bluuebunny/crossref_metadata_2025 huggingface dataset:
Overview: Multilateral/Extended Reach (July 2007)
Authors: Mason Colin
Published: February 2015

ExxonMobil recently announced a new world record for extended-reach drilling at its Chayvo development on Sakhalin Island. This achievement started me thinking: How can exceptionally long wells be drilled and completed in some areas but not in others? The answer to this question is highly complex and is driven by a large number of interdependent variables. Assuming that a drilling rig large enough to supply the required mechanical and hydraulic loads is available, essentially what remains is the nature of the subsurface environment. Usually, it is this factor that holds the key to understanding whether extended-reach-drilling techniques will be viable. Therefore, the use of fit-for-purpose drilling practices and deployment of technology also play a vital role.

The key challenge, therefore, is to understand the complexity of the subsurface environment and its compatibility with extended-reach-drilling techniques. Information on rock type and strength, field-stress orientation, pore pressure, fracture gradient, fractures and faulting, and bedding planes helps form a representation of subsurface risks. Developing a workable and relevant definition of subsurface complexity, applicable to extended-reach wells, would be of high value to the industry, but it would likely be a nontrivial exercise.

By comparison, the multilateral community developed the Technical Advancement of Multilaterals (better known as TAML) classification system that accounts for the complexity of a junction as well as the well type and junction description. In this case, there appears to be a good correlation between complexity and degree of difficulty of successfully installing the junction.

Looking to the near future, the potential is immense for downhole broadband technology to telemeter wellbore conditions continuously in real time together with the use of sophisticated interpretative techniques. This technology could well be an enabler for effective delivery of the industry's most challenging wells.

Multilateral/Extended Reach additional reading available at the SPE eLibrary: www.spe.org

SPE 104623 "Application of Novel Technology Improves Drilling Performance in Multilateral Field Development Offshore West India—Reducing Risk and Increasing Production" by Anil Jaggi, SPE, BG Group, et al.

SPE 105715 "Drilling and Completing Intelligent Multilateral MRC Wells in Haradh Inc-3" by Fahad Al-Bani, SPE, Saudi Aramco, et al.

SPE 104192 "Transport of Small Cuttings in Extended-Reach Drilling" by Mingqin Duan, University of Tulsa, et al.
Innovative Chemical and Mechanical Processing for Treatment of Difficult Production-Waste Sludge
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 105584, "Application of Innovative Chemical and Mechanical Processing for Treatment of Difficult Production-Waste Sludge," by Jacquelyn F. Star, Chevron; Stephen Williams, SPE, M-I Swaco; Isham Sudardjat, Chevron; Roger Kidder, M-I Production Chemicals; and Darrell L. Gallup, SPE, Chevron, prepared for the 2007 SPE E&P Environmental and Safety Conference, Galveston, Texas, 5–7 March.

East Kalimantan field in Indonesia has experienced challenges in managing and treating emulsions, slop oils, slurries, and tank bottoms that accumulate in process vessels and tanks. Previous disposal methods did not provide oil recovery and posed severe environmental or regulatory problems. A viable treatment process that uses an aggressive system of heat, customized chemical demulsification, settling, and various means of mechanical/centrifuge separation was developed and put in place. The system recovered more than 40,000 bbl of oil.

Introduction

Oil and gas producers in the Kutei basin of east Kalimantan, Indonesia, have had difficulties in the management of slurries, slops, and sludges accumulated in process vessels and storage tanks. Unresolved production byproducts, collectively termed sludge, have strong oil/water emulsions, chemically bound by naturally occurring soaps and various mixtures of stabilizing fine sand, scale, and wax. These various production wastes can be exceptionally challenging to treat and recover.

Treatment and reclamation of more than 317,000 bbl of tank sludge from the Santan secondary-impoundment-area (SIA) pit from August 2004 through September 2005 targeted the following:Treat the sludge with 100% efficiency, converting the waste to oil, solids, and acceptably clean water.Treat the sludge and close the pit as quickly as possible.Maximize oil recovery and reduce overall treatment costs.Develop a safe, environmentally superior process for sludge treatment that could be considered the standard for best practice for subsequent operations.

Background

Santan terminal has been receiving, processing, and storing oil and gas from offshore shelf fields for approximately 30 years. Because of chemistries unique to the Kutei basin of east Kalimantan, production fluids have a tendency to form a type of carboxylic soap, leading to strong emulsions of the oil and water phases. These emulsions can be further stabilized by fine scale, formation flour, and wax. With enough solids entrainment, these emulsions can sink, creating a mud-like sludge.

