bluuebunny/crossref_metadata_2025_split huggingface dataset:
Economics and Technology Drive Development of Unconventional Oil and Gas Reservoirs
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 146765, ’Economics and Technology Drive Development of Unconventional Oil and Gas Reservoirs: Lessons Learned in the United States,’ by C.P. Flores, SPE, PB Energy Storage Services, and S.A. Holditch, SPE, and W.B. Ayers, SPE, Texas A&M University, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.
Advances in technology and better economics have supported the exploitation of unconventional reservoirs in the United States. The concept of the energy-resource triangle put forth by J.A. Masters in 1979 explains that unconventional oil and gas are abundant but the exploitation of these resources is particularly sensitive to both technology and commodity prices. Here, the effects of technology and various geopolitical and economic events on US unconventional production are assessed in the context of Master’s resource-triangle theory (RTT).
History of Commodity Prices—Oil- and Gas-Price Fluctuations
Traditionally, commodity prices have been the result of the supply and demand in the markets; however, on occasion, organizations have restricted production to try to affect prices. The fluctuations in oil prices are also related to various political events.
Major critical petroleum-related events from 1861 through 2006 explain fluctuations in oil prices. The Pennsylvania oil boom in the 1860s saw prices reaching a peak of USD 104.35/bbl (in 2006 dollars) until the oil boom began in Texas with the discovery of the Spindletop (1901) and East Texas (1930) fields. The boom in Texas originated a period of stable, low prices sustained by product availability. In 1931, oil prices fell to a low of USD 8.66/bbl (in 2006 dollars) and continued to be relatively stable until the oil crisis in the Middle East during the 1970s. The Yom Kippur war in 1973, the Iranian Revolution in 1978–79, and the Iraq invasion of Kuwait in 1991–92 caused spikes of USD 14.99/bbl (in 2006 dollars), USD 88.13/bbl (in 2006 dollars), and USD 29.71/bbl (in 2006 dollars), respectively. In 1998, the Asian financial crisis saw prices fall to USD 16.22/bbl (in 2006 dollars), but, in 2006, oil prices quadrupled, reaching USD 65.14/bbl. The increase in oil prices continued until recently with prices of approximately USD 70/bbl.
Political, economic, or social events are, among other parameters, responsible for oil-price fluctuations. Historically, periods of high prices have benefited the exploitation of unconventional reservoirs because these reservoirs require costly stimulation methods to produce at economic rates. The link between periods of high price and development of unconventional reservoirs supports the RTT.
Technology Focus: CO2 Applications (July 2012)
Authors: Rogers John D. 
Published: February 2015

Technology Focus
Last year in this focus on CO2 applications, I (as others have) connected enhanced oil recovery (EOR) as an enabling business foundation and a possible way forward to accomplish carbon capture and storage (CCS) as a business investment. This year, in an address to the CCS conference in Pittsburgh, Pennsylvania, US Department of Energy (DOE) Assistant Secretary of Fossil Energy Charles McConnell encouraged the CCS industry to help operators establish a salient business case between CO2 EOR and usage and sequestration. Creating a technical lead in CO2 EOR and other usage technologies establishes an opportunity to commercialize the technologies that could be in high demand in the years to come, particularly in coal-reliant developing countries such as China and India.
The technologies needed to accomplish carbon capture, utilization, and storage (CCUS) require expertise in science and engineering that, in some cases, are not completely matured or, at least, require a different focus and commitment in science and business to affect CCUS. An acceptable return on investment will depend on economic CO2 capture and largely on regulatory stability.
Administratively, the US Environmental Protection Agency proposed a carbon pollutions standard for new power plants, which will have to meet 1,000 lbm of CO2 per electrical megawatt-hour produced. Older coal plants average approximately 1,768 lbm of CO2 per megawatt-hour but are exempt from the standard, as are plants permitted to begin construction within a year. A typical natural-gas electricity-generation plant emits 800 to 860 lbm of CO2 per megawatt-hour.
Recommended additional reading at OnePetro: www.onepetro.org.
IPTC 15029 An Integrated Reservoir-Simulation/Geomechanical Study on Feasability of CO2 Storage in M4 Carbonate Reservoir, Malaysia by Rahim Masoudi, Petronas, et al.
CMTC 151027 NETL CO2-Injection and -Storage Cost Model by T.C. Grant, US Department of Energy, et al.
SPE 154539 Evaluation of the CO2-Storage Capacity of the Captain Sandstone Formation by Min Jin, Heriot-Watt University, et al.
SPE 145440 Monitoring on CO2 EOR and Storage in a CCS Demonstration Project of Jilin Oil Field China by Shaoran Ren, China University of Petroleum, et al.
CMTC 151716 The Longannet to Goldeneye Project: Challenges in Developing an End-to-End CCS Scheme by P.J. Garnham, Shell, et al.
Shale 2.0: From Efficient to Effective Shale Development
Authors: Meisenhelder Jeff 
Published: February 2015

