bluuebunny/crossref_metadata_2025 huggingface dataset:
Overview: Offshore Drilling and Completion (April 2006)
Authors: Gazaniol Didier
Published: February 2015

And now, what? We have been experiencing high oil prices for several months, which quickly translated into high rig rates. Of course, rig market is one obvious direct consequence of the current economic context, but this might not be the only one.

During the past months, we have seen operators drilling deeper to look for (and find) reservoirs in places where geologists did not see reservoirs 10 years ago because of limitations of seismic technology or of geological concepts. These wells cost tens of millions of dollars, and even if the learning curve improves, they will remain expensive. This trend has started in the Gulf of Mexico, but this simple idea of drilling deeper could soon apply in the North Sea, west Africa, Middle East, or Far East—in fact, probably all over the world.

The established energy-demand growth also has the oil industry focusing on maximizing recovery from each reservoir. Of course, people may try enhanced oil recovery in the end to recover the residual oil, but the first answer is to drill for reservoirs that were bypassed or which previously were too small to be economical. In this respect, minimizing well costs will still remain a major objective. In the meantime, and even if costs increase, use of complex completions may increase: sound monitoring and remotely controlled multizone completions will be implemented more often to optimize reservoir management.

Once again, technology will allow us to face these new challenges. But this technology will not be enough if new generations of drilling and completion engineers are not attracted by our profession and well trained. This issue may be at least as challenging as the technical one. In both areas, SPE has a role to play, and it will.

Offshore Drilling and Completion additional reading available at the SPE eLibrary: www.spe.org

SPE 96154 "10K Dual-Splitter Wellheads: 1st Worldwide Application on the Development of an Offshore Gas Field," by J.B. Faget, Total E&P, et al.

SPE 99135 "Integrating Emerging Drilling Methods From Floating Drilling Rigs—Enabling Drilling Solutions for the Future" by J.R. Kozicz, Transocean, et al.

SPE 93866 "Deepwater Subsea Well Intervention—The Future Solution" by A.J. Dick, Expro Group

Available at the OTC Library: www.otcnet.org

OTC 17279 "Drilling Observations of Possible Hydrate-Related Annular Flow in the Deepwater Gulf of Mexico and Implications on Well Planning," by S.C. Williamson, BHP Billiton Petroleum Inc., et al.
Experiment Observations of Miscible Displacement of Heavy Oil With Hydrocarbon Solvents
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 97854, "Experimental Observations of Miscible Displacement of Heavy Oils With Hydrocarbon Solvents," by D. Salama and A. Kantzas, U. of Calgary, prepared for the 2005 SPE International Thermal Operations and Heavy Oil Symposium, Calgary, 1–3 November.

The increased interest in secondary production (or post-cold production) of heavy oil and the rise of oil prices have renewed interest in solvent-based methods for heavy-oil recovery. Although the vapor-extraction (vapex) process is favored, other methods are worth investigating. Also, the relative merit of mass-transfer and viscous mechanisms in the overall recovery efficiency remains a topic of debate. This study of mass-transfer phenomena in heavy-oil/ and bitumen/solvent systems was performed in an effort to determine dispersion coefficients.

Introduction

Heavy oil and oil sands will be an important part of Canada's oil supply. One-third of the world's oil is in Canada in the form of heavy oil and bitumen. The world's heavy-oil resources total approximately 10 trillion bbl, nearly three times the conventional oil in place in the world. Alberta contains nearly 2 trillion bbl of oil. Approximately one-fourth of the oil production of Canada is from oil sands.

Here, in-situ recovery processes are thermal or nonthermal. Thermal processes use heat to reduce the viscosity of the heavy oil in situ, thus mobilizing the heavy oil. Examples include cyclic-steam stimulation, steam-assisted gravity drainage, and steamflooding. Nonthermal processes rely on dilution of the oil to reduce the heavy-oil viscosity. Examples include CO2 injection, miscible floods, and vapex.

Displacement in the case of immiscible floods, such as waterflooding, generally is not complete, but a fluid can be displaced completely from the pores by a miscible fluid. In the case of miscible fluids, there are no residual saturations. Hence, sol-vent floods present an attractive in-situ process for the recovery of the heavy oil. However, the major challenge in miscible floods is for the miscible phase to access a significant fraction of the resident oil.

In solvent-based enhanced-oil-recovery techniques, several mechanisms affect the rate of oil recovery, given that accessibility is provided. These mechanisms include mass transfer, viscous forces, and gravity drainage. The solvent diffuses and/or disperses into the heavy oil, reducing its viscosity. The solvent/oil mixture then drains and is recovered from the production well. This study focused on the mass-transfer process in miscible sol-vent floods by experimentally observing the miscible displacement of heavy oils by hydrocarbon solvents.
Q&A with W. John Lee
Authors: Lee W. John , Donnelly John
Published: February 2015

Editor's Note: In recognition of SPE's 50th anniversary this year, JPT is conducting interviews with several Society luminaries about their careers, their relationship with SPE, and the changes they have seen in the oil and gas industry and the Society over the past several decades.

