bluuebunny/crossref_metadata_2025 huggingface dataset:
Interactive Log Simulation and Inversion on the Web
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90909, "Interactive Log Simulation and Inversion on the Web," by V. Polyakov, SPE, T. Habashy, R. Kocian, J. Pabon, and B. Anderson, SPE, Schlumberger-Doll Research, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.

Log simulation is critical for understanding and interpreting logging-tool responses. Simulation helps the log analyst understand near-wellbore measurements in complex environments, particularly in anomalous situations. Simulated logs also can be used in “what-if” scenarios or as part of an iterative scheme to determine the formation’s geometry and material properties. A forward-modeling and inversion environment with a multitier Web-based architecture was developed to provide universal access from the user’s desktop, through a common Web browser, to the simulator engine running on a high-performance compute server.

Introduction

The essence of log interpretation is the solution of the inverse problem: determining formation parameters from logging data. This task becomes difficult when the logging environment departs from simple, well-understood geometries. Many tools are designed to make deep-reading measurements and, therefore, are susceptible to formation heterogeneities. The most com-mon environmental effects are formation dip, invasion of borehole fluids, and the influence of adjacent formations. Frequently, a combination of these effects can obscure the true formation properties (e.g., formation resistivity and porosity), making it necessary to construct a complex 3D model of the formation to obtain an accurate solution. The only way to validate these complex models is by tool-response simulation, or inversion.

Some logging tools (such as dual induction and dual laterolog) do not provide sufficient information to perform accurate inversion. Iterative forward modeling of what-if scenarios is used routinely in these cases. Iterative modeling simulates the exact tool response in a series of given formations. However, this process requires a high level of user interaction. The initial formation model must be constructed from log, core, and geological information, then updated manually. A solution is reached when a computed log matches the field log.

Automated inversion is more efficient because no interaction is required after the simulation is launched. During the past decade, the introduction of array measurements with greater information content has made it possible to use inversion in log interpretation routinely. Some modern tools record so much data that interpreting their response without the use of inversion presents a considerable challenge.

The interactive Web-based interface provides a convenient and universal user access to the forward-modeling and inversion software. Also, the Web-based-programming interface makes the simulator available as a library for other oil and gas applications.
Guest Editorial: Canadian Oil Sands - Myth and Reality
Authors: Tertzakian Peter
Published: February 2015

Was M. King Hubbert, the famous American Earth scientist, really the first visionary to talk about peak oil? Indeed, many regard Hubbert as the Nostradamus of the oil industry, with his 1950s analytic work on peaking oil production part of any discussion about world oil supply today. But on the other side of the Atlantic Ocean, John Cadman was an oil oracle too, predating Hubbert by 30 years. Though Cadman's thoughts about the future of oil were more qualitative, we are witnessing his important prophecies today. In the end, Hubbert's numerical analysis and Cadman's astute foresights go hand in hand.

A geologist by training, Cadman eventually became Chairman of Anglo-Persian, the predecessor company to British Petroleum, which has evolved into today's BP. Accepting the Chairmanship of Anglo-Persian on 2 November 1927, Cadman said in his inaugural address, "Very many years must elapse before natural petroleum resources will be unable to meet the greater part of the world's requirements. Of course, the time will eventually come when the world may have to look for a great part of its supplies from secondary and synthetic sources."

Fast forward 80 years. Enough time has passed to have seen many of the world's prime hydrocarbon reservoirs mature. Big oil exploration has gradually migrated from the easy geographies of Pennsylvania and Texas to the deep offshore waters of the Gulf of Mexico. Internationally, megascale oil projects today are found in places such as offshore Africa, the offshore Arctic waters of Russia, or many other places that are at what I call the "ends of the Earth"—geographically extreme places where the oil is buried deep under water and rock. In addition, a lot of oil is buried under deep layers of authoritarianism, corruption, civil strife, and geopolitical intrigue.

