bluuebunny/crossref_metadata_2025 huggingface dataset:
Seismic Unwired: Cutting the Cable Can Help in Difficult Spots
Authors: Rassenfoss Stephen
Published: February 2015

Seismic Unwired

David Monk said Apache Corp. uses wireless seismic receivers when it cites advantages over traditional systems connected together by cables.

Examples offered by Apache’s worldwide director of geophysics include a prospect that straddled the border of Argentina and Chile where equipment and radio signals were not allowed to cross; a survey in the shallow waters of the Gulf of Mexico where production platforms would get in the way of streamers used to pick up seismic signals; onshore areas where the cost of crews is high, which is the case in much of the US and Canada; and the Cook Inlet where the extreme environment offshore and onshore made wireless the choice for a number of reasons.

“These things are more efficient systems over more difficult terrain,” Monk said. At the time of the interview nearly all the seismic exploration projects for Apache were wireless.

Eliminating the bright orange or yellow cables reduces the weight of the system, can make it easier to work around obstacles or in difficult waters, and can significantly reduce the profile of seismic exploration in areas where that activity may not be welcome.

A case study by Geospace, a maker of wireless receivers, of a seismic shoot done on the plains of Colombia by Pacific Rubiales Energy Corp., concluded a crew of 21 could lay down the wireless seismic receivers that would have required workers if it had been wired.

And a side-by-side comparison by Apache in the Cook Inlet showed the quality of the seismic data gathered on land was similar for wired and unwired receivers, but wireless performed far better offshore in an area known for its difficult tides and currents.

Apache is a wireless pioneer and is far from the norm in an industry where the largest seismic receiver provider, Sercel, estimates 90% of the seismic channels in use are wired. But the rapid takeoff of wireless receiver sales suggests that is changing.

In most cases one channel, with a geophone that detects the echoes used for underground mapping, is equal to one wireless unit. Wireless multichannel units, though, are a growing part of the market.
Distributed-Temperature-Sensing Method Detects Wax and Optimizes Treatment
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156077, ’Use of Distributed Temperature Sensing for Wax Detection and Treatment Optimization,’ by Manuel Guzman, Brunei Shell Petroleum, prepared for the 2012 SPE International Production and Operations Conference and Exhibition, Doha, Qatar, 14-16 May. The paper has not been peer reviewed.

Distributed temperature sensing (DTS) has been commercially available for more than a decade; however, only recently has it been used in the oil industry. Interpretation of the data has been difficult, and, therefore, its value has been questioned. The author presents an original technique of monitoring wax buildup through the use of the DTS data. Pressure/volume/temperature analysis from an appraisal well showed significant wax content, and DTS provided temperature trends that showed temperature decline in a section of the tubing string. The decline was caused by the additional layer of wax between the crude oil and the gas-filled annulus.

Introduction

DTS has been employed for reservoir monitoring since the 1990s. Application for monitoring on steam-assisted gravity drainage was one of the earlier documented uses. During the last decade, the acquired data have been interpreted for different applications, mainly because of a larger number of installations around the world.

The temperature profile provided for each well in this study has been recorded and is available for evaluation. Nevertheless, current software capabilities allow only qualitative interpretation of the data. Therefore, the time required for monitoring each of the wells is significantly higher than initially expected. Experienced production engineers are required to get the most value out of the large amount of data collected.

During analysis of fluid data from appraisal wells, paraffinic components were identified as part of the crude-oil composition. Several tests were conducted to determine the depositional temperature, and the results showed that wax precipitation could occur along the shallow section of tubing string if the deepest reservoirs were produced alone. However, mixtures of oil from shallow and deep reservoirs reduce the precipitation of paraffinic ends on the tubing string. The field development concept was to produce all four zones simultaneously to minimize wax deposition in the tubing and to install pigging facilities for surface lines.
Reservoir Management for World's First Thermal Gas/Oil Gravity-Drainage Project
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 153967, ’A Reservoir Management System for the World's First Thermal Gas/ Oil Gravity-Drainage Project,’ by Keith Rawnsley, SPE, Augustine Ikwumonu, SPE, Solenn Bettembourg, Pristwanto Putra, SPE, and Ibrahim Al-Ismaili, SPE, Petroleum Development Oman, prepared for the 2012 SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 16-18 April. The paper has not been peer reviewed.

