bluuebunny/crossref_metadata_2025 huggingface dataset:
Fiber Optic Sensing - Learning How It Really Feels Downhole
Authors: Rassenfoss Stephen
Published: February 2015

Fiber optic sensing

Magnus McEwen-King describes his company’s vision by saying it is out to build “the Earth’s nervous system.”

The company, Qinetiq, has a venture, OptaSense, which is developing practical ways to use fiber optic cable for distributed acoustic sensing in oil wells. It is essentially installing a long string of digital microphones in a well. In partnership with Shell, the former British defense contractor has created systems that track what is happening during hydraulic fracturing and record sound waves during seismic testing.

Baker Hughes has a partnership with Shell covering the sense of touch. It is using specially modified fiber optic cable to measure small changes impacting 40-ft-long sections of a well in the US Gulf of Mexico deepwater Mars field. The recently completed injection well has also been wired with fiber optics gathering temperature, pressure, and sound data.

Shell’s third venture, with a Dutch company named TNO, will try to sniff out changes in well chemistry using fiber optic cables coated with specially formulated gels. The gels are designed to absorb specific molecules. When the concentration of the target chemical, such as carbon dioxide, increases, the gel absorbs more of it and swells, which is observed by the sensitive fiber.

Shell’s goal is to create permanent monitoring systems that make intelligent wells smarter by observing conditions inside a well, meter by meter. Vianney Koelman, chief scientist and fiber optics program leader at Shell International E&P, said fiber optics can directly gather information that helps answer pressing questions, including “‘Is a well producing the way I think it is producing?’ ‘Is it working the way the computer model is telling me?’ It can be quite different than what you think.”

Fiber optic temperature measurement systems—ranging from gauges using fiber for measurements in one spot to fiber doing meter-by-meter measurements throughout a well—have been installed in thousands of wells going back to the mid-1990s. The fastest growth has been in heavy oil fields where temperature monitoring improves the efficiency of high-temperature steam injection systems used to coax heavy oil out of the ground.
New Global Awards Launched for Petroleum Engineering Faculty
Authors: Howes Susan , Heinze Lloyd
Published: February 2015

Talent & Technology

At the 2010 SPE Colloquium on Petroleum Engineering Education, discussion focused on the challenges that petroleum engineering faculty face. Fig. 1 illustrates the trend of the increasing ratio of student to faculty in US petroleum engineering schools over the past two decades. Although the data are not available, we believe that similar trends exist internationally.

A survey of US petroleum engineering faculty demographics (Fig. 2) shows that 30% are over age 60, 38% are age 50-59, and 32% are under age 50. While some professors may continue to teach past the traditional retirement age of 65, this data indicates that about 30% or more of current petroleum engineering faculty may retire in the next five years.

As a result of the colloquium’s findings, a task force was commissioned by the SPE Board of Directors Subcommittee on Educational and Professional Activities to look into the recommendations on attracting, developing, and retaining faculty worldwide. The task force used survey methods and focus groups to determine root causes for the petroleum engineering faculty shortage and to make recommendations in three areas:

What universities can do

What the industry can do

What SPE can do

Based on survey results, some of the root causes of the problem appear to be:

Competition with the industry with respect to compensation

Lack of a pathway for petroleum engineering PhD candidates

Insufficient research funding/sources to support new faculty

The industry and petroleum engineering departments share a symbiotic relationship as students with petroleum engineering degrees are uniquely qualified for work in the energy industry. Unlike other disciplines, petroleum engineering graduates work primarily in the petroleum industry. The industry also expects them to be able to contribute immediately upon employment. Without good instruction, new graduates may not be adequately trained. Fig. 3 illustrates the cyclical nature of the number of bachelor’s, master’s, and PhD degrees in petroleum engineering granted in the most recent 40 years in the United States.

Although there is a concern that history will repeat itself in that the steep rise in undergraduate enrollment will be followed by an equally steep decline, a comparison of the trend of petroleum engineering freshmen enrollment between the 1973–1992 period and the 2001–2020 period shows striking differences in the influx of freshmen (Fig. 4).
Technology Focus: Hydraulic Fracturing (March 2012)
Authors: Olson Karen
Published: February 2015

Technology Focus

Hydraulic Fracturing: 2012 and Beyond

It is a good time to be in the oil industry. The rig count, drilling activity, and oil prices are high, and shale plays are a significant reason for each. And, because it is shale, it is an especially good time to be a completion engineer!