What SPE experience has been the most valuable to you professionally?

The SPE experience most valuable to me professionally has been writing all or part of three textbooks published by SPE. Regardless of whether I deserved a favorable image in the industry or not because of these books, I have found that they have opened doors for me all over the world ever since the first book was published in the early 1980s. For example, as a direct result of my books, I have been invited to speak to and consult with groups—such as SPE local sections, operating companies, and government agencies—all over the world. I continue to be amazed when engineers who have been practicing from one year to 30 years bring copies of one or more of my books for me to autograph when we meet for the first time in places like Billings, Montana; Moscow; Bogota, Colombia; or Bandung, Indonesia.

What SPE experience or honor has been the most valuable to you personally?

The DeGolyer Distinguished Service Medal. To me, providing service to other professionals, especially to students and young engineers, is our single most important task. To have been recognized by my peers as having succeeded, at least in part, is worth far more to me than all the technical recognition that SPE provides.

What are the most significant changes that have occurred in SPE since you joined?

The changes I regard as most significant include internationalization and the development of the electronic SPE. The Society's primary objectives have been to collect, store, and disseminate information. We do this so much more effectively now, and make it available to so many more people, than when I joined SPE that there is simply no comparison between then and now.

Do you see major differences in petroleum engineering graduates today vs. a decade or two ago?

Today's petroleum engineering graduates are fundamentally the same as a decade or two ago. Today's graduates have much stronger skills in information technology and they are much better at multitasking than earlier generations were, although sometimes at the expense of depth of knowledge about the information or methodology they use. However, at the core, I have always found a majority of students to be creative, motivated, and interested in making things around them better.
Drilling for Water and Life - The Human Side of Petroleum Engineering
Authors: Arscott Lyn
Published: February 2015

In the 40 years or so that I have worked in the oil and gas industry, I have witnessed an impressive transformation in our industry's performance in protecting people and the environment. There are obvious business and legal drivers, but the success would not have happened without appealing to employees in our industry to be good stewards of the environment and to help others.

It is understood that our industry operates by permission of the public: no permission, no permits. Many companies have excellent programs for partnerships with the communities where they operate. Every year, SPE recognizes exceptional service to the public with its Public Service Award. SPE also has an active energy education program with the objective of improving the industry's public image. The Society encourages section members to get involved with local civic groups and to serve as speakers on energy issues. SPE also sponsors speakers to attend teachers' conventions and is starting a fund to help teachers buy teaching materials on energy education for classroom use and to help pay for education events and trips. The vision statement in the Industry Image section of the recently approved SPE Long Range Plan states: "Petroleum professionals are widely regarded as ethical, competent, environmentally sensitive, and providing a vital service to society." It is in keeping with SPE's tradition of community service that I share an opportunity for humanitarian service that requires the special skills of petroleum engineers.

In 2002, at the World Summit on Sustainable Development, the Johannesburg Declaration committed the 189 nations who signed it to develop concrete action to reverse the poverty, hunger, and disease affecting billions of people. The declaration endorsed a previous set of goals formulated by world leaders at the U.N. Millennium Summit in September 2000. One of the goals is to "reduce by half the proportion of people without access to safe and affordable drinking water and sanitation by the year 2015." A few years ago, a group of nongovernmental organizations combined to form the Millennium Water Alliance to coordinate efforts to save lives by providing clean water and sanitation to the world's poorest countries, where approximately 1.1 billion people lack access to safe drinking water and adequate sanitation.
Overview: Natural Gas Technology/Monetization (April 2007)
Authors: Vitucci John
Published: February 2015

Our industry prides itself on the development of innovative and cost-effective technologies to address the world's ever-growing demand for energy. Technology is being developed and applied at an unprecedented pace to all parts of the natural gas supply chain, from production to distribution, as we continue to develop this resource into a leading global energy supply. Over the past year, industry news has highlighted technology developments in many of the downstream areas, including liquefied natural gas, international gas-pipeline projects, gas-to-wire applications, and clean fuels derived from natural gas.

In reviewing papers for this feature, I found that development of upstream technology to address production of the world's gas reserves is moving ahead at a pace that rivals downstream-technology developments. New gas resources are becoming more challenging to develop because of geological and reservoir complexities. Sustaining well productivity continues to challenge our production methods as more reservoirs tap unconventional gas, deep-horizon gas, and condensate reservoirs. The upstream sector is responding with an increased focus in developing new technologies to address these challenges. And it is being done in all sectors of the industry, from the national and major energy companies to service and equipment companies to research institutions.

The selected papers highlight just a few of the technologies that are being investigated, are under development, or are being applied to recovery and production issues. The papers describe newly developed methods to monitor and optimize production, address near-wellbore problems through optimization of methods in practice today, and discuss potential future applications in near-wellbore conditioning. Our choice in making natural gas a leading source of energy for the world will be driven by technology and by an industry investing in that technology today and tomorrow. I encourage readers to review the additional-reading list to gain a full appreciation for the wide spectrum of technology development under way throughout the natural gas supply chain.