It is estimated that unresolved emulsions are dumped to the water plant at a rate of up to 400 B/D (where they are pumped to a designated sludge tank) or are deposited into the storage tanks. This sludge waste represents more than 40,600 bbl of oil in the SIA.
Comments: Price Drivers
Authors: Donnelly John
Published: February 2015

Editor's column

Two reports released last month help explain the dramatic rise in oil prices this year. The price of Brent, the world's dominant marker crude, has almost doubled in the past year and is up more than 40% since the start of this year. The weak dollar, the flow of money from other financial sectors to oil, and geopolitical blips may be responsible for some of the increase, but the real reason appears to be the basic fundamentals of supply and demand.

The 57th edition of BP's annual Statistical Review of World Energy shows a global market tightly balanced, with little room for error. Last year, global oil production fell by 0.2%, the first decline in world output since 2002, while consumption increased 1.1%. World production decreased 130,000 BOPD to 81.53 million BOPD. OPEC production cuts accounted for some of that drop, but output in OECD countries fell 300,000 BOPD, reflecting aging oil fields. Some of the world's major oil provinces are posting production declines—including the North Sea, Russia, and Mexico—and may continue to fall. North Sea output has been declining since 1999 and Mexico's giant Cantarell field is in rapid decline. During this year's Offshore Technology Conference, Pemex Director General Jesús Reyes-Heroles acknowledged that the company's objective of maintaining crude output at 3.1 million BOPD through 2012 will be severely tested by the challenge to compensate for Cantarell's decline.

Demand grew by approximately 1 million BOPD, according to BP's review, with consumption strong not only in Asia but in large oil-exporting regions such as the Middle East, South America, and Africa, which could limit exports to major consuming centers. Consumption growth slowed last year, due to weaker economies and higher prices, but was still above the 10-year average for the fifth year in a row. Oil prices have risen for 6 years in a row, the longest period of rising prices on record, according to BP, and are certainly on track to finish the year higher again.

Similarly, the International Energy Agency's (IEA) most recent report notes lower global consumption than previously forecast, but predicts demand this year rising to almost 87 million BOPD, about 1% higher than last year. The IEA also revised down its estimates of non-OPEC production for this year, bad news for a tight global supply balance. Demand from developing countries continues to rise, which has pushed the energy sector into a whole new realm, according to Lane Sloan, a longtime Shell executive and author of the new book, Terra Incognita: A Navigation Aid for Energy Leaders. The population of China and India together is 2.4 billion, compared to the OECD population of 1.2 billion, and those nations are going through the industrialization process that OECD countries went through last century. As historian Daniel Yergin has noted, of all the interesting characters in the history of the oil industry, perhaps the two most significant are supply and demand.
Innovations for Deepwater Jubarte Heavy Oil
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19083, "The New Deepwater Oil and Gas Province in Brazil: Flow Assurance and Artificial Lift: Innovations for Jubarte Heavy Oil," by Giovani Colodette, Carlos A.G. Pereira, Cezar A.M. Siqueira, Geraldo A.S.M. Ribeiro, Roberto Rodrigues, Joao S. de Matos, and Marcos P. Ribeiro, Petrobras, originally prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.

The full-length paper presents a review of the artificial-lift (AL) and flow-assurance challenges faced in the exploitation of Jubarte heavy oil, starting from the features of the Pilot Phase. The challenges posed and innovations proposed and implemented for Phase 1 field development, as well as expectations for the subsequent Phase 2, are detailed.

Introduction

The Jubarte field is in the north part of the Campos basin, approximately 80 km offshore from the state of Espírito Santo, at a water depth between 3,280 and 4,922 ft. The field discovery occurred in January 2001, when an interval containing 17°API oil was identified in sandstones of Maastrichtian age.

During the evaluation phase, a study based on the concept of value information supported the decision to drill a horizontal appraisal well. In February 2002, the well was drilled, with a 3,510-ft horizontal length, and was completed with an openhole gravel pack. The result was a well productivity index (PI) 13 times greater than the PI obtained with the vertical well. An extended well test (EWT) was proposed and approved. In the EWT, which started in October 2002, Petrobras made use of the floating production, storage, and offloading (FPSO) vessel Seillean, a dynamically positioned vessel with a rig capable of performing light workover operations. The well was connected to the FPSO through a 5 5/8-in.-inside-diameter drillpipe riser. Using an innovative solution, a 900-hp, 25,000-B/D-capacity electrical submersible pump (ESP) was installed above the wet tree. In case of ESP failure, the drillpipe riser could be recovered by the FPSO for pump retrieval and replacement. The good results obtained in the EWT led to its continuation in a Pilot Phase, which lasted until January 2006.

After the Pilot Phase, the Jubarte Phase 1 production was started with the FPSO P-34. This new development phase comprises four production wells, and a 60,000-B/D oil-production rate is expected. One of the wells represents an innovative installation of the ESP on the seabed, another well has a downhole ESP installed, and the remaining two wells produce with gas lift (GL). GL backup can be used in the ESP wells while awaiting repair in case of pump failure.