Even though we have been able to make these unconventional reservoirs economic by drilling horizontal wells and by multistage fracturing, it is important for us to realize (especially with low gas prices) that there is still plenty to learn about shale fracing (not spelled “fracking”). Buzz words fly around the industry: complex fractures, brittle vs. ductile shale, proppant transport in slickwater, and more. Each is a start, but what I challenge everyone to do is to ask the questions: What is really happening when we are fracturing the various shale plays; and how do we model it so that we can predict and optimize performance?

Economic and political implications of shale are enormous. The USA recently, for the first time in many years, became a net exporter of energy. The USA has clear shale-development advantages compared with other countries at this time because it has the rigs, hydraulic horsepower, personnel, and a long history of hydraulic fracturing.

But truth be told, there are disadvantages that must be dealt with. The USA is dealing with an oversupply of gas, which is reducing prices and making shale-gas plays marginally economical. To date, despite industry efforts, there still is no political will to substitute fuel sources on a large scale, create a widespread gas-fueling infrastructure, or increase automobile shale-gas usage appreciably.

So even though it is a good time to be in the oil field, remember that as completion engineers it is our job/duty to understand what is happening downhole when we are fracturing—Do we really have complexity? Does complexity occur in every shale interval or just the brittle ones? Does proppant “turn the corner” and go into the natural fractures? Knowing the answers to these and other questions can make the economics of shale plays become even better.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 147652 An Experimental Investigation of Spontaneous Imbibition in Gas Shales by B. Roychaudhuri, University of Southern California, et al.

SPE 139984 Hydraulic Fracture Crossing a Natural Fracture at Nonorthogonal Angles: A Criterion, Its Validation, and Applications by H. Gu, University of Ganguly, et al.

SPE 147248 Revisiting Microfrac In-Situ-Stress Measurement Through Flowback—A New Protocol by Alexei A. Savitski, SPE, Shell, et al.
Fracturing-Fluid Effects on Shale and Proppant Embedment
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146658, ’The Effects of Fracturing Fluids on Shale Rock-Mechanical Properties and Proppant Embedment,’ by Ola Akrad, SPE, Jennifer Miskimins, SPE, and Manika Prasad, SPE, Colorado School of Mines, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.

Development of shale reservoirs has grown significantly during the past few decades, driven by evolving technologies in horizontal drilling and hydraulic fracturing. The productivity of shale reservoirs depends highly on the design of the hydraulic-fracturing treatment. To design a successful treatment, a good understanding of the shale mechanical properties is necessary. The results of this study show that the greatest reduction of Young’s modulus occurs at high temperature and in samples with high carbonate content.

Introduction

In geology, shale traditionally has been defined as a sedimentary rock containing a high percentage (>50%) of clay and lower percentages of silica or carbonate minerals. However, many current shale prospects are not shales as defined in geology. Instead, they are “prospective-shale” reservoirs: fine-grained clastics characterized by ultralow permeability and usually composed of silica and carbonate minerals with a small amount of clay.

Success in these shale systems depends largely on excellent hydraulic-fracturing designs that require a good understanding of the mechanical properties of the subject and confining formations. In hydraulic-fracturing design, Young’s modulus is a criterion used to determine the most-appropriate fracturing fluid and other design considerations. Young’s modulus provides an indication of the fracture conductivity that can be expected under the width and embedment considerations. Without adequate fracture conductivity, production from the hydraulic fracture will be minimal, or nonexistent. This study of Young’s modulus shows a significant decrease in the presence of certain fluids. Such decreases in Young’s modulus lead directly to decreases in fracture conductivity and, therefore, should be taken into account when designing the treatment to obtain a required fracture conductivity in a given reservoir.

Methods and Testing Procedures

It is known that fracturing fluids can affect the formation face of the created factures and cause damage. This damage can manifest itself as filter cake, fluid imbibition, and other damage mechanisms. A possible additional damage mechanism in prospective-shale systems is the potential weakening of the rock frame or modification of Young’s modulus, which could allow additional proppant embedment to take place. Such embedment, if occurring, could affect the fracture conductivity of a given treatment adversely.
How Intelligent Knowledge Systems Will Improve Operations and Safety in the Future
Authors: Soignier Andrew
Published: February 2015

Guest editorial

In an era of high workforce turnover, capturing operational knowledge is vital to improving safety and achieving operational excellence. Modern solutions must address not only the replacement of paper-based processes, but also contextually weave together multidisciplinary information in a form that provides a holistic view of equipment across an operation. Going forward, the oil and gas industry should have intelligent, automated systems designed to capture data, learn from events, optimize production, and prevent safety-related incidents. The time is now for this step change in the industry as these fully integrated systems will become as necessary and as expected as the use of tablets and laptops.