Natural Gas Technology/Monetization additional reading available at the SPE eLibrary: www.spe.org

SPE 102100 "Phase Behavior Study of Hydrocarbon/Water/Methanol Mixtures at Reservoir Conditions" by V. Bang, SPE, U. of Texas at Austin, et al.

SPE 102773 "Effect of Wettability on High-Velocity Coefficient in Two-Phase Gas/Liquid Flow" by M. Noh, SPE, Reservoir Engineering Research Inst., et al.

SPE 102160 "Onshore LNG Production Process Selection" by S. Mokhatab, SPE, U. of Wyoming, et al.
Production of Heavy Crude Oil: Topside Experiences on Grane
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18240, "Production of Heavy Crude Oil - Topside Experiences on Grane," by S. Husoy and S. Hatlem, Norsk Hydro A/S, prepared for the 2006 Offshore Technology Conference, Houston, 1–4 May.

Grane field production started in September 2003. Oil is exported to the onshore terminal at Sture in a 28-in. 212-km-long pipeline. Gas for injection is imported in an 18-in. 50-km-long pipeline from the Heimdal field center. Grane is the first oil field on the Norwegian continental shelf producing heavy crude. Close cooperation between Norsk Hydro's operations department, project-development team, contractors, and partners forms the basis for completing the Grane facilities on schedule, below budget, and without any serious incidents.

Introduction

Grane is the tenth field put into production by Norsk Hydro and is the first heavy-crude-oil (19°API) field on the Norwegian Continental Shelf. The full-length paper presents some of the challenges and experiences that Norsk Hydro as an operator has faced during field development and the production ramp-up period. Most of the challenges were well known beforehand, and the facility and organization were prepared accordingly. However, some of these challenges were underestimated. The production facility, including the organization, has been able to use the flexibility present to adjust directly or prepare temporary solutions while permanent solutions were developed and implemented.

Environmental Focus

The platform was designed to meet the zero-discharge philosophy of the operator. A disposal well was drilled as part of the predrilling campaign. This well was completed with 13 3/8-in. casing to an Oligocene sand reservoir 500 m true vertical depth above the oil reservoir. A drill-cutting slurrification unit in the drilling module grinds all drill cuttings and creates a seawater-based slurry. This slurry is injected into the disposal well.

A disposal well for produced water was drilled as the first platform-drilled well and delivers produced water to the same formation as the drill cuttings. No produced water is discharged to the sea under normal operation. Water treatment includes degassing and hydrocyclones. Grane is allowed to direct 10% of yearly produced water to sea; however, the water-injection system uptime was more than 95% in 2005.

The energy requirement for heating the oil is met by use of a waste-heat recovery unit that recovers energy from the exhaust of the turbines. This energy is transferred into the separation process by use of compact heaters. Heat transfer also is achieved from produced water before injection and from the crude before it enters the export pumps. The wellstream has a 70°C temperature entering the first-stage separator. Because sufficient separation of the crude is not achieved at this low temperature, heat is supplied upstream of the second-stage separator where inlet temperature is increased to 90 to 110°C.
The Selfish Technology Gene
Authors: Perrons Robert K. , Watts Lew
Published: February 2015

Guest editorial

Mother Nature may be beautiful, but she is also unapologetically harsh. Changes in an environment—such as an increase in temperature or a shift in precipitation patterns—can act as triggers that ruthlessly reshuffle the fortunes of living things within an ecosystem. Organisms that are best suited to the new conditions will prosper; the rest are swiftly killed off without an ounce of remorse. Similarly, changes in one's business environment should act as a trigger to pause and reflect on the future. Seemingly innocent changes in the prevailing winds of an industry can reshape the competitive landscape of the market with brutal efficiency.

The upstream oil and gas sector is beginning to feel the effects of just such a change, and there is every reason to believe that this shift will have a dramatic impact on the industry's "ecosystem." The sector has historically been very slow to develop and adopt new technologies, and relative investment in R&D by Big Oil has traditionally been only a fraction of that spent in other industries. Much of the oil and gas sector's R&D activities have shifted throughout the past decade toward service companies and, in some areas, to national oil companies (NOCs). But the industry is undergoing a significant transformation. With future hydrocarbon resources being in more technologically challenging environments, future winners in the industry are likely to be firms that have the ability to innovate and develop unique breakthrough technologies, and international oil companies (IOCs) are now working hard to strengthen their in-house R&D capabilities.

