bluuebunny/crossref_metadata_2025 huggingface dataset:
Overview: Gas Production Technology (November 2006)
Authors: Wichert Edward
Published: February 2015

The gas-production and -processing industry continues to apply new technologies, as well as improve old technologies, to produce gas and bring it to market. For many years, gas in remote locations had virtually no value because markets were not within economic reach by pipeline. In recent years, with the increase in the value of oil and the products derived from oil, technologies to convert natural gas chemically to liquid hydrocarbons are being applied to monetize remote gas. This increase in gas-liquefaction capacity is in addition to the older technology that physically changes phases of natural gas from gaseous to liquid by deep cooling for transportation to market.

Natural gas often is produced from tight geological formations. To produce gas from low-permeability reservoirs economically, it is necessary to hydraulically fracture the rock. This process requires pumping a large amount of water or a suitable hydrocarbon liquid at high pressure as carrier fluid for the proppant. Minimizing the leakoff of the fluid being pumped enhances the effectiveness of such stimulation treatments. New approaches to the selection of specific fluid additives, designed to reduce surface tension and leakoff, can extend the fracture length and increase the well's productivity.

A common hindrance to gas production in low-productivity gas wells is the ever-present problem of coproduction of water. While this problem has been studied extensively in the past, new technology can be combined with existing technology to extend the productive life of low-rate gas wells. For high-pressure gas production, a reduction of the water vapor contained in the produced gas can be achieved through the application of supersonic nozzles, in place of traditional dehydration methods.

The above-mentioned topics and other innovations regarding gas production technology were examined in papers presented during the past year at various SPE technical meetings worldwide.

Gas Production Technology additional reading available at the SPE eLibrary: www.spe.org

SPE 100442 "Selective Removal of Water From Supercritical Natural Gas" by A. Karimi, Memorial U. of Newfoundland, et al.

SPE 98285 "Arqumia Field: Mexico's Highest-Deliverability Gas Well" by A.E. Guzmán, SPE, Pemex E&P, et al.

SPE 97070 "Identifying the Timing and Sources of Damage in Gas-Storage Wells Using Smart Storage Technology" by J.P. Spivey, SPE, Phoenix Reservoir Engineering, et al.
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.
Haradh-III: Field Development Using Maximum-Reservoir- Contact Wells, Smart-Well Completions, and I-Field Concept
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 105187, "Haradh- III: Industry's Largest Field Development Using Maximum-Reservoir-Contact Wells, Smart-Well Completions, and I-Field Concept," by Abdulaziz O. Al-Kaabi, SPE, Nabeel I. Al-Afaleg, Tony Pham, SPE, Ali S. Al-Muallem, Fahad A. Al- Bani, Richard G. Hart, and Drew E. Hembling, SPE, Saudi Aramco, prepared for the 2007 SPE Middle East Oil & Gas Show and Conference, Bahrain, 11–14 March.
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.
Big and Clean - A Novel Design for LNG Plants
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper IPTC 11637, "Big and Clean - A Novel Design for LNG Plants," by Barend Johan Jan Pek, Kaart Sander, and Elion Wiveka, Shell, prepared for the 2007 International Petroleum Technology Conference, Dubai, 4-6 December. The paper has not been peer reviewed.

The demand for clean and afford-able energy translates into a large demand for liquefied-natural-gas (LNG) production capacity. To meet this increase in production capacity, increasingly larger processing-train sizes have become the trend. A mega-train design is presented for production of more than 10 Mt/a. Much of the LNG expansion is taking place in the Middle East. A typical feed-gas composition from this region was selected as the basis for integration of gas conditioning (treating), natural-gas-liquid (NGL) extraction, liquefaction process, and utility facilities.

Introduction

The demand for natural gas is forecast to grow by 3%/yr over the next 15 years, with demand for LNG growing by 8–10%/yr. For several years, many projects have been under way, resulting in a constrained contractor market, a worldwide heavy demand for raw materials, and issues regarding logistics of work force and products. These challenges lead to large trains, particularly where large resources are involved, as in the Middle East, Russia, and Australia.

An increasingly important challenge is the need to minimize CO2-emission rates. High efficiency is a crucial enabler. Higher efficiency increases the amount of LNG that can be produced for the selected power turbines and compressors that make up a large part of the capital costs. Therefore, the focus is extended to the use of exhaust heat.