Trends and events in the oil and gas industry in recent years have shown that the focus on operation, maintenance, and safety requires more integration and embedding into operational processes. The industry has been aware of the issue of staff turnover for some time and the causes are not just aging baby boomers, but a change in working trends. The retention of employees is no longer assured through incentives, such as a good pension package, and the modern workforce recognizes that their skills are highly transportable. Lives are built more around portability, and information that would encourage one to realize new ambitions is more readily available than ever before. What attracted and retained previous generations of the workforce no longer has the same appeal. The industry must adapt to this new status quo and protect against the increasing risk that vital, safety-related information could disappear from an organization.

With increased staff turnover, the risk that an organization might not keep required information is particularly high in activities that are not part of daily operations. Less frequent occurrences, such as an operation startup or coming out of a turnaround process, may leave the company particularly vulnerable. Information may be especially limited when it comes to taking long-life, rarely cycled equipment in and out of operation. However, it is under such less frequent conditions that accidents are more likely to occur.

To combat the loss of knowledge retained by staff, intelligent systems should be not only work-process driven but also capture valuable information. These systems must be used by both seasoned and new employees and to capture and harness knowledge about various aspects of operations. They should learn, be intelligent, and make the knowledge they contain clearly available to operators as they work. In this way, when there are transitions, abnormal conditions, or opportunities for improvement, operators and engineers have ready access to the background and information gained from the past 20 years of accumulated knowledge. Such a system is a living, breathing application beyond anything that has been used in the industry to date.
In Search of Better Water Quality Through Continuous Monitoring
Authors: Rassenfoss Stephen
Published: February 2015

The simplest way to measure return on investment for an offshore water treatment system is to determine whether using the system actually reduces the risk of paying a fine for violating water pollution laws. This has typically been done through laboratory tests—required by regulators—on periodically collected samples of treated water.

But increasingly, water testing systems are being installed on production platforms offering constant updates of the effectiveness of the water treatment systems. The argument for them is that what flows out of oil fields changes constantly, with surges and slugs dense with hydrocarbons. An unnoticed surge or slug can cause a sharp increase in the oil level in the treated water that is disposed overboard. Without quick adjustments, these excursions can create a telltale sheen around a platform, which can lead to trouble.

“There is the dreaded sheen,” said Sandy Rintoul, executive vice president of Wilks Enterprise, which was recently acquired by Spectro. “If there is a sheen on the water, watch out. The helicopters will see you pretty soon.”

Wilks sells tabletop devices, used on platforms for periodic processed water quality checks that have been used for decades. It now faces multiple competitors in a niche where new testing methods are for sale. If done properly, those tests can indicate how a platform will fare when tested for regulatory compliance.

“They (platform crews) typically use it at least once a day. You see some do it four times a day. If something is going on with the system and there is an issue, they could grab samples every hour,” said Rintoul.

A small but growing number of platforms have installed constant monitoring systems. The future of this option will depend on convincing operators that there is a favorable return on investment in monitoring systems that cost many times more than periodic checks.

There was keen interest at the annual meeting of the Produced Water Society, which spent one day at its 3-day annual Produced Water Seminar, held 14–16 January in Galveston, Texas, for presentations and debate on the value and effectiveness of continuous monitoring and its future.

At the meeting, an employee of a water treatment company asked an engineer from a major oil company what it would take to convince operators of the value of smarter water treatment systems.

The answer was: “It is hard to prove how much you can save when you do not know the problem you will solve.”

One answer came from MyCelx, a young company that sells equipment for water polishing, which reduces the oil content at the last stage of treatment. Also called tertiary treatment, this step is often taken when there is an upset pushing up oil levels of water from the primary and secondary treatment systems.

A case study conducted by MyCelx covered 2 years’ experience on a deepwater facility in the US Gulf of Mexico where the company observed 10 to 12 upsets a year, some lasting for days.
Beyond Forecasting: Energy Markets in a Time of Unprecedented Uncertainty
Authors: Leis Jorge , Gottfredson Mark
Published: February 2015

Management

Imagine if you could have seen North America’s shale gas phenomenon coming, years ahead of the competition. What would you have done differently?

Some companies might have avoided spending billions of dollars on liquefied natural gas import facilities in the United States. Some might have acquired acreage before hyperinflation escalated land values. Others would have reallocated capital to better position their companies for the onslaught of natural gas and natural gas liquids. If you had seen it coming, would you have anticipated the global competitive advantage of US domestic industries, from manufacturing to fertilizer to plastics to coal, and the resulting changes to international flows?

Hindsight is 20/20, but there were indicators pointing to a shale gas supply shock. What was missing for most executive teams was a systematic approach for identifying plausible scenarios and defining the leading indicators that would allow them to monitor the market’s evolution toward them.