Just as important as the technologies themselves, however, is how companies try to deploy them. Several of the accepted norms of the oil and gas sector are also barriers that impede the introduction of innovations in the industry. First, companies in the oil and gas market have used shared asset-ownership structures as a way to manage risk, but firms quite reasonably refrain from laying their cards on the table—that is, from revealing their cutting-edge innovations—if they believe that these tools and techniques will be immediately absorbed and replicated by the other partners. Second, partner firms often quash new-technology proposals because they are not convinced of the value of the innovation and/or they are uneasy about the additional layers of perceived risk that new technologies tend to carry with them. There always seems to be a reason not to use a new technology, and having many partners in an asset frequently begets frustratingly long lists of excuses.
New R&D White Paper Addresses Challenges for Future Energy Supply
Authors: Moon Ted
Published: February 2015

R&D white paper

Over the next 30 years, the world's economies will need more energy to fuel their growth, and the oil and gas industry will have to increase investment substantially in research and development (R&D) in order to keep pace. This fact is the central theme of a new white paper from SPE's R&D Advisory Committee titled "The R&D Challenges to Secure Energy Supply for the Third Trillion Barrels and Beyond."

The third trillion refers to a US Geological Survey estimate that there are more than 3 trillion bbl of recoverable conventional oil worldwide, with one-third already consumed and the remaining two-thirds largely in the possession of national oil companies (NOCs). As worldwide energy demand grows by more than 50% by 2030 [according to the International Energy Agency (IEA) World Energy Outlook 2006], the oil and gas industry will need to rely heavily on R&D advances, according to Vikram Rao, SPE, Chairman of the R&D Advisory Committee and Senior Vice President and Chief Technology Officer for Halliburton.

"The 12-member R&D Advisory Committee has raised a number of initiatives since its inception in 2002, all designed to raise the profile of R&D in the energy industry," Rao said. "The committee's new white paper was written with one initiative in mind, to promote awareness of R&D challenges impacting the industry to an audience outside of the petroleum community."

"The white paper is mainly concentrated on demographics of what the next 1 to 2 trillion bbl will look like," said Arnis Judzis, SPE, one of the paper's main committee coauthors and Vice President of Schlumberger Data and Consulting Services. "We wanted to relate the myriad challenges associated with producing the unconventional and alternative energy sources that will be needed."

Rao agreed, adding that, "It was intended to be a manifesto, a way to shed light on the imperatives for the industry, and to begin a dialog on the areas of endeavor that are fruitful for R&D."

Before the industry can bear the fruits of an increased energy offering, a significant increase in oil and gas R&D spending will be needed. According to 2007 estimates by the IEA, this investment will need to be on the order of USD 8.2 trillion over the next 25 years. Over the past 25 years, energy R&D investment as a percentage of total R&D declined from 10% to roughly 2% in the US alone. The IEA reports similar declines on a global scale over the same time period.

Major R&D investments over the past 15 to 20 years have focused on technologies designed to find and produce more conventional hydrocarbons, including advances in 3D and 4D seismic, directional drilling, and production in frontier areas such as the deepwater Gulf of Mexico and Brazil. "These technologies will not meet our future needs, and we will need to collaborate on new technical innovations and diversify our energy supply going forward," said Rao.
Trapped Annular Pressure: A Spacer Fluid That Shrinks
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 104698, "Trapped Annular Pressure - A Spacer Fluid That Shrinks," by B. Bloys, SPE, and M. Gonzalez, SPE, Chevron; R. Hermes, Los Alamos Natl. Laboratory; R. Bland, R. Foley, SPE, and R. Tijerina, Baker Hughes Drilling Fluids; J. Davis and T. Cassel, Baker Oil Tools; J. Daniel, I. Robinson, and F. Billings, Lucite Intl.; and R. Eley, ICI, prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20–22 February. The paper has not been peer reviewed.

In subsea-completed wells, fluids commonly are trapped in casing annuli above the top of cement and below the wellhead. When these trapped fluids are heated by the passage of warm produced oil and gas, thermal expansion can create very high pressures and cause the collapse of casing and tubing strings. A successful midscale field trial has been conducted in a 500-ft test well to gauge the ability of a liquid monomer that shrinks 20% upon experiencing heat-triggered polymerization to mitigate trapped annular pressure (TAP). A method was devised to add the initiator on the fly as the spacer is pumped downhole.

Introduction

TAP, also called annular-pressure buildup, is caused by the thermal expansion of fluids trapped in casing annuli between the top of cement and the wellhead. The pressure buildup usually is a result of heat transfer from the produced fluids or from hot drilling fluids circulated while drilling a high-pressure/high-temperature (HP/HT) well. The pressure can exceed the collapse strength of the casing and production tubing. In land wells, the pressure is relieved easily by bleeding off some fluid through a casinghead valve. In subsea-completed wells, wellheads are much less accessible and generally not fitted with the necessary valves.

One of the best-documented cases involved the Marlin field, where the production casing and tubing of the first production well collapsed after only a few days of production. A wide range of mitigation techniques has been used, including vacuum-insulated tubing (VIT), leaving the previous casing shoe uncemented, burst disks in casing, nitrogen-based spacers, and crushable urethane foam.