The world’s first full-field thermally assisted gas/oil gravity-drainage (TAGOGD) project has begun in Oman (Fig. 1). Historically, the field was operated at very high water cut because of aquifer influx through the fractures to the producers. The recovery process was a mixture of gas/oil gravity drainage and water/oil gravity drainage, but the high oil viscosity and low matrix permeability prevented recoveries from reaching more than a few percent. To attempt to unlock the oil in place, a TAGOGD development concept has been piloted in the field over approximately 10 years. This led the way to the full-field project that has now begun.

Introduction

Steam, mainly generated by heat-recovery steam generators, is injected into the natural fractures at the crest of the reservoir, and the fractures distribute the steam in the reservoir. As the oil in the matrix is heated, its viscosity decreases by a factor of 100 and it drains down by gravity through the matrix into the fracture oil rim. From there, it is sent to the production facility (Fig. 2).

The field’s life can be divided into two phases. The first phase, now under way, is the transition period during which the oil rim in the fractures is lowered from its position near the top of the reservoir to a position close to the matrix oil/water contact. This increases the oil column height exposed to TAGOGD to more than 100 m. This period is expected to last approximately 2 years, and production is through gas lifted producers, which are wells inclined 45° to intersect fractures.

The second phase is the plateau/tail period, when the oil rim will be maintained at its deep position. Production in the second phase will be through horizontal producers drilled close to the oil/water contact.

Modeling

The thermal gas/oil gravity process will be the first application of the technique at field scale in the world. Modeling, therefore, has taken and will continue to take a more substantial role than it has in more conventional fields, both to build confidence and to act as an interface between the reservoir surveillance data and opportunity generation. The modeling strategy is designed to ensure that predictions are accurate, to capture ongoing uncertainties, and to improve with experience. As more data become available, the understanding will improve, which will be reflected in changes in the modeling strategy.
Emerging Frontiers: Trends in Capability Development
Authors: Spath Jeff
Published: February 2015

President's column

This month I want to discuss what has recently become a very popular topic among both industry and academia—developing our talent. To weather the big crew change successfully, much of the solution surely involves how we instruct petroleum engineering students, how we train young professionals once they join the industry, and how we continually educate experienced engineers to ensure a sufficiently competent workforce. As the recent SBC O&G HR Benchmark Study (Schlumberger 2012) and the 2013 SPE Forum on Engineering Education (Chase 2013) both concluded, the issue isn’t just about the numbers (people shortage), it is about the skills (talent gap).

Digital Education

The way in which we educate at the university level is under revolutionary change in all disciplines, including the science, technology, engineering, and math subjects that feed our industry. Considering that the brick-and-mortar, lecturer-student model has been substantially the same since ancient Greece, it’s probably time for change. The incorporation of technology into this long-established method of teaching over the last few decades has begun to transform education, giving us online courses; “flip teaching,” where students watch video lectures at home and then work problems in class with more personalized guidance from teachers; and blended learning, which combines face-to-face classroom methods with computer-based studies. But the real disruptive innovation, the model that will really save students time and money and grant access to countless pupils in the most remote corners of the planet, is the creation and proliferation of massively online open courses (MOOCs) and teaching online qualified engaged students (TOQUES). They have the potential to transform undergraduate education.

TOQUES, in particular, will likely mark a tipping point: an inexpensive, online curriculum leading to a degree from an accredited institution. Instead of the massive, non-credentialed nature of the MOOCs trend, this new breed of degree programs emphasizes what universities do exceptionally well—teach degree-seeking students through engaging and thoughtful faculty-student interactions but in a truly diverse and global classroom. Unlike MOOCs, where anyone can participate, students must meet all qualifications for admission to the school. TOQUES are evolving and are becoming popular as they knit together education, entertainment, and social networking. Imagine how valuable this could be to our talent-deficient industry, allowing high-quality education to be location-independent and thus helping to solve many countries’ local content issues.

Industry Training

The transformation in teaching undergraduates has extended to industry training as well. Online courses are popular among young- and young-at-heart- professionals who must squeeze continuing education into already hectic schedules. Whether to obtain a graduate degree, a specific certification, or to simply keep up with advancing technologies, online is the way to go and MOOCs are becoming the preferred method.
Comments (April 2004)
Authors: Donnelly John
Published: February 2015

Editor's column - No abstract available.
Leaders are Born, Not Made . . .and Other Popular Myths
Authors: Graf Joanne
Published: February 2015