Most energy companies could benefit from this type of approach, especially with the high level of today’s uncertainty. We have developed a series of plausible scenarios based on our analytical models. To build these scenarios, we capture the dynamics of the energy ecosystem along three major vectors: natural gas supply, crude oil supply, and the uptake of renewables (Fig. 1). Within each, we consider experience curves and the relevant efficiency gains to determine supply curves and possible clearing prices. We then use those prices to calculate intrafuel substitution (such as shale gas for coalbed methane gas) and interfuel substitutions (such as natural gas for coal). We also reasoned that regulatory actions and technology breakthroughs could make renewables competitive and lead to substitution away from fossil fuels. Then we looked at the constraints on infrastructure build-out and we balanced supply and demand by industry sector (power generation, transportation, industrial heating and power, and industrial feedstock). This type of scenario building is a forward-looking process that anticipates disruptive change and can help inform executives for better decision making.
Conversations: Willing is not Enough - We Must Do
Authors: Fattahi Behrooz
Published: February 2015

President's column

The oil and gas industry employs a large number of people around the world. The American Petroleum Institute (API) estimates that in the US alone, the oil and gas industry is one of the largest employers, supporting more than nine million jobs providing cost-competitive energy and adding more than USD 1 trillion to the US economy.

However, the measure of our industry is not only in the numbers that it employs, but more significantly is in the number of lives that it touches, and that is the entire population of our planet, roughly seven billion people. This creates a profound sense of social responsibility for us as an industry.

Without a doubt, our industry impacts the lives of almost all of us, regardless of whether we reside in developed or developing countries, in large or small urban areas, or in the remotest corners on this planet. Every day we use hundreds of products that have their roots in petroleum—the clothing we wear; equipment that we use in our work or leisure pursuits; health and beauty products; household furnishings; building materials; transportation; and many other applications. Without these products, the lifestyles and health of many, many people would be significantly different.

However, at least a segment of the general public views the activities of the oil and gas industry as incompatible with the concept of a sustainable planet. I am not certain of the extent of the sentiment or the significance of the numbers, but I have clearly heard about it from the industry leaders and the officials in many countries that I have travelled to as the SPE president. Jeane Kirkpatrick, a former US ambassador to the United Nations, once said that “Oil is a product that arouses so much passion. A lot of people have a passionate fear, or distaste, or downright hatred almost for oil. There is no other product that so many people need so badly, yet so many people believe should be produced entirely without profits.”

This is a serious matter. Public perception is an intangible asset that helps the industry attract resources, and develop a sustainable viability. We may differ on whether there is a scientific basis for this negative public opinion, but the reality is that the perception exists, and it translates into a more difficult environment for the industry to conduct its business. We, as members of the industry, need to recognize this and find ways to reverse the sentiment. Erosion of our image, I suggest, has not been due to the way we have run our business, but rather because we have behaved somewhat passively in the past, allowing unqualified others to make sweeping negative claims that portray our industry as insensitive to a sustainable planet. SPE’s energy education program is a key weapon in the fight against misinformation. Our outreach efforts that give teachers the science and facts about energy and our industry’s contributions are hugely important.
Embracing the Low-Carbon Economy of Sustainable Energy Development
Authors: Jiping Zhou
Published: February 2015

Guest editorial

Sustainable development of the economy, using energy while protecting the environment, has become an important global issue. A consensus already has been established regarding the development of a low-carbon economy.

Our industrial civilization, based on fossil fuels, consumes substantial energy resources while producing abundant materials to benefit mankind. However, it also has had a negative impact on the natural environment, and this negative impact is intensifying. The balance between the requirement for low-cost energy, and the need to protect the environment, is the greatest challenge facing mankind today.

Sustainable development of energy calls for a low-carbon approach. Currently, the world is at a critical stage in the industrialization of developing countries. During the past two centuries, industrialization, based on the intensive use of fossil fuels, has modernized a population of 1.2 billion in advanced, developed countries. And developing, emerging countries with a population approaching 3 billion will likely follow the tide of industrialization over the next 30 to 40 years.

As this development takes place, it is essential to choose a low-carbon development based on efficient energy consumption, with low pollution and emissions. Low-carbon development should not be simply interpreted as the development of low-carbon energy; it is rather the sustainable utilization of low-carbon energy. The process of energy evolution from high carbon to low carbon will be a prolonged one, and during this transition period fossil fuels will continue to play a major role in ensuring the sustainable development of the global economy.

During this transition, to further the goal of low-carbon development, our energy industry bears the responsibility to assist in adjusting the energy mix, accelerating natural-gas development, and increasing the proportion of clean energy to gradually replace fossil fuels.