The full-length paper presents a train design for LNG production at a rate of 11 Mt/a. The design is based on Shell's Parallel Mixed Refrigerant (PMR) Process, which uses propane refrigerant in the precool cycle. Depending on project-specific conditions, such as climate and market opportunities, other designs may be more suitable. The double-mixed-refrigerant process was selected for the Sakhalin LNG project currently under construction (Fig. 1).

The PMR concept is scalable from 11 to 6 Mt/a by changing helper-motor size or changing to smaller gas turbines. Improved fuel efficiency by use of waste-heat recovery is applicable to several designs, thus minimizing CO2 emissions.

Design Premises

Plantwide integration of heat generation and demand is provided by steam. The full use of waste heat from the gas-turbine exhausts enables a step change in plant efficiency with respect to conventional LNG-plant designs and can help to reduce the specific CO2 emissions.

This design uses air cooling. Dedicated attention to hot-air recirculation and plot-plan optimization provides a robust design. Should cooling water be available for a once-through or recirculating cooling system, this can be incorporated and will further improve fuel efficiency and, depending on cooling-water-supply complexity, also the specific cost.
Conversations: Engagement Provides Its Own Rewards
Authors: Fattahi Behrooz
Published: February 2015

President's column

My travels as the President-Elect, and now as the 2010 SPE President, have taken me to many countries. These trips have reminded me of how and why SPE evolved from being an entity incorporated in Texas to a truly global organization.

I think it is useful for members to understand how our business structure (Fig. 1) helps us to serve our global membership. At one time, the Society's demographics were such that our membership was easily served by a Dallas-based business. As our demographics changed, we saw the need to open offices outside the U.S. Opening offices in London and Kuala Lumpur in the 1990's were big steps in improving services to members outside North America. The addition of an SPE office in the Middle East in 2003 provided additional support in that growing region. Even with these offices, we still faced challenges of timely provision of services, along with currency-exchange issues and diverse business practices in countries where SPE members reside, which prompted consideration of a new business structure.

In 2004, SPE established its business structure as a Stichting, a not-for-profit society registered in The Netherlands, which has many similarities to U.S. foundations, including tax-exempt status. The SPE Stichting is the parent organization to a number of subsidiaries, which are subject to the laws of the countries where they operate.

Although we have a complex business structure, its workings are transparent to members. You are only aware that we are able to provide services to you worldwide in an efficient manner, wherever you are located!

SPE has about 250 staff located in our offices around the world to help in the delivery of our services to nearly 90,000 members in 116 countries. You can see why we rely on you, our members, to help us conduct our business. Volunteers are SPE's point people who are the enablers of our services and deliverers of our products. Without their passionate engagement and dedicated time and effort, SPE will not be successful in what it intends to accomplish.

About 5,000 volunteers work on the 170 section boards, 200 student chapter boards, 100+ meetings and conference committees, and 19 standing committees, as well as on the 27-member SPE Board of Directors.

With the expertise and time of volunteers, we are able to carry out our mission of technical knowledge exchange.
Reality Checks for Well Time and Cost Forecasts
Authors: McIntosh John
Published: February 2015

Management

Much has been written to explain the origins of the credit crisis that has engulfed the international financial system. At the heart of each explanation is the failure to quantify commercial risks. The companies at the centre of the crisis were often long-established, considered profitable, and were endowed with great resources to make mathematical models of their activities. Despite this, it is safe to conclude that many of their models were wrong. Risk is a feature of financial transactions and drilling wells that no amount of engineering will completely remove. From the crisis in banking it is obvious that the skills required to build a credible model of activities inclusive of risk are in short supply.

It would be convenient to assume that because the energy industry employs lots of numerate people it is good at quantifying uncertainty; unfortunately, many of the time and cost models used for well planning can be easily disproven. The reasons for this go beyond the tools available to the human bias toward optimism. There is a tendency to treat each well project as unique and disregard the fact that past performances will not only inform us about averages but also about uncertainty.