The ultimate Jubarte production system (Phase 2), to be implemented in 2011, will comprise 11 new wells plus the four wells from Phase1, and seven water-injection wells, connected to the FPSO P-57. During this production phase, all production wells will run ESPs installed on the seabed as the main AL method, with GL as backup.
Technology Focus: Unconventional Recovery (July 2008)
Authors: Norris Stephen
Published: February 2015

Technology Focus

Have you heard the story about the "17-year overnight sensation" (Durham 2005)? (If you work in northern Texas or are involved in unconventional resources, then your answer probably is yes, and if so, please bear with me—it is a great story and worthy of being repeated.)

In the early 1980s, in a county on the outskirts of Fort Worth, Texas, there was a privately owned oil and gas company that just would not give up on a novel idea it had for obtaining a new source of gas for a large existing gas-gathering infrastructure and a large gas-processing plant. It seemed that whenever it drilled a well for deeper horizons, it encountered a significant gas show in a very thick shale section that contained methane and some heavier gases. Some brave soul, probably a very young engineer or geologist, suggested testing the shale to see if it possibly could be productive. At the time, the conventional wisdom was that the shale was probably a source rock, but was certainly not reservoir quality and certainly not productive. But the president of the company had faith in his young professionals and gave the go-ahead for testing.

The first well, the C.W. Slay No. 1, was an economic failure, as were the next 40 wells (Bowker 2003). It took 17 years for the company to develop an economic technique that worked. How many companies that you know have that kind of patience? In 1999, very few people had heard of the Barnett shale, but by 2001, it was well on the way to becoming the largest gas field in Texas.

I think that stories like this make unconventional recovery a very exciting arena in which to work. The resource is there, the demand is definitely there, and it is up to engineers, geologists, and enlightened managers to make it happen.

In this issue, we look at three great examples of applying new technology and knowhow in the areas of coalbed methane, tight-gas-field deliquification, and gas hydrates. Is there another 17-year overnight sensation here? You be the judge.

References

Bowker, K.A. 2003. Recent Developments of the Barnett Shale Play, Fort Worth

Basin. West Texas Geological Society Bulletin42 (6): 4–11.

Durham, L.S. 2005. The 17-Year Overnight Sensation. Explorer 2005 (May). www.aapg.org/explorer/2005/05may/barnett_shale.cfm. Accessed 5 June 2008.

Unconventional Recovery additional reading available at the SPE eLibrary: www.spe.org.

SPE 114173 • "Stimulating Unconventional Reservoirs: Maximizing Network Growth While Optimizing Fracture Conductivity" by N.R. Warpinski, SPE, Pinnacle Technologies, et al.

SPE 110590 • "Potential for Oil-Shale Development in the US" by Khosrow Biglarbigi, Intek, et al.

Additional reading available at OnePetro: www.onepetro.org.

OTC 19519 • "Four Critical Needs To Change the Hydrate-Energy Paradigm From Assessment to Production: The 2007 Report to Congress by the US Federal Methane Hydrate Advisory Committee" by Dendy Sloan, SPE, Colorado School of Mines, et al.
Are We Really Listening?
Authors: Hoyer Carel
Published: February 2015

Guest editorial

It is often said that there is a reason we have two ears and one mouth. Similarly, most would agree that things would go a lot easier during well construction if both operators and service entities spent more time listening and trying to comprehend and less time talking. All this talking makes me wonder—who is really listening to what the well is trying to tell them while it is being drilled?

Old habits are a poor excuse for allowing drilling hazards to eat up a budget. But that is the case for many "conventional-wisdom" well construction and fluid programs, where 10 to 40% of expenditures are still spent drilling trouble zones and large contingency funds are the norm. Given we have likely already drilled most of the "easy" prospects, unless we change our approach, drilling-related nonproductive time will no doubt continue trending upwards.

From one well to the next, "the way we've always done it" often trumps lessons learned. The magnitude of the resulting spending—particularly to combat known and predicted hazards—makes a harsh point. For instance, an analysis of Gulf of Mexico data from James K. Dodson Company shows that wellbore instability accounts for more than 31% of total nonproductive time in nonsubsalt wells and 41% in subsalt wells. For a 20,000-ft well, extrapolated losses add up to the millions of dollars.

However, it has also been shown that these trouble zones can be effectively and efficiently drilled or even avoided if new drilling practices are considered, applied, and combined with proven drilling technologies, products, and processes.

Legacy Constraints

The very earliest wells were drilled "underbalanced." Hydrocarbons flowed to the surface until events like Spindletop in 1901 created environmental and safety challenges. It was only from the desire to reach greater depths that drilling fluids were weighted up and "overbalanced drilling" was invented.

