bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of Big-Bore Wells in a Giant Offshore Field
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105509, "Design, Construction, and Optimisation of Big-Bore Gas Wells in a Giant Offshore Field," by B.M. Clancey, SPE, A.S.D. Khemakhem, SPE, and T.F. Bene, RasGas Co. Ltd., and M.H. Schmidt, SPE, ExxonMobil Development Co., prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20-22 February.
An extensive big-bore gas-well drilling and completion program is in progress to develop the giant North field offshore Qatar. Benefits of the big-bore concept compared to the previous 7-in.-monobore design include reduced development costs by requiring fewer wells and deferred installation of compression by providing higher flowing wellhead pressures (FWHPs). This is the widest application known of big-bore wells in a single field and involves more than 75 wells. An extensive system of detailed design review, equipment-performance testing, and quality programs was implemented to meet project requirements for well reliability.

Introduction
Discovered in 1971, the North field of Qatar extends over approximately 2,316 sq miles and contains approximately 900 Tcf of abnormally pressured natural gas. Development has taken place in several stages, commencing with initial production by Qatar Petroleum in 1991 to supply the domestic gas market.
More recently, the growth in global liquefied-natural-gas (LNG) demand has sparked much-more-extensive development. RasGas is responsible for the development of a large area of the North field, covering more than 193 sq miles, to provide natural gas for both new LNG trains and the growing domestic gas market. The RasGas expansion plan requires more than 75 wells to be drilled from 2002 to 2010.
Production is from the massive Khuff carbonate formation, which includes several productive intervals (K1, K2, K3, and K4), at approximately 10,000 ft true vertical depth (TVD). More than 90 wells will be operated, producing a total of 8 Bscf/D.
Well deliverability from the K1 to K4 reservoirs is very high because of formation quality, near-initial reservoir pressure, and high net-pay thickness.
Well designs evolved from packer/tubing completions intended to produce 60 MMscf/D in the initial Qatar Petroleum project to high-rate 7-in.-monobore wells able to deliver more than 100 MMscf/D in the first LNG projects. Higher-capacity well designs, capable of producing more than 150 MMscf/D, could be suitable for the planned expansion projects. Although individual wells would be more expensive to construct, fewer wells would be required, and the higher FWHP would defer installation of compression facilities.
Proud To Be An "Oil Man"
Authors: Stokley C.O. 
Published: February 2015

Guest editorial
After 42 years in the oil and gas industry, I can only say it has been one heck of a ride. I cannot imagine any other career path offering the diversity of technical challenges that I have been so fortunate to enjoy. As a result, I doubt that I will be able to just walk away and SKI (Spend the Kid's Inheritance) or play golf every day.
Those of us in this category (age and experience) must make a concerted effort to pass on our small piece of history to the newcomers, recruit for the industry, and counteract the longstanding, uninformed opinions of the public. The new SPE Ambassador Lecturer Program is one of many ways we might work to achieve these tasks, which may be as important to the future of our industry as any challenge we have faced to date.
The well-publicized age gap in the industry is real, so it is imperative that those of us reaching retirement stay in touch and mentor the new recruits coming into our industry. With the wide array of communication options today, we can consult, volunteer, and attend society meetings to ensure that we pass along some of this experience. I am also involved with the Pioneer Oil Producers Society, a group of about 300 retired or near-retirement-age professionals who have worked or are working in the oil business. A typical monthly luncheon has 120 attendees representing more than 5,000 man-years of experience. Prodding the group to get involved beyond meeting once a month is a difficult task because most have worked 45 years in order to retire and have no intention of doing anything now other than retire. But this is just one large pool of talent and experience that is not being shared with the rest of the industry.
Having recently spoken to students at universities in Tennessee and Texas, I was overwhelmed by the inquisitive and unbiased nature of these young men and women who will soon graduate and enter a career. Hopefully, some will choose the oil and gas business. I found the majority to be searching for the truth, and many had researched the subjects I was speaking on before attending the presentation. The students did not receive academic credit for attending and so were there of their own free will to hear perhaps another side of the story about fossil fuels and some piece of technical or business insight.
Assessing the Past, Present, and Near Future of the Global Energy Market
Authors: Aguilera Roberto F. , Aguilera Roberto 
Published: February 2015

