the total injected fluids.
In a session discussing the fracturing of unconventional reservoirs, experiences from the Barnett Shale were presented. The speakers recommended accounting for the shale's network of natural fractures, and considering a switch to clean fluids when encountering high pressure due to the large increase of sand concentration near the mouth of the fracture. A return of more than 30% of water is a bad sign for the fracturing job.
Overcoming Weight-Transfer Challenges in Complex, Shallow, Extended-Reach Wells on Alaska's North Slope
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19550, "Overcoming Weight- Transfer Challenges in Complex, Shallow, Extended-Reach Wells on Alaska's North Slope," by Randy Thomas, SPE, Dennis Hartwig, and Steve McKeever, SPE, ConocoPhillips Alaska; Dave Egedahl, SPE, ASRC Energy Services E&P Technology; John Patton and Keith Holtzman, Halliburton-Sperry Drilling Services; and Lee Smith, Halliburton-Security DBS/ Alaskan Energy Resources, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.
The complex wells constructed to develop the West Sak field on the North Slope of Alaska are approaching the limits of extended-reach-drilling technology. With the shallow vertical depth and long horizontal departure of these wells, transferring weight effectively while drilling and running tubulars can be very challenging. These challenges and the tools, techniques, and learnings used over the past 7 years to solve weight-transfer challenges in this remote environmentally sensitive area are discussed.

Introduction
The The West Sak field is part of the Kuparuk River Unit on the North Slope of Alaska (Fig. 1). The West Sak heavy-oil sands contain highly viscous, low-API-gravity crude (10 to 22°API) at low reservoir temperatures [result of the extreme northern latitude and the shallow (3,000 to 4,000 ft) burial depth below 1,800 ft of permafrost in the overburden]. The reservoir has three primary sandstone targets, which are very-fine- to fine-grained single and amalgamated sandstone/siltstone beds. Geologic challenges while drilling include numerous fault crossings along the wellbore and random encounters with calcite-cemented spheroids, also known as concretions (Fig. 2). The concretions are much harder than the reservoir sand, having compressive strength of 25,000 psi vs. 500 psi for the reservoir sand. These concretions drill much more slowly than the adjacent sand, which accelerates wear on the bit, the bottomhole assembly, and the drillstring. This difference in hardness can cause the drill bit to deflect off the concretions, resulting in severe unwanted doglegs. Such doglegs make it difficult to maintain directional control, often increasing torque and drag, and can cause downhole-tool damage.

West Sak Well Design
The primary constraints on West Sak well design are as follows.The shallow vertical depth of the reservoir sands.The need for lateral azimuths to be only to the north or south (parallel to the natural faults)The need for precise lateral placements because of spacing requirements of the waterflood depletion planThe need to drill the laterals in-zone by use of real-time geosteeringThe need to avoid collisions with nearby wells drilled from the same gravel pad
Kitina Case: Mature-Field Rejuvenation with Long-Reach Wells and Massive Hydraulic Fracturing
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19455, "Mature Offshore Field Rejuvenation via Long-Reach Wells and Massive Hydraulic Fracturing: The Kitina Case History," by F. Okassa, SPE, L. Tealdi, D. Baldini, A. Casero, H. Malonga, D. Isella, A. Baioni, L. Riccobon, G. Obondoko, F. Itoua Konga, F. Pounga, and M. Rampoldi, SPE, Eni Congo, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.
Many West Africa offshore fields are maturing, and operators are completing secondary targets to maintain economical operation. However, the level of capital expenditure for interventions is critical. In the Kitina field, offshore Pointe Noire, Congo, deeper sands have been produced to economic depletion and reservoir studies indicated alternative production intervals. Reservoir modeling; operation geology; and drilling, completion, and production challenges encountered in the 2007 Kitina rejuvenation campaign are described.

Introduction
The Kitina field, discovered in 1991, has five reservoirs.3A—limestone and sandstone with silty clay2A—limestone: oolitic grainstone/packstone, bioclastic with good intergranular porosity and intercalation of sandstone with carbonate cement2A—south accumulation: oolitic grainstone/packstone, bioclastic with good intergranular porosity and intercalation of sandstone with carbonate cement1A—sandstone with carbonate cement and limestone1B—sandstone with carbonate cement and limestone
Three reservoirs (2A, 1A, and 1B) were depleted with a peripheral water-injection scheme and crestal gas injection. The initial production rate of the field was approximately 50,000 BOPD (1997), declining over a 10-year period to 7,000 BOPD. As the field depleted, some wells were put on artificial lift, initially with electrical submersible pumps and currently with gas lift. The recovery factors have been estimated at 15% for Reservoir 1B and between 25 and 30% for Reservoirs 1A and 2A. To initiate rejuvenation of the fields, it was decided to perform a full review of field potentials, which led to the following decisions.Optimize the recovery from Reservoir 3A (previously considered as marginal because of low permeability and the low production rates of the three wells already completed) by use of a massive hydraulic-fracturing campaign.Drill a long-reach and ultradeep well (KTM-SM5) in the south field structure into the Reservoir-2A south accumulation.