Imagine if a rotating control device (RCD) and automated choke manifold had been invented instead, and all wells had been drilled underbalanced to the present day? Imagine the difficulty in trying to persuade long-time reservoir engineers or drillers to now commence drilling their wells overbalanced, pumping foreign chemicals and particulate into their wellbore to get to total depth (TD) and then being given the "solution" by the service companies to pump expensive stimulation treatments to try and remove or bypass the damage, before handing over to the completion group. Or the need to start running multimillion dollar tools with nuclear sources downhole to indirectly measure rock properties and try and deduce, using complex software, where the oil might actually be located with the very real risk of leaving some of these expensive tools downhole.
Polymer Treatment Controls Fluid Loss While Maintaining Hydrocarbon Flow
Authors: Eoff Larry , Waltman Bart
Published: February 2015

Technology Update

The loss of pumped fluids that are circulated from surface to total depth (TD) and back during various drilling, completion, and intervention operations poses numerous problems affecting wells and reservoirs. Fluid loss (FL) to the formation is costly not only in terms of the fluid itself, diverted from its task, but in the time and expense required to mitigate the problem. Well control can be compromised, wellbore cleanouts impaired, and reservoirs damaged, sometimes permanently, as a result of fluids entering the formation.

A low-viscosity, solids-free FL treatment can help (1) cure lost circulation, (2) prevent loss of expensive drill-in fluid during workovers, (3) improve well control by maintaining a hydrostatic column, and (4) provide FL control in vertical- and horizontal-well gravel-packing operations.

The treatment technology, developed by Halliburton as the LO-Gard fluid-loss-control system, relies on an associative polymer to decrease matrix permeability to aqueous fluids, limiting leakoff into treated zones. A significant property of the treating fluid is that it causes little or no damage to the flow of hydrocarbons.

The treatment fluid may be used in various applications.Well intervention cleanouts by coiled tubing and hydraulic workoverGravel packingMost lost-circulation events occurring during cementing, fracturing, and drillingAfter tubing-conveyed perforating (TCP) operationsFL control before, during, and after gravel packingElectrical submersible pump (ESP) replacement operationsCirculation maintenance in horizontal openhole completions across unconsolidated sands (Fig. 1)Formation permeability reduction inHigh-permeability streaksThinned or eroded drill-in fluid wall cakeBreeched or fractured wall cakeNatural- or hydraulic-fracture networks

FL Problems and Causes

During workovers, gravel-pack completions, ESP replacement, underbalanced TCP (UTCP), and other applications, aqueous well fluids are usually circulated continuously between the surface and TD. Maintenance of a hydrostatic column is necessary for well control and to enable treatment fluids to be injected into the targeted intervals downhole, without fear of overdisplacing the treatment fluids.
Whatever Happened to the Skills Crisis in the Oil and Gas Industry?
Authors: Peek Peter , Gantes Patrick
Published: February 2015

Talent & Technology

During the years leading up to the financial crisis of 2008–09, growing skills shortages were one of the main concerns of the oil and gas industry. A 2007 study by Cambridge Energy Research Associates estimated a shortage of 55,500 engineers and project management staff to deliver the more than 400 major projects that were then scheduled to come on stream over the next 5 years. A 2008 Ernst & Young survey showed that nearly 90% of senior human resources executives at 22 top international oil and gas companies thought the industry faced a major talent void and they called the problem one of the top five business issues facing their companies. Several research institutions even ventured to calculate the cost of skills shortages for the industry, and one of the more conservative studies estimated that the US oil and gas industry alone lost between USD 4 and 5 billion in 2006 as a result of the skills shortage.

A number of oil and gas executives argued that if nothing is done, there would be a slowdown in reserve replacements, a "capacity shut-in," and a major increase in operating costs within the next 5 to 10 years. Already, during 2007 and early 2008, reports were coming in of project delays around the world because of the lack of skilled personnel.

We all know that that situation has changed since then. Crude oil prices plunged from more than USD 140/bbl to under USD 40/bbl as the global recession reduced energy demand in the importing countries. And the demand for higher-skilled workers dropped as production declined and producers cut capital expenditure on exploration and new production facilities. The outcome is that many companies and governments, which had developed plans to invest in human resources to tackle the skills shortage, have decided to drop these or scale them down significantly.

This raises an important question: Once the current recession is over, and the industry gears up to meet growing energy demand, will it again be faced with skills shortages restricting production? Clearly, smaller energy companies with limited access to capital have fewer options. But the larger ones with more capital, does it make sense they drop human resources from their investment plans?

Several large companies are already positioning themselves for the recovery. They have maintained or even increased capital expenditures to be able to meet higher demand in the future. But what we have seen so far is that these plans only cover capital investment in production and exploration. So far we have not seen any major plan to address the potential of future skills shortages once the industry gets ready to meet higher energy demands. In our view, the industry risks paying a high price if it ignores the threat of skills shortages limiting future production.
Taking Advantage of Turbulent Times
Authors: Ferling Albrecht , Sternesky Michael
Published: February 2015

Management

Set in motion by the global financial markets collapse, oil and gas markets have suffered a huge setback since July 2008 when commodity prices began to fall. Energy demand has fallen in all sectors of the global economy, and the lack of available credit and seizing of credit markets had an immediate impact on economic activity in all sectors, signaling the beginning of a deeper and longer recession than we have seen in the last 30 years. These turbulent times require fast and immediate reaction.