On the demand side, the President of the United States has acknowledged that the United States is "addicted" to oil. But the addiction does not end at the U.S. border; the craving for oil is global. Using Cadman's phrase for consumption: "The greater part of the world's requirements" is now a thousand-barrel-a-second oil dependency that is growing relentlessly year after year.

So, the time has come. The world's requirement for more and more oil is taxing the industry's ability to supply it easily. We have finally reached Cadman's point of transition, where the world needs to look for a great part of its oil supplies from "secondary and synthetic sources." Where is this happening on a big scale?
Discussion and Reply to "Advances in Polymer Flooding and Alkaline/Surfactant/Polymer Processes as Developed and Applied in the People's Republic of China"
Authors: Seright R.S. , Chang H.L. , Zhang Z.Q. , Wang Q.M. , Xu Z.S. , Guo Z.D. , Sun H.Q. , Cao X.L. , Qi Q.
Published: February 2015

In the February 2006 issue of JPT, H.L. Chang et al. reported on some of the pilot and commercial-scale field activities of polymer flooding and alkaline/surfactant/polymer (ASP) flooding that were performed in China (Chang et al. 2006). Unquestionably, polymer flooding and ASP flooding are proven processes, and China should be proud of their work in these areas. Unfortunately, the article also advocated a controversial technology [flooding with aqueous colloidal-dispersion gels (CDGs)] as being superior to polymer flooding. I submit that this claim is misleading and generally incorrect. CDGs [i.e., relatively low concentrations of partially hydrolyzed polyacrylamide (HPAM) crosslinked with aluminum citrate] should not be applied without carefully examining the purported science and engineering behind this process.

Chang et al. speculated that low-concentration aluminum citrate/HPAM microgels propagate through porous rock like superpolymer solutions. Specifically, they suggested that these CDG formulations penetrate deep into porous matrix reservoir rock and subsequently provide higher resistance factors (effective viscosities in porous media) and residual resistance factors (permeability-reduction factors) than comparable HPAM polymer solutions without cross-linker. However, independent results from three university research laboratories demonstrated conclusively that this assertion is not correct (see Seright 2006 and Wang et al. 2006 for details). Another assertion made in the February article (Conclusion 3 on page 87) is that "a large amount of CDG would preferentially enter the high-permeability or thief zones and divert polymer or water into medium- and low-permeability zones." This assertion contradicts basic calculations with Darcy's law (Seright 2006). Furthermore, the field evidence given to support CDG gels can readily be attributed to other, more plausible, factors. In many cases, questions arise whether the aluminum citrate had a positive effect on the field results. More details can be found in Seright 2006 and Wang et al. 2006.
Q&A with Kenneth E. Arnold, Senior Executive Vice President, AMEC Paragon
Authors: Arnold Kenneth E. , 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.

When and why did you join SPE?

I came to SPE rather late in life. I am a facilities engineer by background, and most of the time in my early career at Shell I associated SPE with drilling and production and reservoir engineering. But, on the other hand, I was aware that SPE existed, and I became aware that there was information being published in JPT on facilities-related topics, most of it probably associated with the Offshore Technology Conference. The other thing that I was aware of was that facilities engineers were treated almost like second-class citizens in the oil industry in those days. The emphasis in career development was on people who had downhole and drilling experience, rather than people who had project and surface experience. In those days, facilities were not very big or very expensive; they were a small part of the overall development cost. Therefore, it was easier to get ahead if you were a downhole specialist rather than a project specialist.

I got to thinking that, since my bosses belonged to SPE, it would be a good idea for me to belong as well. There was really no technical society for facilities engineers. There were other societies that you could belong to, but they were not really focused on providing the kind of information exchange that facilities engineers needed. It looked like the only logical place for facilities was within SPE.

What was your first involvement with the Society?