Management - No abstract available.
Offshore Drilling and Completions: Canyon Express Project Business Challenges
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 15093, "Overview of the Canyon Express Project, Business Challenges, and Industry Firsts," by Frederik Rijkens, Total S.A.; Marcus Allen, Marathon Oil Co.; and Thomas Hassold, BP plc, originally presented at the 2003 Offshore Technology Conference, Houston, 5-8 May.
Reservoir Simulation and Visualization: Coalbed-Methane Reservoir Simulation: An Evolving Science
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 84424, "Coalbed-Methane Reservoir Simulation: An Evolving Science,"by T.L. Hower, SPE, Malkewicz Hueni Assocs. Inc., prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Reservoir Simulation and Visualization: History Matching Using Time-Lapse Seismic
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 84464, "History Matching Using Time-Lapse Seismic," by O. Gosselin, SPE, Total plc; S.I. Aanonsen, SPE, and I. Aavatsmark, SPE, Norsk Hydro; A. Cominelli, ENI; R. Gonard and M. Kolasinski, Total plc; F. Ferdinandi and L. Kovacic, ENI; and K. Neylon, Schlumberger, prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Enhanced Hydrate Inhibition in an Alberta Gas Field
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90422, "Enhanced Hydrate Inhibition in Alberta Gas Field," by Dana Budd, EnCana Corp., and Danica Hurd, SPE, Marek Pakulski, SPE, and Thane D. Schaffer, SPE, BJ Chemical Services, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.

Operating gas wells in southern Alberta poses challenges. High bottomhole pressure in new wells, low bottomhole temperatures, and the Joule-Thompson expansion-cooling effect (which often lowers the gas-stream temperature below the brine freezing point) create conditions favorable for the formation of gas hydrates in wells and transportation pipelines. The problems are aggravated during cold winter months, when wells and pipelines have strong tendencies to plug with hydrates and ice. Systematic laboratory work was undertaken to explore synergistic effects between methanol and low-dosage hydrate inhibitors (LDHIs). A strong effect was discovered at a certain ratio of methanol and low-molecular-weight oligomer-type hydrate inhibitor.

Introduction

Gas hydrates form when water molecules crystallize around “guest” molecules. The water/guest crystallization process occurs at many combinations of temperature and pressure. Light hydrocarbons (methane to heptanes), nitrogen, carbon dioxide, and hydrogen sulfide are the guest molecules of interest to the natural-gas industry. Depending on pressure and gas composition, gas hydrates may build up at any place where water coexists with natural gas at temperatures as high as 30°C. Gas-transmission lines and new gas wells are particularly vulnerable to being blocked with hydrates.

Formation of gas hydrates can be eliminated or slowed by several methods. Thermodynamic prevention methods control or eliminate elements necessary for hydrate formation: the presence of hydrate-forming guest molecules, the presence of water, high pressure, or low temperature. Eliminating any one of these four factors from a system precludes the formation of hydrates. Unfortunately, elimination of these hydrate elements is often impractical or even impossible. For long subsea transmission lines, heating and insulating is a common mechanical solution to hydrate problems. Hydrates will not form if the gas/water system is kept at a temperature greater than the hydrate-formation temperature. Gas dehydration is another method of removing a hydrate component. However, in a practical field operation, water can be economically removed only to a certain vapor pressure, and residual water vapor always exists in a dry gas. Hydrate plugs in “dry” gas lines have been reported.

Adding chemicals to the gas/water streams is the most common method of preventing hydrate formation. Large amounts of alcohols, glycols, or salts are used. These additives thermodynamically destabilize hydrates and effectively lower the hydrate-formation temperature. They function by bonding to water molecules through hydrogen bonds or solvation.
Q&A with John Gibson (April 2006)
Authors: Gibson John , Donnelly John
Published: February 2015

You have been with Paradigm now since April 2005. What changes have occurred at the company since then?

The first three or four months I was here, I was just a director. Then I began to get more excited about what was possible here, and I migrated to being Chairman, then Executive Chairman, and then Executive Chairman and CEO. So I have been in that role about 6 months. What really excited me about the company is that we have tremendous researchers, great scientific products, and an opportunity to make a real difference in the industry with our technology.

The owner, the employees, and I all believe that there is a lot of opportunity for Paradigm, and we have organized ourselves to take advantage of that opportunity. We have made a lot of changes, all in light of trying to grow the company to become the number one provider of high-end tools in the industry. We have brought in a tremendous executive team over the last year. We brought in new sales leadership, marketing and financial leadership, and development leadership. We have made a tremendous number of changes, but at the same time, we had a record quarter for software in the fourth quarter. So it is a case where we think we have taken the wings off the airplane and gotten them back on while in flight without doing any damage to the passengers.