Management
This article is based on paper SPE 110215, which was presented at the 2007 SPE Annual Technical Conference and Exhibition in Anaheim, California.
The availability of abundant and inexpensive energy sources has been the driver of the industrial revolution and still is linked to the well-being of the global economy. But there is concern about a potential energy crisis this century. Pessimists point out that petroleum resources are fixed physical stocks that eventually will be depleted, while optimists view petroleum as a working inventory that is constantly being renewed as it is extracted.
In the case of oil and other hydrocarbons, eventually there will be a maximum peak in production. The question is whether it will occur sooner or later, and whether it will happen because of depletion or because of substitution to other energy sources, perhaps unconventional. Recent work suggests that there are enough hydrocarbons, available at production costs far below current oil prices, for society to substitute alternative sources before depletion becomes a problem. However, the successful transition after peak oil production depends on whether adequate investment in alternative sources takes place on a timely basis. With respect to hydrocarbon availability, the ability of technological advancement to offset the cost-increasing effects of depletion will be fundamental. Temporary shortages might occur because of the lack of spare capacity, cartels, political instability, natural disasters, strikes, a shortage of qualified workers, shortage of refining capacity, and commodity manipulation.

Global Energy Market (GEM) Model
The model presented in this article leads to what we are calling the "2030 1/3 forecast." It indicates that global energy needs will be met by approximately 1/3 liquids, 1/3 solids, and 1/3 gases by 2030. Although the model can be used for forecasting far into the future, it is currently calibrated to a reasonable time horizon, the year 2030.
The pentagon shown in Fig. 1 describes the philosophy of the GEM model, explained primarily with the case of oil. In the center of the pentagon is global population, which has been increasing dramatically since 1950. The top of the pentagon shows historical energy consumption and forecast future energy consumption. The next corner shows the historical and forecast future fraction contributed by each primary energy source. Corner 3 shows actual and forecast consumption rates of each source. The question is whether there are enough volumes of oil, gas, and other resources to supply the rates forecast for the period in this study. This is answered in the next corner (4), which shows estimated energy resource availability by plotting recoverable petroleum volumes vs. the number of recognized petroleum provinces around the world. The final corner (5) of the pentagon shows a cumulative long-run supply curve that presents production costs of the world's recoverable petroleum volumes.
Technology Focus: Wellbore Tubulars (May 2008)
Authors: Baker David A. 
Published: February 2015

Technology Focus
Welcome back to the Wellbore Tubulars feature. Let me begin by stating that once again we have been presented with excellent work in the tubulars area. Of most recent note was the quality work discussed at the 2008 IADC/SPE Drilling Conference. A colleague commented recently on how amazed he was to see the level of fundamental tubulars work (e.g., buckling, collapse, and fatigue). I hope this trend continues.
In 2006, this feature focused on fundamentals, and we still need this level of examination. As applications evolve, we need to know what we can really expect. Just as importantly, we need to step forward with new technologies and to embrace twists on old technologies, or ones that finally have come of age. Last year, this feature looked at technologies that have been taken to the field, and this year, we will look at new technologies for both field and laboratory use.
One of the first avenues we look toward to gain an advantage is use of new materials: We want them lighter, stronger, and more resistant to whatever we can throw at them. Market conditions sometimes drive the consideration of alternatives—titanium and aluminum alloys come to mind immediately for strength and weight considerations. Other application-specific needs may not require material changes. For example, modifications to traditional metallurgies may enhance drilling capability in sour environments or tubular longevity in erosive environments.
Remote sensing also is becoming mainstream. The desire for real-time knowledge about the rock, hole, or tubular condition drives us to new applications of data transmission such as drillpipe telemetry for measurement-while-drilling and logging-while-drilling operations. In addition, we are seeing the growth of fiber optics to collect downhole data during production, not solely for pressure and temperature, but also to assess the mechanical integrity of tubulars. Technology evolution need not be only for field use, but can be of benefit in a laboratory environment as well. A more thorough understanding developed during laboratory evaluation reduces the risk during field installation and use.
Wellbore Tubulars additional reading available at the SPE eLibrary: www.spe.org
SPE 109722 • "Aluminium-Alloy Tubulars—Assessment for Ultralong-Well Construction" by Mikhail Ya. Gelfgat, SPE, Aquatic Company, et al.
SPE 108707 • "Enhanced Steel Alloys Outperform Typical Bottomhole-Assembly Chemistries in Sour-Service Applications" by Alvaro Chan, SPE, Grant Prideco, et al.
SPE 110939 • "The First Offshore Use of an Ultrahigh-Speed Drillstring-Telemetry Network Involving a Full LWD Logging Suite and Rotary-Steerable Drilling System" by H. Wolter, SPE, StatoilHydro, et al.
Overcoming the Weak Link in Cemented Isolation
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 110523, "Overcoming the Weak Link in Cemented Hydraulic Isolation," by N. Moroni and N. Panciera, Eni E&P; A. Zanchi, Stogit; and C.R. Johnson, SPE, S. LeRoy- Delage, SPE, H. Bulte-Loyer, SPE, S. Cantini, SPE, E. Belleggia, SPE, and R. Illuminati, SPE, Schlumberger, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November. The paper has not been peer reviewed.
The full-length paper describes a unique isolation solution based on a responsive cement system with intrinsic self-healing properties that are activated automatically upon hydrocarbon exposure. Activation occurs whenever the integrity of the cement sheath is compromised. The new sealant system rapidly forms a complete barrier by swelling and continues to reseal should further damage occur. The technical advantages of this sealant have been demonstrated through successful field tests.