Low-carbon development brings important opportunities especially to the natural-gas industry. As the most environment-friendly fossil fuel, natural-gas plays a unique role in the transition of the energy mix from high to low carbon, and therefore carries tremendous potential for development. Not only will natural-gas development increase the proportion of clean energy in fossil fuels, but it can also compensate for some of the disadvantages of renewable energy, for example, the difficulties of storing power in batteries, and the unstable supply of wind and solar energy. In this respect, by providing stable backup energy supplies, the gas industry will also help to accelerate the development of renewable energy.

In the coming 20 years, the global demand for natural gas will continue to grow at an average annual rate of 1.8%, and gas will overtake oil as the world’s largest energy source sometime in the first half of this century.
Cryogenic Piping Reduces the Effect of LNG Transfer Terminals on Local Communities
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20223, ’How the Use of Cryogenic Piping Can Reduce the Impact of LNG Transfer Terminals on Environment and Local Communities, While Increasing Site Safety and Security,’ by Phillip Cox and Raul Risi, Technip, originally prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May.

Environmental considerations play an important part in the permitting process for new liquefied-natural-gas (LNG) facilities. Ports generally are overworked, while coastal green-site areas often are protected and populated by local communities. An attractive alternative to conventional solutions can be achieved by installation of subsea cryogenic pipe in pipe (CPIP) to a nearshore transfer post, and by displacing the process facilities inland. This avoids the installation of a jetty and brings significant savings to the project, while improving the operational aspects of site safety and security.  

Introduction

Use of alternative technology in the LNG industry, whether it is new or proven, always will provide a challenge, and solid justification for its choice will be needed. Respect of the environment, linked closely to safety and security, is an item of prime importance during the permitting phase of any proposed new LNG terminal, and use of modern technology to address these issues will assist in obtaining required permits. Positive impact statements, supported by detailed engineering and certification, relative to the operability of the LNG chain and reduction of costs are an integral part of the engineering package to be supplied.

During the development phase of new equipment and methods, the overall picture must always be considered because the knock-on effect of upgrading one “link in the chain” may lead to further modification of associated equipment. This has been the case with the double development of the CPIP and the new marine offloading posts that are exposed to dynamic conditions, leading to the requirement for heavy-duty cryogenic flexible transfer systems.
Technology Focus: HP/HT Challenges (April 2010)
Authors: Payne Mike
Published: February 2015

Technology Focus

Industry focus on high-pressure/high-temperature (HP/HT) operations seems to go in cycles as exploration successes identify new hydrocarbon resources that can be developed commercially and as technical advances allow wells to be drilled and completed that extend prior capabilities. When production of HP/HT reservoirs becomes dependent upon the development of a particular technology, business incentives create both a substantial momentum and a sharp focus that drives technology development to a successful end.

Historically, this drive has been the case with HP/HT developments. With the passage of time, some may be unfamiliar with the substantial foundation of HP/HT technologies that were created by the hard work of our predecessors. For example, the Association of American Wellhead Equipment Manufacturers (AWHEM) started work on 15,000-psi wellhead equipment in 1952. That research resulted in AWHEM Standard No. 6 in 1957, which would later become part of the API 15K wellhead standards. The first 20,000-psi wellhead system was developed in 1972, which was followed quickly with the development of the first 30,000-psi wellhead system in 1974. These developments were in response to Shell’s discovery of the Thomasville field in Mississippi, USA, in 1969. In addition to Thomasville and Piney Woods fields in Mississippi, other substantial HP/HT developments include the Tuscaloosa fields in Louisiana, USA, and the Central Graben fields in the North Sea.

Currently, the industry is pursuing new generations of HP/HT fields including deeper wells in deep water and deep gas wells on the outer continental shelf (OCS). Relative to the deepwater operations, well pressures may approach 15,000 psi at the mudline, and, hence, 20,000-psi subsea equipment is being pursued. Relative to the deep gas wells on the OCS, 20,000-psi surface wellheads and trees, such as those used in Mississippi, Louisiana, and elsewhere, will again be needed, and discussions are active on 25,000-psi equipment.

Just as the industry addressed the new HP/HT requirements successfully and safely that appeared in the 1950s and onward, the industry’s current engineering rigor, innovation, and advanced technical capabilities will again converge to address today’s HP/HT challenges. These challenges should invigorate our engineers as they lay the foundations and groundwork for the next generation of HP/HT capabilities.

HP/HT Challenges additional reading available at OnePetro: www.onepetro.org

SPE 123681 • “Elgin/Franklin: What Could We Have Done Differently?” by Eric Festa, Total E&P(See JPT, January 2010, page 54)

SPE 118904 • “First Application of High-Density Fracturing Fluid To Stimulate a High-Pressure/High-Temperature Tight Gas Producer Sandstone Formation of Saudi Arabia” by K. Bartko, Saudi Aramco, et al.