What are Paradigm's leading-edge technologies?

The industry has tremendous data-management solutions for corporate data management that are already in existence, and we see our competitors doing a very good job of supporting multiclient data access. We also see tremendous offerings from competitors in reservoir simulation, and fluid flow and simulation is an area already covered. So you ask yourself, "What is it that really needs focus in the industry?" And that is what Paradigm's strength is. I think that over the next 10 years, you are going to see tremendous advances in geophysics and petrophysics coming together. It is taking microdata at the borehole scale and combining it with macrodata such as seismic and making sure that you have the right correlation and the right attribute model to carry into reservoir characterization. So we are integrating petrophysics and geophysics, which really gives us a leadership position in rock and fluid interpretation.

What is Paradigm's growth strategy?

The industry's move toward optimizing production means that petrophysics becomes a real driver in every decision on every desktop, and we have a leadership position in petrophysics. And when you leverage it with the geophysics, you give the petrophysicists the ability to see across the whole reservoir and the geophysicists the opportunity to incorporate rock and fluid analysis from the borehole. As the industry tries to enhance recovery, to get another 8% or 20% or 2%, it is those two disciplines combined on the front end for interpretation of the rock and fluids in their spatial positions and how they are changing dynamically over time that is really going to bring all of the value in the industry. Our growth will be a result of that becoming the focus.
Overview: Offshore Drilling and Completion (April 2007)
Authors: Gazaniol Didier
Published: February 2015

Just flying over the North Sea, from Stavanger to Aberdeen, is definitely an interesting time to contemplate what the future of offshore drilling could be. Not that long ago, this so-called mature region was seen as declining, and drilling activity was slowly decreasing. In recent months, anyone trying to find an available offshore rig there (as in many other places indeed) knows that this vision of decline must be put aside, and for a long time, he/she will be very cautious with a prognosis about the future.

One thing that probably will remain is the pressure on drilling engineers and drilling teams as a whole to control, or at least mitigate, well costs. Several methods can be envisaged, which might be very different.

Of course, the market could be the first mitigating agent when a new equilibrium point will be reached. But does this industry really function on equilibrium points? And, for instance, is there any ceiling or minimum for deep-offshore-rig rates?

A first means could be to increase pressure on rig efficiency. We have been continuously and successfully improving technology, rig automation, and rig-time management for years. Still, there certainly is room for such improvements, and maybe a stopwatch will be the first driller's tool.

Another means is, of course, based on reducing our needs to the minimum. Even though this method has not always (or not yet) been successful from a business point of view (for instance, the slender-well concept), there are still interesting concepts that someday could introduce real breakthroughs. Some "drilling-from-the-mudline" concepts are probably among them, and the current mood for small-diameter drilling could be part of their success.

Eventually, beyond these cost challenges, new technical challenges also will have to be addressed. Our desire for fossil fuels will lead us to envisage producing such difficult reservoirs that, today, are often produced only onshore (e.g., heavy oils, tight reservoirs, and smaller accumulations). These challenges might once more put pressure on well costs so that, in the end, we may still be running after market equilibrium for a long time.

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

SPE 101080 "Design and Performance Evaluation of an Ultradeepwater Subsea Blowout-Preventor Control System Using Shape-Memory Alloy Actuators" by N. Ma, U. of Houston, et al.

SPE 98894 "Large-Scale Feasibility Determination of Storing and Transporting a Cement Slurry Below Deck Under Maritime Conditions" by D. Doherty, SPE, BJ Services, et al.

SPE 99005 "First Hyperstatic Riser Joint Field Tested for Deep Offshore Drilling" by Y. Poirette, SPE, Inst. Français du Pétrole, et al.

SPE 105649 "CIDS to Orlan: Transformation and Startup of Sakhalin's Ice-Resistant Drilling Platform" by A.M. Higgins, SPE, ExxonMobil Development Co., et al.
Steam Injection in Fractured Carbonate Reservoirs
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 102186, "The Physics of Steam Injection in Fractured Carbonate Reservoirs: Engineering Development Options That Minimize Risk," by G.T. Shahin Jr., SPE, Shell E&P Technology; R. Moosa, SPE, PDO; and B. Kharusi and G. Chilek, Shell E&P Technology, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.