A Suitable Benchmark

The budget for new well projects will often first be defined with little detailed engineering information. There are perfectly valid reasons for this; out of a basket of many prospects an operator is unlikely to develop every one. Early budgetary estimates play a part in the selection of the best prospects to drill. Irrespective of the method used to define a budget figure, and irrespective of the maturity of the estimate, some guidance on confidence should accompany the result. In common with any other forecasting discipline, well cost estimation never is and never will be an exact science. The very best that can be done is to describe the probability of a particular scenario and to use the results from similar previous wells to back this up.

If a model of well project duration cannot be substantiated with empirical evidence it must be treated with extreme caution. The inputs to the model matter much less in this respect than the output; it is surprisingly easy to make a poor probabilistic model from good information. In many mature drilling provinces such as the UK, public data can be used to provide the justification necessary for models of project duration which in turn can be used to model cost.
Technology Focus: Drilling and Completion Fluids (November 2009)
Authors: Estes Brent
Published: February 2015

Technology Focus

The success or failure of a well is a function of many factors. One important influence is the drilling fluid. As companies deal with drilling more-complex and -difficult wells, a well-designed drilling fluid can contribute to the success of the well. The year's highlights range from laboratory studies on fluid/chemical effects that relate to borehole stability to complex-fluid physical properties that mitigate lost returns.

With ever-increasingly complex wells being drilled, the role of a drilling-fluid engineer has changed as well. When I started in the fluids industry 15 years ago, we were concerned mostly about controlling fluid loss, plastic viscosity, yield point, and gels. To meet today's challenging wells, we have to be educated about the aforementioned fundamental properties as well as borehole stability, narrow-margin drilling, and lost returns, in addition to environmental regulations and waste management.

A good example is in the lost-returns arena. With the increasing understanding of rock mechanics, a more systematic approach to lost-returns remediation was developed. Only a few years ago, most people were unfamiliar with concepts such as "building stress or integrity" and terms such as "hoop stress," "stress cage," and "fracture-closure stress." No longer are the days of pumping "everything but the kitchen sink" down the hole in an often futile attempt to stop losses! Now, we take a science-based approach to fluids and engineer the particle sizes to stop lost returns and reach drilling objectives in less time and at a lower cost.

The roles of fluids specialists working for operators and fluids companies are changing as well. They have become knowledgeable about more than just fluid makeup and properties. Companies have engineers and scientists on staff who research issues such as borehole stability, lost returns, waste management, and environmental regulations around the world.

Please take time to read the following summaries as well as the suggested additional reading.

Drilling and Completion Fluids additional reading available at OnePetro: www.onepetro.org

SPE 120646 • "Quest for a Pragmatic Drilling-Fluid-Performance Index—Key to Improving Fluid Performance and Optimizing Quality-Well-Delivery Economics" by Peter Osode, SPE, Petroleum Development Oman, et al.

SPE 123013 • "Changing Shale Strengths With Invert-Emulsion Drilling Fluids: Theory, Measurement, and Modeling" by T. Hemphill, Halliburton, et al.

SPE 119269 • "Drilling-Fluid Design Prevents Lost Returns by Building Integrity Continuously While Drilling in East Texas" by Kenneth B. Vaczi, SPE, ExxonMobil, et al.
First Deepwater Well Successfully Drilled in Colombia With a High-Performance Water-Based Fluid
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 120768, "First Deepwater Well Successfully Drilled in Colombia With a High-Performance Water-Based Fluid," by J. Marin, SPE, F. Shah, SPE, M. Serrano, SPE, A. Jaramillo, and C. Marin, Halliburton, and W. Arevalo and G. Priandi, Petrobras, originally prepared for the 2009 SPE Latin American and Caribbean Petroleum Engineering Conference, Cartagena, Colombia, 31 May-3 June. The paper has not been peer reviewed.

Deepwater drilling presents significant issues and uncertainties, especially when there is no prior drilling experience in the area. Uncertainties about the drilling conditions create additional risk to operators and can cause project budget overruns. Innovative technologies often are implemented to help ensure that the well is drilled efficiently and safely. Drilling-fluid selection was a key decision to the success of the project.

Introduction

Deepwater exploration activity in the oil and gas industry continues to present new hurdles requiring innovative technical solutions. These difficult wells can increase the risk factor and result in potentially higher operational costs. In most cases, an oil-based drilling fluid is selected as the first option because of the high daily costs associated with a deepwater operation and the advantages gained in wellbore stability and rate of penetration (ROP) compared to conventional water-based systems. However, tightening environmental regulations and high costs associated with cuttings and oily fluid disposal are sufficient reasons to seek viable water-based fluid alternatives that could provide an oil-based-drilling-fluid performance.