SPE 124713 • “Depletion-Induced Stress Changes in an HP/HT Reservoir: Calibration and Verification of a Full-Field Geomechanical Model” by M.H.H. Hettema, StatoilHydro, et al.
New Technologies Enhance Efficiency of Horizontal, Multistage Fracturing
Authors: Themig Dan
Published: February 2015

Technology Update

Significant differences in completion philosophy are emerging within our industry. Even companies that practice a factory mentality (one size/method fits all) are beginning to see that the “sledgehammer approach” to hydraulic fracturing may not be the most effective in draining horizontal wells in resource plays. For several years, we have seen massive increases in fluid volume, pumping rate, total proppant volume, and pumping time to increase recovery. We have seen through microseismic as well as fracturing into offset wells, that we are able to create massive and extremely long hydraulic fractures. Yet, when effective fracture length is calculated, the results are extremely disappointing. It only makes sense that “more is better.” However, after years of steadily increasing job size, stage number, perforating strategy, proppant volume, and lateral length, the only one that stands out as consistently improving recoveries is that more stages are required to effectively drain microdarcy permeability rock (Rankin et al., 2010).

What We Have Learned

Building an understanding of shale gas, unconventional gas, tight carbonate reservoirs, and more recently the renewed emphasis on oil and high-liquid gas formations has not been easy. Perhaps this is because of the extremely rapid pace of development and the acceptable economics of many projects in North America and throughout the world. Also, the diversity of applications for horizontal, multistage fracturing has made it more difficult to pin down best practices. As a massive body of data develops, a number of things have become clear. First, when equivalent stage numbers and proppant volumes are considered, open hole generally seems to outperform cased hole by 25% to 70% in production (Fig. 1, Edwards et al., 2010; Snyder and Seale, 2010). Second, the number of stages required to effectively drain microdarcy permeability rock is extremely high. Just a few years ago, performing 20 stages seemed too high to consider. Current stage numbers are often double that. Third, today’s common plug and perf practices—even at high densities—may not be sufficient to drain shale gas or tight oil, even after 15 years of depletion time (Quirk, 2010). Reservoir modeling indicates that evenly spaced fractures would effectively drain today’s reservoirs in North America. The actual production data, however, indicates otherwise.
Proppants: Where in the World
Authors: Beckwith Robin
Published: February 2015

With the rise in hydraulic fracturing over the past decade has come a steep climb in proppant demand. Global supplies are currently tight. The number of proppant suppliers worldwide has increased since 2000 from a handful to well over 50 sand, ceramic proppant, and resin-coat producers. The estimated amount of proppant used has grown tenfold since 2000, when little more than 3 billion lbs was supplied, according to research by PropTester and Kelrik. Circumstances appear favorable for those seeking to enter the market.

However, gearing up to take advantage of these propitious conditions represents a daunting task, requiring coordination of complex logistics, material resources, and processing knowledge, as well as a substantial capital investment in processing and material handling facilities.

The price proppant manufacturers can charge must be figured in to the overall cost of producing a well, which in the Bakken, for example, can be approximately USD 6 million, with proppant representing about 5% of well costs. Since a majority of proppant is currently used in fracturing unconventional gas wells, depressed natural gas prices tend to keep a cap on the prices proppant suppliers can demand.

However, as hydraulically fractured wells proliferate, a growing body of data is continually being generated to aid in the creation of targeted fracture stimulation plans, with more highly engineered stages—boosting the demand for greater volumes of proppant—being performed per well to maximize production. For example, a typical Barnett Shale well would in the early 2000s have consumed approximately 300,000 lbs of proppant. The longer horizontal wells drilled today, produced with often 20 or more stages, might consume 3 to 5 million lbs.

Still, proppant supplier margins are relatively slim, requiring the steady, high-quality production and distribution of large volumes to sustain a profitable enterprise.

Proppants: Earth to Earth

The journey of an individual grain or bead of proppant is a circular one, making its way from its origins as a substance mined from the Earth to its final destination deep within the Earth in the far reaches of the filigree-like or dendritically shaped fractures emanating from the long horizontal borehole. It is the only substance operators want to remain downhole following a successful hydraulic fracturing treatment and performs the vital function of propping open the fractured formation to promote the economic flow—or conductivity—of hydrocarbons in the ensuing months and years over the well’s productive life.