The economic success of the Qarn Alam project depends on the ability to predict steam requirements and oil production. Two key oil-production mechanisms are heat transport through the fractures and into the matrix and gas-cap generation resulting from thermal volatilization of the oil. The process mechanisms involved in thermally assisted gas/oil gravity drainage (TAGOGD) were validated through laboratory experiments, while the field-forecast model results were validated by history matching pilot-performance data.

Introduction

The Qarn Alam field was first brought on production in 1975. When the field came on stream, the net oil production peaked at 6000 m3/d, despite the high oil viscosity. Water breakthrough followed rapidly, and by 1978, net oil production declined and remained low thereafter. During the initial peak in oil production, the oil contained in the highly permeable and pervasive network of fractures was produced and replaced mostly by formation water. After this period, a rim of oil remained, separating the newly formed fracture water/oil contact (WOC) and the newly formed fracture gas/oil contact (GOC). Under primary production, the reservoir produces on average approximately 100 m3/d of 16°API oil, at a 10 m3/m3 gas/oil ratio (GOR).

The purpose of TAGOGD in Qarn Alam is to develop additional oil by increasing the field recovery from 4% under isothermal gas/oil gravity drainage (GOGD) to 27% of original oil in place. TAGOGD is a novel enhanced-oil-recovery development concept that has as yet no full-field analog. Despite the lack of commercial analogs, several field trials have occurred on a pilot scale. Isothermal GOGD in this viscous (220 cp)-oil reservoir is economically unattractive because of the low oil mobility. Reservoir heating by steam injection significantly lowers the oil viscosity to approximately 2 cp, increases the gas cap as a result of thermal vaporization of the oil, and increases the GOGD rate by a factor of approximately 60. This development concept has been piloted in the Qarn Alam field and was found to be economically attractive. The attractiveness of the concept stems from the fact that the dense fracture spacing in the reservoir effectively distributes the steam and is a conduit to collect the oil in the oil rim. This type of development requires significantly fewer wells than an equivalent conventional steamflood.
Intelligently Using Intelligent Completions
Authors: Schorn Patrick
Published: February 2015

Management

Oil and gas producers and service companies have long been committed to recovering more hydrocarbons from fewer wells. This presents a significant challenge, and most in our industry will agree that innovative application of technology is key to addressing it. Today, however, the challenge is even more daunting: to produce more complex hydrocarbon resources economically while continuing to increase ultimate recovery.

In the past, a well's longevity could be prolonged by plugging it back and recompleting it in a shallower pay zone, continuing until all zones had watered out and the well was abandoned. However, engineers realized that in spite of their best attempts, recovery factors averaged only 30%, and often their response was to drill more wells.

Engineers sought new ways to improve recovery while drilling fewer wells using geophysical and reservoir information to guide well placement. More accurate, higher-resolution data reduced interpretation ambiguities and decision risk, and advances in drilling technology allowed wells to be steered into the most prolific portions of the reservoir. Most significantly, the shift from analog to digital data recording enabled integration of information from separate sources. This integration improved knowledge and allowed full field simulation, which in turn resulted in better reservoir understanding and more efficient field development plans.

From Knowing to Doing

Over time, several techniques have been employed to maximize early production and optimize financial returns. However, in the current environment, production rates alone do not define a good project.

Economically improving recovery is perceived as more difficult to achieve than just increasing production. Recovery is highly dependent on completion technology and reservoir management. Completion technology and reservoir management are more likely to succeed when applied on a fieldwide basis, and they both require substantial upfront engineering and investment. Despite the technical challenges, increasing recovery economically is essential to bringing the industry to a new level of success.

As we encounter more complex reservoirs, requiring multiple-zone completions, it is critical to have the capability to modify the downhole completion as production parameters change over the life of the well. The types of completions that can be modified to improve recovery are intelligent completions—combinations of downhole sensors and actuators, plus the software and systems integration to monitor and control individual sections of a well remotely.

In the first applications of intelligent completions, the focus was on single-well flow-control valves with limited monitoring. The economics of such technology limited its use to complex, often subsea, wells with high productivity. Over the course of a decade, however, about 1,200 zones now are producing through intelligent completions.
Comments: Mexico's Challenge
Authors: Donnelly John
Published: February 2015

Editor's column

Four months after major oil reform was approved in Mexico, the country's oil industry is struggling. Oil production in the country—one of the world's top producers and suppliers—peaked in 2003 at 3.46 million BOPD, with the heralded Cantarell field supplying approximately two-thirds of that total. But by February of this year, production had declined by almost a third to 2.64 million BOPD with Cantarell's share dropping to just over 700,000 BOPD.