Supply and demand balances have been difficult to determine, and oil prices have been volatile over the past year. Today's uncertainty adds considerable complexity to the process of making the right investment decisions for future supply. If the situation does not change soon, the industry may be subject to a very severe supply crunch in the middle of the next decade.

Extraordinary times can also create opportunity. Many companies used the last four years of rising commodity prices as an opportunity to reduce debt and bolster their balance sheets. That may lead to an uptick in mergers and acquisitions of companies with strong and proven reserve positions in politically stable host countries. The risk/reward balance is tilting toward the purchase of whole companies to replace reserves produced.

The ability to quickly integrate an acquisition into the enterprise, which can save millions of dollars, is a significant agility requirement in these troubled times. Today, technology can enable the faster integration of an acquired company's assets with overlapping assets within the enterprise. Using Web-based systems and service-oriented architecture, a virtual consolidation of the underlying enterprise systems can be quickly achieved at the presentation layer, pulling data from the different legacy systems into one unifying view. This virtual consolidation enables the quick integration of overlapping assets with consistent work processes, resulting in faster realization of economies of scale and elimination of redundancies, and gives the acquisition-integration teams more time to harmonize the legacy business systems.
Technology Focus: Reservoir Simulation and Visualization (July 2009)
Authors: Crick Martin
Published: February 2015

Technology Focus

For many years, the title of this feature has been "Reservoir Simulation and Visualization," but year by year fewer papers are submitted on visualization. This clearly reflects that 3D visualization is no longer a novelty—it is a standard part of our workflow. This trend ties with another I noted last year—greater inclusion of geological modeling in history-matching workflows. Visualization is an essential part of the geological-modeling workflow, one of the geologist's key quality-checking steps, and only with good 3D-graphics workstations did geological modeling become mainstream. However, it does not seem likely that history matching will die out as a topic for papers any time soon!

A great variety of techniques are being deployed to automate the process of history matching (improving the engineer's productivity) and to improve the quality of the result. Several experimental-design techniques are reported, as researchers continue attempts to extract the maximum benefit out of the fewest runs. It will be interesting to see if developments in hardware, leading to ever-reducing computing costs, result in a change of emphasis.

Although history matching remains a key focus, the broader application of mathematical-optimization techniques to prediction is emerging as a key topic of interest. This application goes to the heart of our role as reservoir engineers, and it is good to see history matching treated as merely a means to an end, rather than an end in itself.

The variety of reservoirs being developed and studied with simulation continues to grow, and the boundaries of technology continue to stretch. Naturally fractured carbonates, heavy oil under thermal recovery, tight gas, shale gas, coalbed methane, and other projects all feature more-complex and sophisticated wells.

The 2009 SPE Reservoir Simulation Symposium produced many excellent papers on the underlying technology and algorithms of simulation and its application: It is good to see that innovation continues. Sadly, many of these papers do not lend themselves well to the synopsis format of this feature, so I strongly urge you to track down the Proceedings from a colleague if you were unable to attend.

Reservoir Simulation and Visualization additional reading available at OnePetro: www.onepetro.org

SPE 118178 • "An Integrated Case Study From Seismic to Simulation Through Geostatistical Inversion" by S. Soni, SPE, Fugro-Jason, et al.

SPE 119139 • "Comparison of Stochastic Sampling Algorithms for Uncertainty Quantification" by L. Mohamed, SPE, Heriot-Watt University, et al.

SPE 122934 • "A Workflow for Integrated Barnett Shale Gas Reservoir Modeling and Simulation" by C. Du, SPE, Schlumberger, et al.
Technology Focus: Unconventional Resources (July 2009)
Authors: Polikar Marcel
Published: February 2015

Technology Focus

The baton has been passed, and so, during the next 3 years, I will provide here a brief editorial about and drawing your attention to recent publications or events pertaining to unconventional resources.

I have been around the industry since the late 1970s and have seen many changes since. I started my petroleum career working in the unconventional oil sands of Alberta, Canada, which are similar to but colder than those of Venezuela. Although unconventional-oil exploitation is still a dynamic topic, activity in unconventional gas (e.g., tight gas, shale gas, and coalbed methane) is picking up as environmental awareness surrounding the exploitation of unconventional resources grows. So, my editorial is about "unconventionals," a very trendy word indeed.

What are unconventional resources and what characterizes them? I will broach this topic in a general way without offering a definition—this has been debated for a long time! There are unconventional locations (e.g., deep water or beneath national parklands, a lake, or a city), which require unconventional methods. There are unconventional formations (e.g., oil sands and coalbed methane) containing hydrocarbons that cannot be produced in a conventional (primary or secondary) way with available equipment, or are not being exploited because of unavailable methods and/or high costs. Unconventional technologies are being developed to recover these unconventional and difficult-to-recover hydrocarbons, from drilling and completions to logging to production. There are unconventional "energies," with a shift toward renewable ones such as wind, solar, geothermal, and deep ocean energies, and biofuels.