Water-based drilling fluids that simulate the performance of oil-based drilling fluids, commonly are referred to as high-performance water-based fluids (HPWBFs). The main benefits of these systems are reduced environmental footprint and lower costs associated with cuttings and fluids disposal.

Petrobras Colombia undertook the challenge of drilling the first deep-water well in Colombia in 1,840-ft water depth in the Tayrona Block in the Caribbean Sea north of Colombia. Because of environmental restrictions, uncertainties about formations that would be encountered, and the need to protect the target zone from damage, an HPWBF was selected to drill the well.

HPWBF System

Fluid selection presented several challenges related to drilling the exploratory well. The operator rejected the option of using an oil-based fluid because of environmental restrictions and cuttings and fluids-disposal complications. The HPWBF used met the required criteria and was designed for maximum shale inhibition in highly reactive formations and provided wellbore stability, high ROPs, and acceptable rheological properties over a wide range of temperatures. It had been run successfully in the Gulf of Mexico in shelf and deepwater operations.
Independent Evaluation for Reliable Reserves Estimates
Authors: McGilvray W. Gary
Published: February 2015

Guest editorial - No abstract available.
Offshore Rig Sharing Improves Exploration-Drilling Performance
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 87178, "Offshore Rig Sharing Improves Exploration-Drilling Performance: A Case History," by David R. Bert, SPE, BP plc, prepared for the 2004 IADC/SPE Drilling Conference, Dallas, 2-4 March.
2004 SPE ATCE
Authors: Donnelly John , Denney Dennis
Published: February 2015

Conference review - No abstract available.
Stage-Gate Project-Management Process in the Oil and Gas Industry
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 102926, "The Good, the Bad, and the Ugly of the Stage-Gate Project-Management Process in the Oil and Gas Industry," by G.W. Walkup Jr., SPE, SDG, and J.R. Ligon, SPE, Consultant, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.

Management teams speculate on major capital projects to drive company performance. Capital committed to megaprojects has increased at a compounded average growth rate of more than 12% during the last decade, and this trend is expected to continue over the next decade. To manage the shareholder value that is at risk in these projects, most companies have invested heavily in a formal stage-gate project-management process (PMP). Yet the performance of major projects has not improved appreciably, and significant project failures—both technical and economic—continue to occur. Key organizational and technical shortcomings that diminish project performance are identified, and actions that management can take to gain significant competitive advantage are suggested.

Introduction

Spending in excess of U.S. $2 billion over a 5-year period for a single project is accepted. Most companies have adopted a stage-gate PMP to manage these projects. While differences exist, there is much similarity among the different PMPs. For this paper, the process and nomenclature shown in Fig. 1 are used. The focus is on the first three phases of the PMP because they are most relevant to petroleum engineers.

PMP Overview

A PMP should create greater shareholder value from major projects while simultaneously protecting people and the environment. Fig. 2 is a model of how shareholder value is created, beginning with value identification and ending with value delivery. The role of a PMP in this value-creation cycle is to improve value identification through improved decision quality and to improve value delivery through improved project execution.

The five-phase stage-gate process in Fig. 1 is the PMP that has evolved from companies' beliefs about shareholder-value creation and management's ability to influence it. Three of the five PMP phases are focused on value identification, and frequently they are referred to collectively as front-end loading (FEL). Each phase has a specific goal and ends with a decision to move the project to the next phase, redo the current or prior phase, or drop the project altogether. The exception is that the final phase, Operations, has no terminal stage-gate decision.
Faster and Longer Bit Runs With New-Generation PDC Cutter
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 102067, "Faster, Longer, and More-Reliable Bit Runs With New-Generation PDC Cutter," by J. Clegg, SPE, ReedHycalog, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.

A new process for manufacturing polycrystalline-diamond compact (PDC) cutters creates a wrapped thermostable region across the face and around the periphery of the PDC cutter. This differs significantly from existing first-generation thermostable product because the treated region has complex geometry in three dimensions. The full-length paper describes the new cutter geometry and shows how the thermostable region supports the cutter as it slowly wears.