Located in the Gulf of Campeche, Cantarell is one of the largest oil fields in the world and has been the backbone of Mexico's production strength. Output at the field began in 1979 but gradually declined because of falling reservoir pressure. In 1997, state oil company Pemex began a massive nitrogen-injection project designed to maintain reservoir pressure and reverse the decline. The plan worked and, by 2004, output at the field had doubled to more than 2 million BOPD. But the field soon began to decline again and its faster-than-expected drop may be irreversible. Now, Pemex, as well as the government, which relies heavily on oil revenue, are searching for ways to develop new resources to compensate.

Pemex is seeking outside financing to fund an ambitious investment program. It wants to spend a total of USD 19 billion this year, primarily on upstream exploration and development, and is hoping to maintain overall country production at 2.75 million BOPD and gas output at 65 billion cubic ft/D. Its most promising oil targets are the offshore Ku Maloob Zaap field, where output has grown to 800,000 BOPD—now Mexico's largest field—and Chicontepec, a complex onshore field that currently produces only 145,000 BOPD but has great potential. Pemex plans to drill 1,000 new wells at Chicontepec this year, and also plans to explore more in the deepwater Gulf of Mexico.

Upstream development and Pemex's operations have been hamstrung by the country's constitution, which has all but prohibited private investment in the oil sector since 1938 when the oil industry was nationalized. Significant reforms are now taking place but their success depends on how, and how quickly, the reforms are implemented and whether they will be enough to attract outside investment.

After considerable debate, the government made several key regulatory changes last November, including provisions that reduce Pemex's tax burden, allow the company more oversight of its budget, enhance its ability to raise debt, and give it more flexibility in licensing terms. In addition, four independent members will join Pemex's board, which will create new contract models. Analysts believe that service companies and local firms will find the changes promising, but international oil companies may need more enticement before they invest in Mexico's upstream. Already, the Mexican state oil company has awarded contracts totaling more than USD 5.39 billion this year, a boost for service companies during a year when many companies are making major spending cuts.
Fiber-Optic DTS Flow Profiling Installed in Advanced MRC Well
Authors: Kluth Richard , Naldrett Garth
Published: February 2015

Technology Update

The current decline in crude oil prices has created major interest in methods that significantly reduce overhead and improve efficiency in operations. Distributed temperature sensing (DTS), used for advanced, in-well permanent monitoring, is a technology that can deliver on both of these objectives.

DTS has demonstrated long-term reliability, high performance, and application benefit in a range of production- and injection-well types. An area of particular interest is the application of monitoring in horizontal and advanced well completions. While allowing significant improvements in production and reservoir depletion, these wells have caused data-gathering disruptions for the operators. In particular, the options for performing well logging are much reduced, and the costs of performing a production log extremely high. These factors are related to the costs of both the more advanced horizontal well-logging tools and the more expensive logging methods—such as coiled-tubing and tracker systems—used to convey these tools into the wellbore.

DTS allows this monitoring gap to be closed. In line with advancements in this technology, Sensornet and FloQuest have developed a real-time digital flow-profiling system, which aids increased production, reduces operating costs and improves recovery. Digital flow profiling with DTS is used to determine distributed flow-allocation profiles in production and injection wells. The system combines DTS fiber-optic technology with software modeling and data interpretation (Figs. 1a and b).

The combination of the two technologies enables accurate location of fluid entry points across an entire reservoir. The result is a permanently installed system providing continuous data similar to that obtained from a production-logging tool (PLT), even before the completion is locked down.

The key to obtaining accurate and reliable flow information across the reservoir interval by means of DTS data relies on two principal factors. First, the DTS system must be able to detect very fine temperature changes. (The DTS system discussed here can measure temperature changes of less than 0.01°C at all points along the reservoir.) Second, to extract valuable information from the temperature data, it is essential to combine it with information on the geology, reservoir fluids, and the completion. In the system under discussion, this information is obtained by means of interpreting data from software models.
Techbits: Subsurface Corrosion Spotlighted at Workshop
Authors: JPT staff _
Published: February 2015

Techbits

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

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

Materials for Oil and Gas Production

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

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

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

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 114303, "The Study and Application of Low-Damage and Massive Hydraulic-Fracturing Technique in Tight Gas Formations With High Temperature and High Pressure," by Lei Qun, Tingxue Jiang, SPE, Xu Yun, SPE, Yunhong Ding, SPE, Yongjun Lu, SPE, Cai Bo, Yuhua Shu, and Yaoyao Duan, PetroChina, prepared for the 2008 SPE Gas Technology Symposium, Calgary, 16-19 June. The paper has not been peer reviewed.