Obviously, the environment is a priority, and large efforts are expended nowadays in this direction. For example, greenhouse gases are being captured and disposed of in deep rocks or in the water in pilot projects; these gases are also used for enhanced oil recovery.

The more-than-century-old "oil and gas" industry has changed into an "energy" industry. As this industry is redefined, many of the technologies that traditionally have been used for oil and gas exploration and development are needed to expand unconventional resources and advance the development of other sources of energy, whether they are nonrenewable or renewable ones. It is natural for this growth of the industry to happen. Along the way, we will find/discover new technologies that will also help the development or redevelopment of the old established sources. Bright is the future!

Unconventional Resources additional reading available at OnePetro: www.onepetro.org

SPE 119891 • "Workflow for Stratigraphic Characterization of Unconventional Gas Shales" by Roger M. Slatt, SPE, University of Oklahoma, et al.

IPTC 12743 • "Importance of Unconventional Oil Resources in Shaping the Far East Energy Future" by Philip Stark, IHS, et al.

SPE 113852 • "Oil and Gas Expertise for Geothermal Exploitation: The Need for Technology Transfer" by Gioia Falcone, SPE, Texas A&M University, et al.
Ocean-Thermal-Energy Conversion
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19979, "Ocean-Thermal- Energy Conversion (OTEC): Technical Viability, Cost Projections, and De velopment Strategies," by T.J. Plocek and M. Laboy, Offshore Infrastructure Associates, and J.A. Marti, Technical Consulting Group, originally prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May. The paper has not been peer reviewed.

Ocean-thermal-energy conversion (OTEC) is a renewable-energy source particularly suited for tropical zones. It uses the temperature difference between the warm surface ocean water and the cold deep ocean water to generate electricity and, if desired, potable water. This alternative energy source does not depend on fossil fuels, is not vulnerable to world market fluctuations and has less environmental impact than other energy sources.

Introduction

OTEC is a renewable-energy technology that is applicable to most parts of the world's deep oceans between 20° north and 20° south latitude, including the Caribbean Sea and the Gulf of Mexico; the Pacific, Atlantic, and Indian Oceans; and the Arabian Sea, where the temperature difference between the warm surface ocean water and the cold deep ocean water is equal to or greater than 68°F. OTEC basically recovers part of the solar energy absorbed by the ocean. Its main application is in tropical zones where deep ocean water is available at a short distance from the shore (less than 6 miles). In addition, the potential site must have a marine environment that allows the operation of a stable system.

One of the greatest advantages of OTEC is that it allows the coproduction of potable water in addition to electric power. It is possible to produce as much 0.5 million gal/D for each MW of electricity generated. Because OTEC does not use fossil fuel, the produced electricity has a fixed cost; thus, it is not susceptible to the cost volatility that affects other energy sources such as petroleum, coal, and natural gas. Moreover, the environmental impact is less than that of other sources of energy because no products of combustion are generated during the power-production process. All of these aspects have caused a revival of interest in OTEC.

Basic Principles

An OTEC plant consists of a heat engine that converts thermal energy into mechanical work by use of the temperature gradient between a heat source and a heat sink. Although this temperature gradient is relatively small compared to a steam engine, the principle is the same. OTEC technology is divided into three categories: closed cycle, open cycle, and hybrid cycle.
Techbits: Conferences Highlight Indian, North African E&P Efforts
Authors: JPT staff _
Published: February 2015

Techbits

Two conferences held recently highlighted the challenges and opportunities unique to E&P activities in two important oil and gas regions, India and North Africa.

SPE Oil and Gas India Conference and Exhibition (OGIC)

The SPE OGIC, held in January in Mumbai, had an overarching theme of “E&P Business: Excellence Out of Turbulence.” The event, which marked the first conference organized by SPE in India, brought together more than 1,200 industry leaders representing 167 companies from 30 countries to discuss new means of managing risks at times when oil prices undergo wide fluctuations.

To open the conference, Murli Deora, the Government of India’s Minister of Petroleum and Natural Gas, sent a message that included his best wishes for the conference’s success and emphasized its importance to the region. “We need to deploy our best brains to find technologies which can bring [oil and gas] resources to the realm of affordability and sustainability and at a scale which would aid in furthering the region’s economic activities,” Deora said. “There is no single solution. There is no single company, nation, or technology that can meet our energy challenges, all on their own. Sustainable energy solutions would require increasing collective attention and efforts.”