The primary order of business for a proppant facility, therefore, is choosing the optimum location—preferably one close to both raw material supply and end-user. The immediate proximity of railcar and possibly barge transport is critical, as well as a good road system and the availability of a reliable trucking fleet.
Well-Integrity Issues in Malacca Strait Contract Area
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 129083, ’Well Integrity Issues in Malacca Strait Contract Area,’ by Weka Janitra Calosa, SPE, and Bambang Sadarta, SPE, EMP Malacca Strait, and Ronaldi, WCS Indonesia, originally prepared for the 2010 SPE Oil and Gas India Conference and Exhibition, Mumbai, 20-22 January. The paper has not been peer reviewed.

The Malacca Strait contract area is east of Sumatra Island between Sumatra and the Malaya Cape. This area started oil production in the early 1980s, and consists of 175 onshore and offshore oil wells spread over five fields. A 7.9 Richter scale earthquake occurred on 12 September 2007. Two days later, during a snubbing unit service on Well K-02, the 95/8-in. casing suddenly dropped down 6 ft. It was believed that the area had been affected by the earthquake. Following the incident, the well-services team inspected Well K-02 and found that it had an integrity problem.

Introduction

Following the Well K-02 incident, historical records were examined, and it was found that the Well K-02 incident was not the first. Several well incidents had been reported previously with significant impact and potential for serious accidents. This created the awareness that there might be a wider issue, and a comprehensive well-integrity study was initiated to obtain better insight into the well-integrity situation for all wells within the block. The scope of the study was the following.

To evaluate the well-integrity status of all wells.

To review the possible causes of the well-integrity problems.

To generate workable engineering recommendations to extend the economic life of the production wells safely.

To include well-integrity considerations in future well-planning and operation procedures.

To build a comprehensive database of well-integrity condition and solutions.

Well Integrity. Well integrity, is defined as the application of technical, operational, and organizational solutions to reduce the risk of an uncontrolled release of formation fluids throughout the life cycle of a well. There are various facets to well integrity, including accountability/responsibility, well operating processes, well service processes, tubing/annulus integrity, Christmas-tree/wellhead integrity, and testing of safety systems. Well barriers are envelopes of one or several dependent well-barrier elements to prevent fluids or gases from flowing unintentionally from the formation into another formation or to surface. Interrupted barrier elements are related to well integrity and are crucial from the point of view of safety, but are also important concerning production regularity and cost. Lack of well maintenance may interfere with the well-barrier concept.

Well-Integrity Field Survey

The survey was conducted to compile a well-integrity database based on the status of the well barriers, using the following basis for evaluation.
History Matching With Learned Sparse Dictionaries
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 133654, ’History Matching With Learned Sparse Dictionaries,’ by Mohammad-Reza M. Khaninezhad, Behnam Jafarpour, SPE, and Lianlin Li, Texas A&M University, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed.

History matching of heterogeneous hydrocarbon reservoirs is carried out to construct predictive reservoir models. Estimating individual-gridblock heterogeneous-reservoir properties from limited static data and spatially averaged dynamic-production measurements inherently leads to an ill-posed inverse problem that can have several nonunique solutions. To achieve solution sparsity, an iteratively reweighted-sparsity regularized least-squares algorithm is used to combine and weigh a small subset of relevant model elements selectively from a learned dictionary that explains the observed data.

Introduction

History matching of hydrocarbon-reservoir models is required to integrate production data that constrain uncertain previous descriptions of model parameters (i.e., spatially distributed petrophysical properties). The main goal of history matching is to construct updated models capable of predicting future performance of the reservoir more accurately. Reconstructing petrophysical properties is a challenging inverse problem because of data scarcity and because these properties are heterogeneous. When spatial discretization of the forward-simulation model is used to describe unknown spatial parameters in history matching, the problem typically becomes ill posed because the number of unknown parameters overwhelmingly exceeds available observations. Consequently, several nonunique solutions can exist that respect available observations but exhibit different spatial continuity and flow predictions. Several techniques can regularize ill-posed history-matching problems. Usually, regularization involves incorporating additional prior assumptions to eliminate implausible solutions and improve the stability of solution algorithms.

Reparameterization

Reparameterization of the original spatial problem is a regularization approach for ill-posed inverse problems in which a reduced number of parameters is used to approximate the unknown-petrophysical-property maps. Reparameterization is facilitated when reliable a priori information about structural attributes of the solution is available.

Mathematical transformations provide an effective reparameterization approach when the properties of the unknown parameters are exploited better in the transform domain. For example, principal-component analysis (PCA) is effective in reparameterizing correlated parameters by elimination of their correlation (redundancy). Other popular transform-domain reparameterization methods that have compression properties include the discrete-cosine transform (DCT) and the discrete-wavelet transform (DWT).
Real-Time Field Monitoring To Optimize Microbe Control
Authors: Keasler Vic
Published: February 2015

Technology Update

Microbial growth in oil and gas systems can cause numerous problems that result in production downtime, lost revenue, and safety concerns. Unfortunately, microbial populations are ubiquitous in many oil and gas production zones and minimizing their impact is challenging. The most common effects of microbial growth are corrosion, hydrogen sulfide (H2S) production, and biofouling.