New Sealant System
In recent years, the well-cementing industry has begun to concentrate on the ability of set cement to provide zonal isolation throughout the lifetime of the well. Even if the cement has been placed properly and initially provides a competent hydraulic seal, zonal isolation could be compromised as a result of changing downhole conditions over the lifetime of the well. Studies have shown that the main causes of cement-sheath damage are stresses induced by varying downhole conditions.
The loss of zonal isolation after cement has hardened can be a result of mechanical failure of the set cement itself or debonding of the casing from the cement or the cement from the formation. Several solutions have been developed and applied successfully in field applications. One current method to improve cement resistance to physical stresses involves the addition of fibrous or ribbon-like materials to increase the toughness of the cement matrix. While these methods increase the resistance of the cement matrix to physical stresses, none of these approaches can accommodate problems that occur once the cement sheath has actually failed and becomes permeable.
The objective of the self-healing cement (SHC) system is to pro-vide long-term zonal isolation with a cement-based system that incorporates self-healing additives. Hydrocarbons activate the self-healing additives whenever the integrity of the cement sheath is compromised (e.g., cracks and micro-annuli), and the cement matrix would seal the leak path through a swelling mechanism.
Application of this responsive sealant targets a wide range of wells to mitigate risks of future cement-sheath degradation through unplanned well events and operations, and to ensure long-term zonal isolation throughout the productive and abandoned periods. The versatile sealant can be strategically placed, from surface to total depth of the well in any string of the well, to provide an effective long-term seal.
Tool Enables One-Trip Completions in Multiple Deepwater Pay Intervals
Authors: Landry Jed , Weiss Stephanie 
Published: February 2015

Technology Update
When designing deepwater wells with long or multiple pay zones, completion specialists face economic and technical problems whose solutions are often in conflict.
Typically, these long pay zones include variations in fracture pressures, permeability, or other reservoir parameters. In trying to stimulate the entire length as one zone, it can be difficult to manage the many stimulation requirements, such as volume, rate, and pressure factors. The result can be poor reservoir coverage and uneconomic production. On the other hand, traditional multizone sandface completions can impair well economics because of the rig time required.
The typical completion of a two- or three-zone conventional, 10,000-ft well takes 10 to 18 days, most of which is nonproductive time (NPT) spent tripping in and out of the well (Turner et al. 2007). For a typical five-zone well in Indonesia, the conventional completion cycle has been estimated at up to 30 days (Delattre et al. 2008).
To address the varied and frequently conflicting problems of completing long- or multiple-pay-zone wells, especially in deep water, a system has been designed by BJ Services for executing gravel- or frac-pack completions over long or multiple intervals in a single trip (Fig 1).

Stimulating Multiple Zones
A reservoir with a large gross pay zone and numerous stress layers is difficult to complete and stimulate effectively as a single interval. Frac packs, in particular, require careful planning to avoid overstimulation, which can breach water zones, or understimulation, which can fail to achieve optimal wellbore-to-reservoir connectivity. Even ordinary gravel packs can be difficult and expensive to execute successfully in multilayer formations.
In reservoirs such as these, the most effective treatment method is to isolate each zone being treated. This is traditionally done by perforating, stimulating, and isolating each zone individually, a time-consuming process with many trips in and out of the well to run and retrieve various tools.
To minimize this NPT for tripping, the single-trip long- and multiple-zone completion tool, called ComPlete MST, combines several traditional tools to enable full flexibility in sand-placement techniques. Thus, positive, selective isolation of all zones can be achieved during completion, stimulation, and production operations.
By this combination of several tools into one, completion time and cost can be reduced by 20 to 60%, depending on well depth, water depth, and the number of zones being completed. Eliminating one-third of a typical completion schedule on a multizone well could save an operator from USD 750,000 to 2.5 million in total cost for this work, based on a USD 250,000 day-rate for the rig. That cost estimate is conservative. Deepwater rig rates have been running at approximately twice that figure in early 2009.
Techbits: Hydraulic Fracturing Potential, Challenges Highlighted in Conference
Authors: Moon Ted 
Published: February 2015