Following the inauguration of the event, a VIP tour of the venue and exhibition space took place, which included dignitaries R.S. Sharma, chairman and managing director of Oil and Natural Gas Corporation (ONGC); Sudhir Vasudeva, OGIC chairperson; and 2010 SPE President Behrooz Fattahi. Several of the 30 companies exhibiting at the conference launched new products, including new rotary steerable systems designed to create smoother wellbores and new multiphase-flow measurement devices that do not require separation of fluids.

An executive plenary session followed, in which panelists including N. M. Borah of Oil India, Derek Fisher of BG India, A.K. Balyan of ONGC, and James McCallum of Senergy shared their regional and international insights on how oil and gas companies are committed to exploring more efficient methods and integrating advanced technologies to enhance their operations and improve productivity.

The first day also included several technical sessions that explored E&P topics such as well simulation, unconventional-resource extraction, reservoir characterization, facility engineering, and drilling challenges. The day closed with a special session titled “Management of Mega Projects,” which addressed the optimum ways to design and manage mega E&P projects, to reduce their intensive capital investments, and the best strategic approaches to improve a project’s overall management process.
The Geared Centrifugal Pump: A New High-Volume Lift System
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 123938, ’The Geared Centrifugal Pump: A New High- Volume Lift System,’ by J.C. Patterson, SPE, ConocoPhillips; W.B. Morrow, SPE, Harrier Technologies.; and M.R. Berry, SPE, Mike Berry Consulting, originally prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed.

The geared centrifugal pump (GCP) is a high-volume artificial-lift system consisting of a progressing-cavity-pump (PCP) -style rotating rod string driving a bottom-intake electrical-submersible-pump (ESP) -style multistage centrifugal pump by use of a downhole speed-increasing transmission. The heart of the system is the unique transmission that uses a novel gearing configuration that allows high torque and power. The GCP provides the high-volume lift of an ESP but with better gas handling, simpler operation, and lower capital and operating costs.  

Introduction

The GCP is an artificial-lift system consisting of the rotating-rod-string drive of a PCP, driving the multistage centrifugal pump of an ESP by a downhole speed-increasing transmission. The transmission is required to increase the relatively slow rotational speed of the PCP rod string, typically less than 500 rev/min, up to the 3,500-rev/min operational speed of the centrifugal pump.

The GCP was developed as an artificial-lift system to provide the high-volume lift of an ESP without the expensive and troublesome downhole electric motor and cable of the ESP system. The GCP uses efficient and relatively inexpensive industrial electric motors in the surface drive head, requiring none of the special controls or transformers necessary for high-voltage ESP motors. The rotating rod string transmits power downhole with low power losses. This system combines the highly efficient GCP transmission assembly with a modern ESP pump.  This combination results in a system with lift efficiency greater than 50%. Because all of the downhole components of the GCP are mechanical, the design is adaptable to very-high-temperature applications such as steam-assisted gravity-drainage (SAGD) projects.

GCP Components

Drive Head. The GCP uses the same drive system as a PCP system. A surface drive head turns a rotating rod string that drives the downhole assembly. The only difference between a PCP drive head and one built for the GCP is the load-capacity requirements of the thrust bearing carrying the rod load. In a PCP drive head, the thrust bearing must carry the weight of the rod string as well as the fluid load. Because the rod string of the GCP does not carry any fluid load, the thrust bearing in the GCP drive head can have a correspondingly lower capacity. Another characteristic of both PCP and GCP drive heads is prime-mover flexibility. Although the majority of well locations have electric power, the GCP can be powered by an internal-combustion engine, a hydraulic motor, or an electric motor.
Annular-Velocity Enhancement With Gas Lift as a Deliquefication Method
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 130256, ’Annular Velocity Enhancement With Gas Lift as a Deliquification Method for Tight Gas Wells With Long Completion Intervals,’ by S.A. Pohler, SPE, W.D. Holmes, SPE, and S.A. Cox, SPE, Marathon Oil Corporation, originally prepared for the 2010 SPE Unconventional Gas Conference, Pittsburgh, Pennsylvania, 23-25 February. The paper has not been peer reviewed.

It is common practice in the industry to complete multiple reservoirs in a single wellbore to establish commercial production rates from tight gas completions. In some cases, these zones are separated vertically by several hundred to more than 1,000 ft. The deliquefication of these completions is one of the most challenging problems facing our industry. Many of the deliquefication methods currently being used are effective over only a portion of the wellbore. 

Introduction

It is common practice to complete tight gas wells with the tubing tail above the bottom perforation. This completion practice allows static liquid to stand across the lower set of perforations. Static liquid standing across the perforations promotes increased near-well liquid saturations through a process of spontaneous imbibition. The imbibition process is a damage mechanism that can be present upon initial completion and can continue throughout the productive life of the well if allowed to form through ineffective liquid-removal/completion practices.