My first activity was as a technical editor, doing peer review of papers that were facilities-oriented. There were not that many of us who had the capability of reviewing these papers, so it started very slowly. In the early 1980s, Roger Hite, who was with Shell at the time, had done a quick study and determined that there were a lot of facilities engineers at Shell but none of them belonged to SPE. So SPE put together an ad hoc committee on facilities engineering to try to determine if this was something that SPE should worry about, and I served as Chairperson of that committee. We discovered that about 25% of the engineers within the oil companies represented on the committee were facilities engineers, so, basically, we were not providing much service to this group.
Adco ESP Pilot
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 101492, "Adco ESP Pilot," by H.A. Hashim, Adco, prepared for the 2006 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 5–8 November.

Adco's experience with electrical submersible pumps (ESPs) in deep, high-temperature, and high-gas/oil-ratio (GOR) wells has been discouraging. To ensure that future ESP applications in Adco's mature fields are successful, a comprehensive review was conducted to determine the causes of the previous failures and recommend methods to improve current practices. A multidisciplinary team was created to plan and execute an ESP pilot project. The result of this effort was the successful installation and operation of ESPs in two of the field's oil wells.

Introduction

The field is in southeast Abu Dhabi and was discovered by a seismic survey conducted in 1959. Crude oil from the reservoir is 42°API with an 850-scf/STB GOR. The reservoir temperature is 250°F. The field has been waterflooded for more than 25 years, resulting in a long history of producing wells ceasing to flow when the water cut reaches 40 to 60%. The long-term solution is to put these wells on artificial lift (AL) such as gas lift (GL) or ESPs.

The slow increase in water cuts will change to a much more rapid increase upon fieldwide implementation of the first phase of AL scheduled in 2009. Although GL is seen as the preferred AL method for the field, ESPs could be used as a secondary method.

An initial step to the fieldwide AL implementation was to plan an ESP trial with the objectives of restoring production and accelerating data acquisition on well and reservoir performance at higher water cuts to refine field-development plans.

The wells selected for the ESP project were three oil producers that had ceased to flow because of a high water cut. Because of mechanical-integrity problems with one of the wells, only two ESPs were installed.

Adco ESP Review

Although ESP performance in water-production wells and shallow oil wells is impressive, performance in deep and high-temperature oil wells has been beleaguered by a number of premature failures. To ensure that future ESP applications in these fields are successful, a comprehensive review was conducted to determine the causes of the previous failures and incorporate the findings into new designs and procedures for the pilot tests.

After analysis of the past ESP experiences, the review team agreed that all past failures could have been prevented if attention had been paid to detail. The failures in the past were primarily the result of wellbore pollutants and debris; poor manufacturing, quality assurance, and quality control; and installation practices.
Dope-Free Connections: A North Sea Case Study
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105851, "Dope-Free Tubular Connections, Through Research and Development to Field Trial and Implementation: A North Sea Case History," by H.B. Andersen, M.P. Hummer, SPE, and R.C. Engell, SPE, Mærsk Oil, and Lionel Verdillon and Arnaud Parde, Vallourec & Mannesmann Tubes, prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20–22 February.

After an initial development period, a final dope-free product was ready for testing. A waxy compound is applied directly on selected premium threads, serving as both storage and running dope, eliminating requirements for cleaning and redoping at the wellsite. The decision was made to perform a field test.

Introduction

Mærsk Oil operates offshore wells in the Danish sector of the North Sea, which are characterized by being long horizontal wells (5,000 to 20,000 ft) drilled in chalk reservoirs. The wells commonly are completed with 4 1/2- or 5 1/2-in. completions inside a 7-in. liner hung off in a 9 5/8-in. production casing set just above the reservoir. In some cases, the liners are cemented in place to provide zonal isolation.

Field Trial

For the field test, 230 joints of 7-in., 29-lbm/ft liner with premium dope-free tubular connections (DTCs) were acquired. All joints were equipped with standard open-ended driftable protectors. The 7-in. liner was selected for the test because it would have the least effect on final well performance if it turned out the DTCs did not perform as expected. The decision was made to use two wells, one of which had a cemented liner so the pressure integrity of the connections could be tested.