Perhaps the most successful mitigation approach has been use of VIT. This technique generally has been successful in keeping the annular-fluid temperatures within an acceptable range. However, with the advent of deeper and hotter wells in deep water, the limits of the protection provided by VIT are being approached in two ways. First, deeper wells have much higher hanging weights that are reaching the stress limits of VIT designs. Second, the greater depths also are producing at higher temperatures. Even with the insulating effects of VIT, temperatures are sufficiently high that pressures are predicted to increase to dangerous levels.
Deepwater Blowout: A Case Study
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105914, "Deepwater Blowout - A Case History: Shallow Gas Hazards Hide in the Weeds," by William Flores Jr., John B. Garner, SPE, and Chris Scarborough, SPE, Boots & Coots, prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20-22 February. The paper has not been peer reviewed.

The full-length paper details the sequence of events of a blowout in 2,400-ft water depth of a deepwater development well adjacent to the discovery well. Loop current prevented running the blowout-preventer (BOP) stack and riser after cementing surface casing. After 3 weeks, the loop current abated, and a remotely operated vehicle (ROV) could be deployed. Upon deployment, it was discovered that the development well was blowing out, with the blowout plume carrying more than 300 ft.

Introduction

The prospect was drilled initially in 1997 and abandoned as a result of economics at that time. In the course of planning, a shallow gas hazard was identified from seismic, and records from the 1997 well reported several nonproductive days fighting lost circulation and gas.

To avoid the nonproductive time encountered on the 1997 well, the operator designed a casing program for the first development well to include riserless drilling of the shallow gas hazard using the pump-and-dump process. Development Well 1 was drilled successfully in this manner and was completed as a producer in April 2006. The well currently is shut in, awaiting field development and production facilities.

The rig was moved to a second location. Well 2 was spudded on 3 April 2006 less than 2,000 ft from Well 1 and drilled riserless through the shallow hazard. Structural pipe was jetted to 2,778 ft, which is 285 ft below the mudline. The 30-in. casing was allowed to soak for 4 hours. A 24-in. hole was drilled to 3,200 ft using seawater and gel sweeps. From 3,200- to 3,899-ft total depth (TD), a pump-and-dump system was used, maintaining a 10.5-lbm/gal equivalent mud density, by monitoring equivalent circulating density (ECD) with pressure-while-drilling (PWD) instrumentation and vortex mixing 16.0-lbm/gal water-based mud "on the fly" with seawater. A wiper trip was attempted. However, the well appeared to begin to flow with pipe at 3,597 ft. The pipe was tripped to bottom where circulation was begun and the equivalent mud weight (EMW) was increased to 10.7 lbm/gal. Circulation was stopped, and the well was observed to be static. A wiper trip then was made without problems. With no fill on bottom, the well was circulated again with a 10.7-lbm/gal EMW. While keeping the hole full, the pipe was pulled out of the hole to run 20-in. casing. The well, standing full of mud, was monitored by an ROV while preparing to run casing.
Fluidic Oscillation With Acid Stimulation Improves Gas-Well Productivity
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper IPTC 11452, "Fluidic- Oscillation Technique in Conjunction With Acid Stimulation Improves Gas- Well Productivity," by Ahmed Hegazy, Belayim Petroleum Company, and Bruce Conrad, Arshad Waheed, and Osama Sanad, Halliburton, prepared for the 2007 International Petroleum Technology Conference, Dubai, 4–6 December. The paper has not been peer reviewed. Copyright 2007 International Petroleum Technology Conference. Reproduced by permission.

Low productivity of gas wells in the offshore Mediterranean Sea operations of Egypt often is caused by near-wellbore formation damage. The stimulation technique will vary depending on the type of damage; however, prevalent techniques are hydraulic fracturing and matrix acid stimulation. A new technique called "fluidic oscillation" was proposed, which would be especially applicable in cases having uncertainties regarding rock mineralogy. Fluidic oscillation is a mechanical, nonfluid-invasive stimulation technique (i.e., it is not essential to inject the treatment fluid into the reservoir to break down damage, although its use in that manner is not precluded). This technique was successful in stimulating gas wells in Egypt.

Introduction

The main challenge after completing two high-rate gas wells was less-than-expected production. These wells are approximately 37 miles off the Mediterranean Sea coast in the PetroTemsah field, northwest of Port Said in Egypt. This field produces gas and condensate with a condensate/gas ratio (CGR) of 60 bbl/MMscf. The producing formation is the Sidi Salem formation of Serrvallian age (Miocene), with an average porosity of 22%, average water saturation of 30%, and an average permeability of 100 md. This formation consists of four main reservoir layers (Lobe-0, -1, -2, and -3) and is at a depth of approximately 14,000 ft with a bottomhole temperature of 230°F. The bottomhole pressure ranges from 7,400 to 8,000 psi. A complete mineralogical breakdown of the rock by weight is not available, but essentially the rock is clean sandstone (80% quartz with 3 to 4% calcium carbonate and 10 to 15% feldspars and clay).