The ability to minimize the negative impact of microbes is confounded by the current field monitoring technology, which is unable to detect many of the organisms. These monitoring technologies are culture-based, meaning that organisms must be grown in culture to be detected and quantified. It is well documented in many systems that less than 1% of the total organisms present are culturable. In addition, the culture-based methods commonly take days or weeks to produce a result. Thus, operators must wait a considerable time before taking control measures, and the impact of microbial populations can increase during the long period of undetection.

New Development in Monitoring Method

Two essential parameters for any new field monitoring technology are the ability to obtain a result in real time and the ability to detect all organisms, not just the ones that can be grown in culture. The industry has evaluated several of these technologies over the years, including a first-generation adenosine triphosphate (ATP) assay in which the level of ATP is used to measure the number of actively growing microbes in a sample.

ATP is the molecule used by cells to drive any process that requires energy. This includes metabolism, protein translation, DNA repair, and cell division. Although there are differences in the absolute quantity of ATP in different species or organisms, it is assumed that actively growing bacterial cells hold relatively similar amounts of ATP, and a calculation has been determined to quantify microbial cell numbers based on a measurement of ATP.

The major challenge of using this technology in oilfield systems is that the enzymatic assay used to quantify ATP is very sensitive to the quality of the fluids tested. This means that many oilfield fluids such as oil, emulsions, produced water with significant solids, high-salinity fluids, and fluids contaminated with certain chemicals would not yield meaningful results. As an example, the first-generation ATP test was not generally accepted by oilfield operators and has been little used. However, a second-generation ATP test that addresses the concerns has been developed recently. Specifically, additional steps were developed to enable accurate testing of fluids that contain oil, high salinity, residual chemicals, and solids. This technology also meets the other necessary criteria—real-time results and detection of all microbes, not only those that grow in culture.
Hydraulic Fracturing 101: What Every Representative, Environmentalist, Regulator, Reporter, Investor, University Researcher, Neighbor, and Engineer Should Know About Hydraulic Fracturing Risk
Authors: King George E.
Published: February 2015

Management - This is an excerpt from SPE 152596.

The use of horizontal wells and hydraulic fracturing is so effective that it has been called “disruptive.” That is, it threatens the profitability and continued development of other energy sources, such as wind and solar, because it is much less expensive and far more reliable. Not only that, but compared with coal, natural gas produces only half the carbon dioxide and almost no sulfur, nitrous oxides, or mercury.

Those demonstrable benefits over both traditional and alternative energy draw monetary and political attacks. Some university and media reports have focused on two main environmental concerns about using hydraulic fracturing to recover shale gas:

Groundwater and/or surface-water contamination by methane or chemicals

Escape of methane gas to the atmosphere

These risks come from well construction, transportation of chemicals and fluids to the well site, and operation of the wells and the gas-transport system. This paper is an abbreviated analysis of a larger document on factual information about the purported risks of hydraulic fracturing:

1. Deep-well hydraulic fracturing does not travel through the rock far enough to harm fresh-water supplies. Thousands of field-monitoring tests and millions of fracturing jobs have confirmed this point.

2. In the deep, properly constructed wells that produce most US shale gas, the chance of even minor water contamination from fracturing chemicals is less than one event in a million fracture treatments, based on statistical analysis. When compared with the frequency of pollution from chemical dumps, acid mine drainage, general manufacturing, oil refining, and other energy- or product-producing activities, natural gas from conventional and unconventional sources generates more energy with the least impact and fewest problems.

3. Even as underground fractures grow (mostly outward with limited upward and downward growth), the total fracture extent remains thousands of feet below the deepest fresh water sands. The height of any fracture is limited by rock stresses, leakage of fracturing fluids within the target fracturing zone, and the hundreds of natural rock barriers that border the shale zone. Typical fracture height is 100 to 300 ft and separation between the top of the fracture and the deepest fresh water sands ranges from 3000 to over 5000 ft.

4. Water contamination due to spilled industrial chemicals occurs rarely and even less so for fracturing chemicals and comes exclusively from careless road transport, on-site storage and surface mixing, or well construction. These failings can be addressed successfully with existing technology and effective regulations. It is interesting to note that the states with the fewest problems are those with strong state regulations. Appropriate regulations already exist in most producing states and work very effectively to protect the environment.