Reservoir 3A
Potential production from Reservoir 3A was studied by correlating with a similar sequence in another field, the Sounda marine field, 8 km east of Kitina. The formation permeability to oil ranges from 2 to 7 md. Three wells have been completed in this reservoir. Each well was produced as natural flow, but was completed with gas lift mandrels to accelerate well cleanup. Reservoir-3A production potential, from those three wells, was approximately 800 BOPD.
Manganese Tetraoxide Weighted Invert Emulsions as Completion Fluids
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112313, "Manganese-Tetraoxide-Weighted Invert Emulsions as Completion Fluids," by L.P. Moroni, SPE, J.R. Fraser, and R. Somerset, Baker Hughes; A. Jones, Oilexco North Sea; and A. Guarneri, Eni AGIP SpA, originally prepared for the 2008 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 13-15 February. The paper has not been peer reviewed.
Traditionally, completion equipment is run in clear fluids, brines, or base oils to minimize the potential for solids to plug equipment. Base oils typically have approximately 0.8 specific gravity (SG), which has well-control implications, and brines can be prohibitively expensive where high densities are required. A novel approach was used by a UK operator to address these problems by compromising between the shale stability provided by oil and the density achievable with brine.

Introduction
Once the drilling phase is complete, most operators clean up the well before running the completion string. With non-aqueous fluids (NAFs), cleanup can be quite complicated, requiring a sequence of surfactant pills to remove mud residue from the wellbore and casing. The objective is to leave the well with a clean fluid that has very-low solids content (typically less than 0.05%) or meets a clarity specification. This process can result in large volumes of fluid that are considered to be contaminated to the point of requiring disposal. Where an NAF is used, environmental limitations usually require the contaminated fluid to be contained for special disposal.
Manganese tetraoxide (Mn3O4) has been used as an alternative weighting agent in both water-based and nonaqueous drilling fluids where equivalent circulating density and sag performance have precluded use of barite-weighted fluids. The combination of small particle size, spherical shape (Fig. 1), and high SG (4.8 g/cm3) makes Mn3O4an ideal weighting agent for fluids in which a low viscosity profile and low gel strength are required.
Case History 1
A temporary completion fluid with 1.95 SG was required while running the completion string to provide a secondary well-control barrier in addition to the cemented liner while the blowout-preventer (BOP) stack was replaced with the Christmas tree. Use of cesium formate was one alternative explored by the operator, but the cost was considered prohibitively high. A previous application that used a water-based mud containing ultrafine barite failed on three issues: The fluid was prone to barite sag, the fluid left a coating on tubulars that was virtually impossible to remove, and the fine barite particles plugged surface well-test-line valves. One of the major concerns was the tight clearance (0.1 in.) of the hydraulically set packer and the risk of setting prematurely because of pressure surges while displacing to the oil-based packer fluid. The wellbore geometry consists of a long tangent between 40 and 50º, so sag prevention is a key requirement.
Technology Focus: Gas Production Technology (November 2008)
Authors: Wilson Scott J. 
Published: February 2015

Technology Focus
One trend that Stephen Norris noted in his Unconventional Recovery editorial (JPT, July 2008, page 74) is that resources that have been on someone's back burner for 17 years (in the case of the Barnett shale) have finally started to have their day in the sun.
What has changed? Did a new technology suddenly change all the drivers? Did incremental adjustments in existing technologies, or cross pollination from other disciplines, or an excess supply of technical talent make the difference? How about the value of the underlying product? Until approximately 10 years ago, gas was viewed in many parts of the world as a waste product and was flared. Now, worldwide natural-gas prices make it possible to go to extraordinary efforts to bring gas to market.
Classic economic theory predicts that as prices increase, high technology and high-cost supplies will, eventually, join the market, and as long as they do not overwhelm it, will become a long-term source and drive the price back to equilibrium. This new price is high enough to provide a profit to these new producers but low enough to maintain demand. Just as a receding tide can expose a shipwreck holding treasure, a stable higher price renders many difficult gas-production and -transportation methods worthwhile.
How is possible to develop 13,000-ft gas wells on 10-acre spacing? If the target zone is 3,500 ft thick and needs 12 separate fracture treatments, the lack of areal extent is offset by huge vertical extent. But how will the well perform with some zones continuous and others not? Consider the Barnett shale: "The largest gas field in Texas," where the average well is less than 4 years old and water production in the noncore area typically necessitates artificial lift. The Haynesville and Marcellus shales are expected to be equally impressive, even though these tight formations were identified long before drill bits turned to the right. Extensively developed in the US and Australia, coalbed methane still is viewed as "unconventional" in most of the world.
For all of you with a 17-year science project waiting for a lucky break, remember that luck happens when opportunity meets preparation, and opportunity is knocking….
Gas Production Technology additional reading available at the SPE eLibrary: www.spe.org
IPTC 11307 • "Subsea LNG Transfer System" by William S. Mathews, ExxonMobil, et al.
IPTC 11795 • "A Model for Short-Term Supply-Chain Management of an LNG Production System" by Ajay Selot, Massachusetts Institute of Technology, et al.
SPE 109182 • "Gas-to-Hydrate Technology, an Alternative Energy for Low-Level Communities in Indonesia" by Adam Nur Bawono, Perusahaan Gas Negara
SPE 113816 • "Angsi K-Sand Production Performance: A Case History of Hydraulically Fractured Retrograde-Gas-Condensate Reservoir" by Mohamad Othman, SPE, Petronas, et al.