Many tight gas formations in the southern Songliao basin in northeast China have high pressure/high temperature (HP/HT) conditions. However, it is very difficult to conduct successful fracturing treatments in the deep wells (deeper than 4200 m) with temperatures greater than 150°C and pressures greater than 60 MPa. A study was conducted to overcome these difficulties.

Introduction

There are many difficulties related to hydraulic-fracturing design and treatment in tight HP/HT gas formations, including formation fines, initiation and propagation of the hydraulic fracture, selection of a low-damage and highly viscous elastic fluid, selection of a high-strength proppant that is transported easily, and that many fracturing-treatment failures result from early tip screenout. The commonly used fracturing technique included ordinary guar fluid with relative high polymer concentration and high residue content; medium proppant size of 20/40 mesh; a common proppant-pumping schedule such as 180, 360, 540, 720, and then 900 kg/m3; and longer shut-in time (at least 2 hours). Consequently, the post-fracturing production rate was disappointing.

Formation Evaluation

For fracturing design, it is critical to understand the targeted formation in both macro- and microperspectives. Macroparameters include sediment, perforation data, permeability, porosity, thickness, saturations, rock mechanics, in-situ stress magnitude and azimuth, and the distribution of these parameters. Macroparameters may be available from drilling, logging, and well-testing data. Microparameters include mineral components and sensitivities of micropore structure such as pore and throat diameter, along with natural fissures and their distribution. Microparameters may be obtained from test data of core samples in the laboratory.

In fracturing-stimulation design, macroparameters may be used to optimize fracture length, conductivity, and proppant selection, while microparameters are used mainly to choose low-damage fluid additives and determine their mixture, optimize use of 100-mesh proppant or any other solids-loss reducers in case of natural fissures, and optimize the time and velocity of flowing back fracturing fluid in case of stress and velocity sensitivity.
Fusion of Engineering and IT Transforms the E&P Business
Authors: Brule Mike
Published: February 2015

Management

The case for information technology’s (IT’s) direct value in E&P has been made for technical computing, real-time monitoring, workflow automation, data integration and quality, unified communications and collaboration, data mining, and artificial intelligence (AI) (Marks 2008; Brulé 2009). But few reservoir and production engineers acknowledge the fundamental need for IT in their everyday activities. E&P leadership abets this attitude with unofficial indifference to IT. The isolation of IT from the core E&P business was demonstrated when SPE held two Americas forums simultaneously, one reservoir engineering-oriented and the other IT-oriented (Shillings 2009). The two forums focused on the E&P business themes of “making better decisions” and “maximizing oil recovery,” but there was little interaction between them.

E&P industry biases weigh against IT. IT has been characterized as “too thin” in E&P engineering and integrated operations (IO), and less relevant as digital oilfield (DOF) formulation moves into DOF 2.0 implementation (Holland 2009). One notion is that “E&P data analyses are different and we do more full-physics modeling than in other industries.” Another is that “we have advanced visualization and enough other technologies.” Further submerging IT below other E&P business concerns, decision-makers tend to focus more on where to explore and drill, and less on using IT to standardize and optimize subsequent operations (Mahdavi et al. 2009). Several case studies of companies outside the oil & gas industry show that when executive leadership mandates that IT be part of the company business model, corporate performance is clearly improved (Weill and Ross, 2009). Yet making IT a central part of the E&P business model is still among the “burning issues” of E&P chief information officers (CIOs).

Different Backgrounds

IT’s lack of familiarity is especially evident in modeling and simulation. A grasp of how to model the behavior of oil & gas systems is normally gained through formal training in math, physics, chemistry, engineering, and geoscience. Most IT specialists are unfamiliar with the basic laws of thermo-dynamics and fluid flow, and “bean-up guidelines for sand-control completions.”