The Sidi Salem formation is unconsolidated, and without adequate sand control, the wells tend to sand up, ceasing all flow from the reservoirs. The sand-control techniques used for the field include openhole gravel packs, expandable sand screens, and cased-hole gravel packs. The first example is an openhole completion with an expandable sand screen set across the zones of interest. The second well has an inside-casing gravel-pack completion.
High-Pressure/High-Temperature Consolidated Completion in the Gulf of Mexico
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18976, "High- Pressure, High-Temperature Consolidated Completion in the Continental Shelf Environment of the Gulf of Mexico: Case History," by Richard E. Patterson, SPE, and Trevor J. Willms, SPE, El Paso E&P, and Keith Foley, SPE, and Jason Edwards, SPE, Halliburton, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.

Decades after the first completion in the Gulf of Mexico (GOM) continental shelf, the logical expansion of these mature assets has extended into reservoirs that are deeper, hotter, and higher-pressured than wells completed previously. These high-pressure/high-temperature (HP/HT) wells can cause extreme completion challenges. HP/HT formations also tend to have low permeabilities, which is the opposite of most GOM reservoirs. To make these low-permeability formations economical in an offshore environment, it is imperative that stimulation treatments be completely effective.

Introduction

The West Cameron 62 field, on the continental shelf just south of Louisiana at a water depth of 35 ft, had its first well completed more than 20 years ago. Since that time, more than 30 different intervals have been completed at depths ranging from a few thousand feet to more than 10,000 ft. In recent years, it has become necessary to focus on reservoirs that exist in the 18,000 to 20,000 ft true vertical depth (TVD) range. At these depths, the pressures and temperatures of the formation trend toward the limit of what current technology allows when completion equipment and fluids are considered. The West Cameron 62 Well A-2 was completed at these depths in the Cris R formation.

The Cris R sand is located between 17,843 and 18,021 ft TVD, which correlates to 19,789 and 19,976 ft measured depth (MD), respectively. The initial bottomhole pressure (BHP) for the Cris R formation was measured at 16,500 psi at midperforation. The bottomhole temperature (BHT) at midperforation was 356°F.

Contrary to conventional GOM reservoirs, which typically have average permeabilities greater than 50 md, the permeability of the Cris R sand averaged only 0.64 md. The 18% porosity also was significantly lower than that of the well-sorted formations found at shallower depths. In fact, along with permeability and porosity, the rock mechanics falls more in line with typical south Texas "hard rock" reservoirs such as the Wilcox and Frio formations.

Despite the low permeability and porosity, the production of the well before the hydraulic-fracturing treatment was 12.0 MMscf/D and 396 B/D of condensate at a 8,572-psi flowing tubing pressure (FTP). Use of fracture models and nodal analysis led to the belief that the production rates could be increased by at least two-fold through implementation of a hydraulic fracture. However, very little information on HP/HT fracturing treatments in the GOM was available.
Your SPE: SPE Managing Costs and Maintaining Quality
Authors: Roodhart Leo
Published: February 2015

President's column

We are a bit further into the year since I wrote my last column, and unfortunately the global economic crisis deepens. Companies have already tightened such things as travel budgets and will certainly be watching cash flow very carefully. I maintain, however, that this is the time we should focus on preparing for the next upturn by retaining capacity and developing or improving the relevant technology. In an ideal world, R&D and training would be anti-cyclic to the economic cycle: use a lower demand on staff in a downturn to train them for the next phase and allow this human capital to develop new ideas/R&D when there is time for it. Now, more than ever, companies should be seeking innovative ideas and technology to reduce their operating costs and produce better results.

Crisis or no crisis, SPE presidents have to travel. So, I am writing this column on a low-cost airliner visiting sections in India. I am over 6 ft tall, so I am particularly averse to cramped budget seating! However, if our members have to tighten their belts, so does SPE.

The Fiscal Year 2010 budget, which begins 1 April, reflects significant economies in both operating (which includes staff travel) and program expenses. Through the year, we will exercise additional cost-cutting measures to achieve even more savings in program expenses. We'll use technologies like Skype or WebEx for committee meetings, renegotiate contracts with hotels and conference venues wherever possible, and hold both committee meetings and events in more cost-effective locations. For instance, why do we need to hold a workshop committee meeting in a hotel for USD 1,000 if one of the committee members has an office with meeting rooms to do the same! At the same time, both volunteers and staff will do everything possible to increase the quality of SPE programs. We might have fewer papers at a conference, but we (the program committee) will ensure that the quality of the papers will be higher. We can do that, as most conferences now get more abstracts than previously (in earlier downturns, the saying in my company was "He who publishes, stays."), which allows us to choose the very best and focus presentations in fewer but better sessions. So please come, as SPE conferences will be better than ever!