Manufacturing Trial Order

The 230 joints for the test were produced in February 2002. In the plant, the dope-free layer was applied on connections manually before mill makeup. As expected, no major difference was found at the coupling makeup stage when compared with standard American Petroleum Inst. (API) modified mill makeup. The 230 joints were shipped to the offloading facilities in Esbjerg, Denmark, where pipes were stored until shipped to the North Sea offshore rig in March 2002.

Rig Deck

The pipes were received at the rigsite bundled in slings. On the deck, they were laid out in one layer at a time. For the field trial, the protector design did not allow the pipe to be tallied with protectors installed; consequently, these were removed and the pipe was tallied. The pipe was drifted with the protectors reinstalled. Drifting the pipe with the protectors installed ensures that no pipe scale or other debris pollutes the box-end threads during drifting. Drifting pipe without DTCs normally is done before cleaning the thread so drift debris in the thread is not an issue.
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.
Trials and Tribulations of a Long-Reach Well in Deepwater GOM
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 118705, "Trials and Tribulations of a Long-Reach Well in the Deepwater GOM," by Ron Day, Ramsey Fisher, SPE, and Louise Jacobsen Plutt, SPE, BP plc, and Nesny Pardo, SPE, Segun Jebutu, SPE, and Hans-Christian Freitag, Baker Hughes, prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed.

For deepwater offshore areas with irregular water-bottom topography, subsea infrastructure above the field often can be limited. Access to reservoir targets becomes constrained, particularly when drilling challenges exist above the reservoir, such as pressure ramps or layers with unstable lithologies. Long stepouts can be required. Strategies implemented to drill and access reservoirs successfully in a large faulted anticline in the deepwater Gulf of Mexico (GOM) are presented.

Introduction

Discovered in 1998, the subject field is in the Green Canyon protraction area of the GOM in a water depth of 6,800 ft. The main reservoir targets are stacked oil-bearing turbidite sands at a depth of approximately 9,800 ft below the mudline. As shown in Fig. 1, the field is a large faulted anticline 11 miles long by 4 miles wide. Development is complicated by shallow salt fingers that obscure seismic imaging of the north flank of the structure and create a complex water bottom across the middle of the field where water depth changes 2,200 ft across a 1-mile width. Because of this lack of clarity on the northern flank, the south flank of the field was developed first from a central drill center, designated as Drill Center One (DC1).

Drilling Challenges

Well U was the sixteenth penetration in the field. Like all development wells drilled from DC1, Well U had three strings of casing (36-in. surface casing set approximately 200 ft below mudline; 26-in. conductor casing set at approximately 1,200 ft below mudline; and 20-in. casing set at approximately 2,300 ft below mudline) set during the 2004 batch-set operation. However, Well U, would need to mitigate three main drilling challenges in its remaining 17×20-in., 14 3/4×16 1/2-in., and 12 1/4-in. hole sections. First, Well U would need to navigate through a 1,000-ft-thick laminated and thin-bedded sand, which had caused severe lateral vibrations to the drilling assembly in previous wells, making directional control difficult and occasionally leading to downhole-assembly failures. As a result, vibration management became crucial in drilling the 14 3/4×16 1/2-in. section in one trip. An additional complication in the 14 3/4×16 1/2-in. section was that it would reach total depth in a pressure ramp, which could contribute to borehole instability.
New Technology Applications for Improved Attic-Oil Recovery: Slim Smart Completions
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 12365, "New Technology Applications for Improved Attic-Oil Recovery: The World's First Slim Smart Completions," by Stig Lyngra, SPE, Abdulkareem M. Al-Sofi, SPE, Uthman F. Al-Otaibi, SPE, Mohammed J. Alshakhs, SPE, and Ahmad A. Al-Alawi, SPE, Saudi Aramco, prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed.

Smart completions, passive inflow-control devices (ICDs), and maximum-reservoir-contact (MRC) wells are some recent technologies used to enhance recovery and extend the life of mature oil fields. In a Saudi Aramco field, one challenge was to maximize production from the inadequately swept attic-oil zone. Since 1995, new technology has improved oil recovery from this thin attic-oil zone. Technology deployments included recompletion with short-radius-horizontal (SRH) sidetracks, single-lateral re-entry sidetracks equipped with passive ICDs, and multilateral MRC wells equipped with intelligent completions. A slim smart completion (SSC) was run in a multilateral sidetrack enabling production optimization and control of individual laterals.