The tables turn when engineers transfer to an IT role without any computer-science training. Few engineers are familiar with IT architecture and governance frameworks such as TOGAF, ITIL, and CMMI, and “idempotent capability in cloud patterns.” Without a sound background in data structures, event-driven architecture, or development platforms, engineers may flounder in software and systems development. In IO and DOF 2.0 efforts, the engineer’s lack of an IT background may also lead them to confuse operations monitoring, control, and visualization vs. complex event processing and predictive analytics (Brulé 2009; 2010). To bridge the gaps between engineering and IT, some universities have begun offering a hybrid “digital petroleum engineering degree” with a dose of computer-science courses (Ershaghi et al. 2009).
Choices for LNG FPSOs
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19884, ’Choices for LNG FPSOs,’ by L.J.F.M. Festen and J.B.P.M. Leo, CB&I Lummus B.V., originally prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May.

An estimated quarter of world gas reserves currently is stranded in offshore gas fields. The energy markets and dwindling oil reserves highlight the necessity to find new ways for offshore gas production. Liquefied-natural-gas (LNG) floating production, storage, and offloading (FPSO) vessels will be required to develop the fields that are too far from market for pipelines or are in extreme water depths. Despite many design studies, technical and economic constraints have prevented LNG FPSOs from being developed as fast as oil FPSOs.

Introduction

More than 20 years of development work has been performed on LNG FPSOs, but apparently there are challenges that have prevented the realization of such a project even with rising gas prices. Both the organization of the project and the actual design of an LNG FPSO are considerably more complicated than those of an oil FPSO. The full-length paper discusses the choices to be made during selection and design of a project on the basis of many years of development work.

Table 1 in the full-length paper lists the main parts of an LNG FPSO where choices have to be made. For an offshore facility, the interdependence of the choices is much stronger than onshore because of the limited plot area on an FPSO. 

Selection of Gas Field and Pretreatment

The design of the LNG FPSO begins with the selection of the gas field to be developed and the intended market for the LNG. The higher-heating-value (HHV) specification for the LNG together with the hydrocarbon part of the feed-gas composition determines the natural-gas-liquids (NGLs) separation.

A very rich gas (i.e., high C2, C3, C4, C5+ content) and a market that requires lean LNG will require a pretreatment process that also produces liquefied petroleum gas (LPG) and condensate. The leaner the LNG specification, the more NGLs that have to be separated. When the mol ratio of methane to ethane in the feed gas is lower than 14 to 11, it becomes very difficult to produce a lean LNG specification with HHV less than 1,070 Btu/scf unless ethane is produced as a separate product. Producing a fourth product, liquid ethane, is rather improbable for an FPSO.
Combining Wireline and LWD Borehole-Seismic Data for Drilling an HP/HT Well
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 13083, ’Combining Wireline and LWD Borehole Seismic Data for Drilling an HP/HT Well: A Novel Approach,’ by T.K. Lim, SPE, and Aqil Ahmed, SPE, Schlumberger, and Gunawan Taslim and Muhammad Antonia Gibrata, SPE, Petronas, prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December.

An integrated borehole-seismic technique was used to access and mitigate drilling risk on a high-pressure/high-temperature (HP/HT) exploration well offshore Sabah, Malaysia. The approach combined wireline vertical seismic profiling (VSP) with logging-while-drilling (LWD) seismic surveys to predict pore pressure, determine geo-stopping, and obtain high-resolution seismic imaging beyond the well path. This high-resolution image was used to select the sidetrack path. The final rig-source VSP was logged at total depth (TD) to complement the pore-pressure prediction and seismic imaging.  

Introduction

Integrating wireline and LWD bore-hole-seismic information for drilling is a new technique in Malaysia. In this approach, borehole-seismic data, which are used conventionally for geologic and geophysical interpretation, have added value for drilling and well planning.

The well, drilled in 2008, is off the coast of Sabah, East Malaysia. The target reservoir, in contrast to most other reservoirs in the region, is deeper, hotter, and at much higher pressures than normal. Pore-pressure ramps and depleted sands in the field had made drilling difficult previously, generating hazardous incidents including stuck and in-hole-lost pipe, fluid losses, and kicks. These incidents had resulted in stopping drilling prematurely, resulting in ultradeep targets remaining unexplored. Studies by the sedimentologist suggested that this overpressure hazard is associated with undercompacted bathyal mudstone, and the well-casing design required accurate prediction.

The well path was designed to avoid the regional fault that could complicate pore-pressure prediction. Existing surface-seismic and distant-well-based velocity control were inadequate for this purpose.

Primary well objectives were the lightly explored, stacked, lowstand Upper Miocene turbidite-reservoir sequences. The deepest of these were expected to be at approximately 4000- to 5000-m sub-sea (SS) depth. The shallow units, which are depleted because of production from other locations, were at approximately 2500- to 4000-m SS depth.