For many of you, though, travel constraints are a bottleneck. Our response is to place SPE's technical conferences and workshops close to major petroleum operations to help reduce or eliminate travel costs. We are even examining whether we can relocate some currently scheduled events to be more conveniently placed. We also plan to make greater use of technology in the development of event programs to make members’ participation easier and to reduce the number of committee meetings that volunteer organizers will be asked to attend.
Proper Inventory Management Requires Sound Analysis and Technology
Authors: Turner Bert
Published: February 2015

Management

Corrosion remains a major challenge to maintaining the integrity of infrastructure in oil and gas fields, particularly at the subsurface. A recent SPE Applied Technology Workshop in Abu Dhabi, UAE called "Subsurface Corrosion Risks and Challenges" highlighted critical aspects of subsurface corrosion control, including selection of corrosion-protection methods, improving drilling practices to minimize corrosion, and assessing downhole corrosion-monitoring techniques.

The welcome address by Qasem al-Kayoumi of Zadco highlighted the importance of organizations working together to identify critical subsurface corrosion challenges, share and agree on best practices, and identify the best existing downhole corrosion-mitigation technologies. To understand the technical areas where additional focus is required, networks must be formed between the operators, well engineers, and service providers. Al-Kayoumi said that Zadco has gained valuable subsurface experience by creating a seamless co-operative relationship with other operators. Zadco has also sponsored projects for downhole corrosion-modeling programs.

Materials for Oil and Gas Production

The first technical session of the work-shop highlighted materials used in oil and gas production. Keynote speaker Bijan Kermani of KeyTech opened by stating that hydrocarbons will continue to be the world's principal energy source in the foreseeable future. The expected growth in energy demand will spur increases in production, which will become more multiphase in nature and contain higher percentages of harsh components such as hydrogen sulfide (H2S) and carbon dioxide (CO2). These acid gases in high water-cut production systems present major corrosion concerns.

Therefore, material selection must become more specific to mitigate corrosion, and the impact of corrosion with regards to health, safety, and the environment; capital expenditure; and operational expenditure must receive continued serious consideration. Kermani said that materials selection must be coupled with ‘near-realistic’ corrosion modeling and prediction for optimum integrity assurance.

Zadco's Obadah Al-Sawadi next discussed the principles of corrosion modeling and prediction as they relate to materials selection. He stated that any useful model should be able to accurately predict corrosion rates as operating conditions change and account for actual tubing conditions rather than predict the phenomena at only one set of design conditions. A successful modeling program should also clearly define target corrosion rates to assess whether carbon steel or a corrosion-resistant alloy (CRA) should be employed. Finally Al-Sawadi highlighted several continuing challenges for accurate modeling programs, including obtaining accurate field data, the large number of variables involved and their relevance, and changes in the operating regime.
An Integrated Decision-Management Process Shortens Time to First Gas
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 115251, "Reducing Time to First Gas: Lessons Learned in Expediting and Informing International Investment Chain Decisions," by Deborah D. Resley, SPE, and Christopher Reinsvold, SPE, Decision Strategies, originally prepared for the 2008 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 20-22 October. The paper has not been peer reviewed.

The monetization of gas, particularly in liquefied natural gas (LNG) projects, requires large capital investment in most links of the gas value chain from production to end use. Companies that invest in a single component of the value chain, such as nonintegrated gas producers, must understand the value of and risks inherent in every link in the chain, because gas will be priced in relation to its final point of sale. Final sale price as well as the effects of processing and capacity limitations ripple their way upstream to alter the timing, demand, and viability of the upstream investment.

Introduction

LNG projects are good examples of complex global gas-development projects with large capital-investment requirements. To build a commercial LNG project from gas production to point of final sale requires investment in and development of several capital projects. These linked or integrated projects serve to produce, treat, transport, and sell the gas in specific markets. These projects are joined in a value chain by at least 16 major commercial contracts, beginning with a production-sharing contract at the wellhead and ending with a gas-sales agreement in the end-use market. The entire set of investment decisions in the LNG chain can be driven by objectives such as the ability to book gas reserves by a certain date, optimizing the entire gas portfolio of assets, and in the case of companies with a portfolio of LNG assets, the potential for arbitrage and the ability to leverage and trade each LNG asset.

LNG projects now have even more complex business chains than 10 years ago, involving multiple investors in various parts of each chain. Successfully commercializing gas in integrated LNG projects and achieving acceptable returns requires numerous investment decisions. Building such a chain involves high-level coordination and integration of both technical and commercial processes, the option of reducing costs through increasing throughput, and leveraging economies of scale to reduce plant costs.
Perforating Techniques and Use of Cesium Formate Kill Pills To Maximize Productivity in HP/HT Gas Wells and Minimize HSE Risks
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 19242, "An Evaluation of Perforating Techniques and Use of Cesium Formate Kill Pills To Maximize Productivity in HP/HT Gas Wells and Minimize HSE Risks," by Alistair Roy, SPE, Allan Twynam and Jeff Parke, BP; Angus Morrison, Schlumberger; and John Downs, Cabot, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.