Introduction

Historically, there has been a trade-off between abrasion and impact resistance of PDC cutters. Typically, impact resistance was achievable by use of a larger diamond grain size but at the expense of abrasion resistance. The first attempts to extend the envelope of PDC-bit and -cutter performance occurred in the mid-1990s when multimodal polycrystalline diamond was introduced. This used a mixture of grit sizes from 50 to 2 µm in diameter, allowing the smaller grits to fill the voids left between the larger particles, resulting in a much denser polycrystalline-diamond layer that improved abrasion resistance.

Additional improvement was achieved by use of nonplanar interfaces. The move from planar to nonplanar interfaces was driven by a desire to reduce stresses at the interface between the polycrystalline diamond and its tungsten carbide substrate.

The introduction of the nonplanar interface combined with the multimodal polycrystalline-diamond mix provided significant improvement in both relative toughness and relative wear life over planar multimodal materials. The thicker diamond edge that resulted improved relative abrasion life.

Thermostable PDC Cutters

Cobalt normally is present in the creation of polycrystalline diamond in the PDC press. It is introduced in the tungsten carbide support, where it acts as a cement. At the elevated temperature and pressure where diamond-to-diamond bonding occurs, the cobalt migrates into the diamond grit and helps to catalyze the bonding process. It also forms a bond with the tungsten carbide substrate and ensures that the PDC is one integral component. However, cobalt significantly reduces the thermal stability of the PDC because it has a greater coefficient of thermal expansion than the surrounding diamond particles. Between 700 and 760°C, the cobalt expands and forces the diamond-to-diamond bonds apart. This results in the rapid breakdown of the compact. What appears to be abrasive wear when a dull PDC bit is analyzed often can be the result of the breakdown of the diamond-to-diamond bonds because of overheating. Therefore, it is important that the temperature of the PDC cutter is maintained below 700°C to avoid thermal breakdown. Unfortunately, the cutting-tip temperature often exceeds this critical limit.
Step Change in Performance: Upgraded Bit Technology Improves Drilling Economics
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 103074, "Step Change in Performance: Upgraded Bit Technology Significantly Improves Drilling Economics in GOM Motor Applications," by B. Grimes, SPE, and B. Kirkpatrick, Hughes Christensen, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.

Operators in the Gulf of Mexico (GOM) are constantly looking for ways to reduce the costs of drilling development wells. A new steel-tooth (ST) roller-cone bit with an advanced metal-seal bearing has achieved this goal and is having a significant effect on drilling economics. Improvements in bearing life, seal reliability, and cutting-structure durability have resulted in more time on bottom, giving the operator the confidence to use the new roller-cone bits in long directional hole sections.

Introduction

With large regions of the GOM rapidly becoming mature provinces, operators are looking for ways to reduce the costs of drilling development wells. Most of the wells drilled are directional, and heavy water-based drilling fluids often are required in the intermediate hole sections. Relatively high bottomhole temperatures combine with high bottomhole pressures and balling shales to present a challenging drilling environment. Operators strive to increase rate of penetration (ROP), maximize hours on bottom for each bit, reduce risk, and complete the section with fewer bits to reduce the number of trips.

Improved roller-cone bits with an innovative single-energizer metal-seal (SEMS) bearing were introduced in 1998 (Fig. 1). A step change in bit life was realized, yet it took a year or two for operators in the GOM to gain sufficient confidence in the new ST bits to run them harder and leave them in the hole longer. By 2000, operators routinely were achieving runs as much as twice as long as was typical with the predecessor elastomer-sealed ST bits, particularly at higher rotary speeds (e.g., 175 to 275 rev/min). In 2000, enhanced ST cutting structures were introduced to complement the SEMS bearing (Fig. 2). The new ST cutting structure provided longer tooth life by improved tooth wear resistance and reduced tooth breakage.

GOM Drilling Environment

The GOM drilling environment is one of the most diverse in the world. With exploration and development programs taking wells to ever greater depths, the demands placed on ST roller-cone bits and their sealed-bearing systems become increasingly severe. The increased service life and reliability of rotary-steerable systems and top-of-the-line motor assemblies allow them to successfully drill long, complex well paths, which increases the directional challenges for roller-cone bits. Both concentric and eccentric hole-opening technologies place unique loading conditions on roller-cone bits when they are used as pilot bits.