There are a number of different methods currently in use for the deliquefication of gas wells. Some of the more common are plunger lift, chemical-foam lift, and conventional pumps (i.e., rod pumps, electrical submersible pumps, and progressing-cavity pumps). Each method has drawbacks when it comes to deliquefying wells with long completion intervals. Effective liquid removal can improve overall well performance significantly. However, an effective system cannot ignore the potential presence of a static liquid column. Current completion technology has been found to have limited effectiveness when long productive intervals are involved. Therefore, a modified continuous-flow gas lift system is proposed that includes a packer and crossover system and that allows for gas lifting the well below the bottom perforation. The details of this completion process and its field applications are discussed in the body of the full-length paper.
Technology Focus: CO2 Applications (July 2010)
Authors: Gomersall Sam
Published: February 2015

Technology Focus

“CO2 storage is just a hole in the ground.”

The creation of an effective carbon-capture and -storage (CCS) project involves a complex relationship between a CO2 emitter and a CO2-storage provider and the alignment of each of their major project developments. Power generators, who are major emitters of CO2, generally have little knowledge or interest in the subsurface and are prone to oversimplification—on occasions representing storage as a “hole in the ground.” Conversely, oil and gas operators do not see CO2 storage as part of their range of business activities, unless it involves enhanced oil recovery or provides a solution to unlock a gas project with a high CO2 content. As a result, the wider oil and gas sector is not yet fully engaged with the CCS opportunity.

Without a full appreciation of the end-to-end CCS project, it is difficult to ensure effective risk allocation. Power generators tend to take the lead on CCS projects, and experience to date suggests that storage-related issues are not considered sufficiently during the early stages of these projects. To progress, each industry must play its part: providing greater clarity over the nature of the challenges and being willing to understand the other’s issues. The academic sector has identified the funding opportunities that come with CCS and plays an important part in developing and sharing relevant knowledge within and across industries.

However, such knowledge sharing comes with responsibilities. These responsibilities include being very clear about material presented. By way of example: Assessments of capacity to store CO2 sometimes include extreme over- or underestimates (e.g., through approximation or the selection of specific, but unusual, reservoir assumptions). Such material then is used by proponents of one argument (e.g., “storage will never work”) or another (e.g., “storage is just a hole in the ground”) to justify their position.

Of course, the reality is that CO2 storage is a complex matter requiring the effective application of all the subsurface knowledge that we have to identify, appraise, select, and develop suitable storage reservoirs. Effective communication across industries is key to the success of CCS.

CO2 Applications additional reading available at OnePetro: www.onepetro.org

SPE 127080 • “The Application of Environmental-Impact Assessment in Carbon Capture and Storage” by Evert Holleman, Royal Haskoning, et al.

SPE 124002 • “CO2-ECBM/Storage Activities at the San Juan Basin Pump Canyon Test Site” by George J. Koperna Jr., SPE, Advanced Resources International, et al.

SPE 126444 • “Development of Storage Coefficients for Determining the Effective CO2 Storage Resource in Deep Saline Formations” by Charles D. Gorecki, SPE, University of North Dakota, et al.
Offshore Drilling and Public Service
Authors: Bromwich Michael
Published: February 2015

Guest editorial

Approximately a year ago, in June 2010, US President Barack Obama and Secretary of the Interior Ken Salazar asked me to serve as director of the US Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE). Two months earlier, the Deepwater Horizon exploded, taking the lives of 11 men, injuring 17 others, and causing nearly 5 million bbl of oil to spill into the Gulf of Mexico. It was an event with enormous human and environmental consequences, which will leave a lasting legacy. It was an event that jolted industry and government alike. 

In the wake of Deepwater Horizon, BOEMRE has raised the bar for safety, oversight, and environmental protection at every stage of the drilling process. We have made significant progress, but there is still much work to be done. One of the most pressing issues facing the agency is ensuring that we can fill our ranks with the nation’s best and the brightest engineers and scientists.

Strengthening Regulations

First, a brief look at the reforms we have undertaken. Among the central tasks that needed to be addressed was the strengthening of the rules and regulations that govern offshore drilling. We needed to enhance drilling and workplace safety and provide additional protection for the environment. We did so quickly and responsibly. Within a few short months, we developed and implemented two important new rules.

The first rule, the Drilling Safety Rule, created tough new standards for well design, casing, and cementing, and new rules for well control procedures and equipment, including blowout preventers. Operators are now required to obtain independent third party inspection and certification of the proposed drilling process, and an engineer must certify that blowout preventers meet new standards for testing and maintenance and are capable of severing the drill pipe under anticipated well pressures. The second rule, the Workplace Safety Rule, requires operators to systematically identify risks and establish barriers to those risks and thereby seeks to reduce the human and organizational errors that lie at the heart of many accidents and oil spills.

In addition, operators must now have a plan and the demonstrated ability to shut in a deepwater blowout and capture oil flowing from a wild well. Thus, rather than improvising a containment response on the fly—with the hits and misses we saw during the attempts to bring the Macondo well under control—each operator must develop a containment plan that includes demonstration of access to containment technology such as a capping stack, and BOEMRE has to approve this plan.