The BP-operated Rhum field is a North Sea high-pressure/high-temperature (HP/HT) lean-gas field. A key design requirement was to evaluate overbalance- and dynamic-underbalance-perforating techniques to optimize productivity while reducing the risk of producing hydrocarbons to surface during downhole operations. This case history focuses on available perforation techniques with the aim of matching or exceeding the flow performance achieved on the appraisal-well drillstem test (DST).

Introduction

The Rhum field is 45 km north of the Bruce field (Fig. 1). It has three subsea development wells tied back to the host Bruce production platform. The water depth is approximately 108 m. The field has several challenges.

Bottomhole temperature and pressure (BHP) were 300°F and 12,500 psi, respectively.

The lean-gas reservoir fluid leads to high surface pressures (>10,000 psi).

The rock strength varies from 8,000 to 30,000 psi unconfined compressive strength (UCS).

Middle sour environment is expected with H2S levels of 10 to 20 ppm and CO2 levels between 4 and 8%.

Appraisal Well 3/29a-4 was spudded in August 2000, and testing was completed in February 2001. This well confirmed that the field was an HP (12,418 psia at 4745 m true vertical depth subsea), lean-gas discovery with approximately 1 Tcf of gas initially in place.

Completion Objectives

From the start of the project, a desired objective for the Rhum completions was to maintain at least one mechanical barrier and one fluid barrier while running the completion. This combination was essential risk mitigation for running completions in a subsea environment. Only two clear fluids were capable of delivering the required 1.9- to 2.2-specific-gravity (SG) brine weight: cesium formate and zinc bromide. The environmental risks of working with zinc bromide were deemed unacceptable; therefore, cesium formate was selected.

It was decided to evaluate whether cesium formate could be used during perforation to avoid the complicated rig ups and multiple runs required for deploying the required number of perforations by use of coiled tubing (CT) or electric line (E line).
The Oil Field of the Future, Now
Authors: Cobb Calvin
Published: February 2015

Guest editorial - No abstract available.
Overview: Wellbore Tubulars (May 2004)
Authors: Mabile Claude
Published: February 2015

Overview - No abstract available.
An Innovative Design Approach to Reduce Drillstring Fatigue
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 87188, "An Innovative Design Approach to Reduce Drillstring Fatigue," by Tom Hill, SPE, Sean Ellis, SPE, Kang Lee, Nicholas Reynolds, and Nanjiu Zheng, T.H. Hill Assocs. Inc., prepared for the 2004 IADC/SPE Drilling Conference, Dallas, 2-4 March.
Overview: Formation Evaluation (May 2004)
Authors: Unalmiser Servet
Published: February 2015

Overview - No abstract available.
Productivity-Based Method for Selecting the Reservoir Drilling Target and Steering Strategy
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 85341, "Productivity-Based Method for Selection of Reservoir Drilling Target and Steering Strategy," by A. Kharghoria, SPE, Texas A&M U.; M. Cakici, Stanford U.; R. Narayanasamy, SPE, U. of Texas at Austin; and R. Kalita, SPE, S. Sinha, SPE, and Y. Jalali, SPE, Schlumberger, prepared for the 2003 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Abu Dhabi, 20-22 October.
Annual Drilling Conference Probes Technology Development and Lessons Learned
Authors: Donnelly John
Published: February 2015

More than 1,500 industry professionals attended this year’s 3-day SPE/IADC Drilling Conference and Exhibition in Amsterdam, which placed special emphasis on the development and uptake of new technology. The annual event attracted representatives from more than 46 countries. It was the highest attendance for the conference location in Amsterdam, and it also set a record for exhibitors at the venue, with 48. Next year, the conference adds a new location, with the conference to take place in Miami during 21–23 February 2006.

Well-rounded and provocative plenary sessions touched on contemporary issues that affect drilling as well as other aspects of the upstream oil and gas industry. The sessions also featured an interactive component, in which audience members voted on the questions posed to the panel. The first plenary session—titled “New Technology Development: Who Tony Meggs Satish Pai Should Be Responsible?”—included moderator Toni Marszalek, Vice President, Schlumberger; Paul Ching, Director of E&P R&D, Shell Intl. E&P; Tony Meggs, Group Vice President, Technology, BP; Steven Newman, Vice President Performance and Technology, Transocean; Satish Pai, Vice President, Schlumberger Oilfield Technologies; and Kevin Lacy, Principal Adviser Well Engineering and Operations, ChevronTexaco.

Meggs offered an overview of R&D spending over the past decade, which saw a shift in spending from operators to service providers. Operators have reduced much unnecessary spending and, through consolidation, eliminated some duplication, leading to higher efficiency. But he acknowledged that the shift in R&D spending to service companies may have gone too far and that operators are now picking up the pace regarding expenditures. Pai called the amount now spent by the industry on R&D “worrying” because it has dropped significantly from the past. “It is now a big D and a small R,” with development spending far outstripping research, he said.