Techbits
A distinguished panel of operating company representatives assembled earlier this year to share their views on how hydraulic fracturing is being applied today, and what challenges must be overcome to achieve further gains. The panelists took part in the plenary session "Hydraulic Fracturing: Think Global But Act Local" at the SPE Hydraulic Fracturing Technology Conference 2009 in The Woodlands, Texas.
Stephen Holditch, Department Head and Samuel Roberts Noble Foundation-endowed Chair in Petroleum Engineering at Texas A&M University, moderated the plenary. He opened with a discussion of the so-called "resource triangle" theory that states that hydrocarbon resources are distributed log-normally in nature, with easily developed conventional reserves—which are a relatively small portion of overall volume—located at the top of the triangle. "As you get deeper into the resource triangle [closer to the base], the amount of unconventional resource plays is tremendous," Holditch said.
A method developed at A&M to evaluate the ratio of conventional to unconventional resources in a basin suggests that there is approximately 10 times more technically recoverable oil and gas from unconventional resources than from conventional reserves. This method was developed from data-rich basins in the US Rockies region, but Holditch is confident that this same ratio should be found in basins around the world.
"We are looking at more basins with this technique, and if the 10-to-1 [unconventional to conventional] ratio holds up, this means there is an enormous amount of unconventional resources yet to be produced around the world," he said. "Technology transfer on techniques such as hydraulic fracturing will be key to unlocking these resources."
Kirk Bartko, Senior Petroleum Engineering Consultant with Saudi Aramco's Petroleum Engineering Support Division, spoke next about his company's stimulation efforts in Saudi Arabia. He said that as of 2006, the country had more than 5% of the world's known gas reserves with 230 Tcf. "Domestic demand is 7 Bcf per day, and by 2025 this is expected to grow to 14 Bcf per day due to increasing industrial requirements and electricity generation," he continued.
Improving Operations Using Model-Based Decision Support for E&P Assets
Authors: Meixell Milo D. , Rodriguez Juan Carlos 
Published: February 2015

Management
Online applications using models of process and utilities plants have delivered benefits to refinery, chemicals, and utilities processes for more than two decades. The scope and objectives of these applications range from monitoring individual equipment performance to closed-loop optimization of operating profit across complex, integrated plantwide assets. E&P operators have historically focused on adding reserves through exploration. This is what drives a company's share price. As a result, E&P operators have not widely embraced the technology available to optimize their existing assets. With exploration opportunities becoming more difficult and costly, optimization of existing assets is a "new" frontier for adding shareholder value.
Early adopters have deployed online models in the E&P business with significant benefit. Technology improvements and experience have now opened up opportunities that allow more widespread and accelerated deployment of real-time, model-based decision support applications for E&P assets. This article outlines where online models can have significant impact on improving several aspects of E&P operations, the technology involved, as well as the approach and best practices necessary for successful deployment and maintenance of these applications.
Most process simulators include configurable models of process equipment including two- and three-phase flash drums (gas/oil separators); pumps; compressors (centrifugal, reciprocating, axial, screw, etc.); drivers such as motors, steam turbines, and gas turbines; heat exchangers; distillation columns; absorbers; strippers; valves; mixers; splitters; piping; and other unit operations. These unit operations can be configured together to model small parts of an E&P asset; a single platform and its processing equipment, or multiple assets interconnected with complex piping networks. It is challenging but now practical to deploy scalable model-based applications which monitor, simulate, and optimize E&P assets in real time in operating environments adding benefits that are appreciable and measurable.
Below the surface E&P assets are addressed by reservoir modeling that shares little in common with the aforementioned process-equipment models. These reservoir models are not practical to use in real time because of lack of real-time data collection, slow reaction to production changes, and their very large computation times. However, practical empirical models of wells are successfully employed along with the above-surface models so that the first-order effects of changing above-surface conditions such as pressures on flows and compositions are taken into account.