Introduction

This field in Saudi Arabia was discovered in the early 1940s. A pressure-support program was started after 8 years of primary depletion. During a 24-year period, the produced solution gas was reinjected as part of the reservoir-pressure-support program.

Gas injection was into the primary reservoir at the crest of a high-relief dome feature. A flank water-injection program was started in the mid-1950s, and it became the main field pressure-support mechanism.

After more than 60 years of production, approximately 57% of the oil initially in place in the primary reservoir has been produced. Still, the field water cut has remained less than 35%. The absence of vertical barriers, relatively long distance from injector to first-row producers, and managed production offtake have allowed gravity to play the primary role in the recovery process.

The main-reservoir permeability distribution (higher permeability toward the top, excluding the top 25 ft) allowed oil production from the top section while gravity drainage occurred in the lower, poorer reservoir section. As a result, water production has been very limited. The normal production practice during the first 34 years was to shut in any producing well with crude samples containing salt.

Attic-Oil Target Zone

The attic-oil section is approximately 25 ft thick. Saturation logs run in 2007 in wells very close to flank injectors indicated that this interval is at original oil saturations. Fig. 1 is a schematic showing the main layering of the attic-oil interval.
The Quadruple Bottom Line (June 2004)
Authors: Baker Kate H.
Published: February 2015

President's column - No abstract available.
Why Delay the Advances of Oilfield Technology?
Authors: Middleton Charles K.
Published: February 2015

Guest editorial - No abstract available.
Q&A with Art Huffman, Baroid Drilling Fluids
Authors: Huffman Art , Donnelly John
Published: February 2015

Q&A - No abstract available.
Wellstream Booster Solution for Deepwater and Ultradeepwater Oil Fields
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 16447, "An Efficient Wellstream Booster Solution for Deepand Ultradeepwater Oil Fields," by Eivind Birkeland, Kvaerner Oilfield Products A/S; Jo Jernsletten, Kvaerner Process Systems A/S; Geir Olsen, Kvaerner Oilfield Products A/S; Jan Gunnar Waalmann, Aker Kvaerner Engineering and Technology A/S; and Knut Nyborg, Kvaerner Oilfield Products A/S, prepared for the 2004 Offshore Technology Conference, Houston, 3-6 May.
Active Heating For Flow-Assurance Control in Deepwater Flowlines
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 15188, "Active Heating For Flow-Assurance Control in Deepwater Flowlines," by Khlefa A. Esaklul, Gee Fung, Gary Harrison, and Ron Perego, BP America, prepared for the 2003 Offshore Technology Conference, Houston, 5-8 May.
Coiled-Tubing Underbalanced Through-Tubing Drilling
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 87146, "Basis of Design for Coiled-Tubing Underbalanced Through-Tubing Drilling in the Sajaa Field," by P.V. Suryanarayana, SPE, Blade Energy Partners; Bruce Smith, SPE, BP plc; ABM Hasan, SPE, Blade Energy Partners; and Charlie Leslie, SPE, Richard Buchanan, and Randy Pruitt, SPE, BP plc, prepared for the 2004 SPE/IADC Drilling Conference, Dallas, 2-4 March.
The First Coiled-Tubing-Deployed ESP in the Gulf of Mexico
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 89300, "The First Coiled-Tubing-Deployed ESP in the Gulf of Mexico," by R.G. Keck, SPE, BP plc; S.W. Robertson, SPE, BJ Services; D.J. Butler, SPE, Centrilift; and D.B. Bumbaugh, SPE, BP plc, prepared for the 2004 SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, 23-24 March.
Overview: Heavy Oil (June 2004)
Authors: Gurfinkel Mariano
Published: February 2015

Overview - No abstract available.