Guest editorial
Hydrocarbons from shale were first produced commercially as long ago as 1821, and from the 1860s through the 1920s gas was produced from shallow, low-pressure, naturally fractured shales in the eastern US. However, today’s shale “revolution” did not really begin until 1985. That was when George Mitchell started developing a model for economically viable exploitation of the Barnett Shale. It took almost 20 years and literally hundreds of wells to find the right formula, based on two transformative technologies: horizontal drilling and multistage hydraulic fracturing.
Shale 1.0: The Quest for Operational Efficiency
Since roughly 2005—the beginning of what I call Shale 1.0—we have successfully revived old shale plays and developed new ones. Every year, North American companies complete thousands of wells in shale reservoirs. However, even in mature plays like the Barnett, where productivity per well has doubled or tripled over the past decade, as many as 30% of all perforation clusters contribute absolutely nothing to production. That is the same as drilling 30 totally nonproductive wells out of every 100. To improve shale economics, operators and oilfield service companies have focused considerable brainpower and technical resources on reducing the unit cost of production through greater operational efficiency.
In many cases, we have brought drilling and completion costs down 50%, largely through application of new technologies, efficient project management, and supply chain negotiations. In some cases, advanced drilling technologies, automation, and real-time data have slashed average time to total depth from 48 days to just 8. Not all new technologies are exotic. For example, installation of rupture disk valves—which replace coiled tubing or drillpipe-conveyed perforations for the first stage in horizontal wells—reduced completion costs in 15 Eagle Ford wells by more than USD 100,000 per well.
The shale revolution has yielded many economic and social benefits, including growth in jobs and local businesses across the US, lower domestic energy costs, reduced CO2 emissions, and—perhaps most important—access to a new national resource that holds enormous potential for long-term energy security.
According to the Institute for Energy Research, the US has more than 200 years’ capacity of technically recoverable oil reserves and 110 years’ worth of natural gas at current rates of consumption, much of those from unconventional plays. In fact, shale oil is leading the current growth in US crude production. The US Energy Information Administration conservatively predicts global shale oil production will reach more than 4 million BOPD by 2030. Other analysts double that estimate.
Mobile Mixer Adds Dry Friction Reducer to Fracturing Fluid at the Wellsite
Authors: Nakra Geeta , Wright Steven , Wright David 
Published: February 2015

Technology Update
A mobile system has been developed that mixes consistent solutions of powder-based friction reducers (FRs) at the wellsite and adds them to hydraulic fracturing fluid. The use of the system has achieved reductions in fracture stage cycle times of as much as 10% and significant cost savings, compared with the convention-al use of oil-based liquid emulsion FRs in slickwater fracturing fluids.
In addition, the use of powder-based FRs reduces the potential of the FR solution freezing, settling, or gelling and eliminates the hazard of liquid FR spillage in work areas.
Water-soluble dry polyacrylamide can be used as an FR, with the selection of a polymer dependent on water quality. Dry FRs can perform in waters ranging from fresh water to high-brine produced water.
The challenge to developing the use of dry FRs in fracturing fluid was the ability to hydrate them on a treatment site. The PowderFrac mobile mixing and feeding system developed by SNF has performed successfully in the field since its initial deployment in the Barnett Shale of Texas during 2011. The system provides onsite storage, hydration, and dose control of the powder FRs.
The mobile unit enables well operators to reduce logistics and labor costs, and the chemistry of the dry FR solutions is also less costly. Deployment of the mobile unit does not require the modification of equipment or infrastructure at the fracturing site. The unit was designed and built with field replaceable parts to ensure prompt, cost-effective vehicle maintenance while deployed.
The equipment includes a patented Polymer Slicing Unit (PSU) for rapid hydration of the dry FR. The PSU can operate at treatment rates up to 120 bbl/min. Additional equipment consists of two solution tanks, a 12,000-lbm dry storage container, a horizontal screw conveyor, water filter pots, water pumps, FR solution pumps, and a self-contained generator system that can be fueled by an onboard tank or the saddle tank of the tractor.
Safe deployment and operation is a crucial part of the unit’s design. All electronics capable of data recording can perform reporting and analysis. The mobile unit, 45 ft in length, requires no special transport permits and can be refilled with dry powder FR by a powder bulk truck.
The friction reduction from a polyacrylamide will be affected by water quality and salinity and any other additives in the fluid that interact with the polymer. Concentrations of FR are adjusted during the treatment to lower or raise the pumping pressure.
CLD Rigs, MPD Change Equation for Deepwater Well Control
Authors: Grayson Brian 
Published: February 2015

Technology Update
Closed loop drilling (CLD) systems and managed pressure drilling (MPD) are challenging long-held industry ideas about well control. This realignment in philosophy is happening because of a unique ability to precisely monitor, analyze, and control wellbore pressure in real time.
These capabilities are the basis for a growing number of proactive and reactive methods and tools that are solving many conventional well control problems. This is particularly true in the extremes of deepwater drilling, in which managing wellbore pressure plays a principal role in safety, efficiency, and even the ability to drill the well. Fig. 1 presents many of the critical issues addressed by advances in MPD.
Although the number of deepwater MPD applications is relatively small, the advantages being achieved with closed loop systems are driving its increased use and the development of specialized deep-water MPD technology and drilling rigs.
Monitoring and Control
MPD reduces well control events and pressure-related wellbore problems by addressing two key challenges associated with conventional methods: the uncertainty of the predrill model and the inflexibility of the resulting well design and mud regimes. These challenges are overcome by a dynamic capability that is counter to static predrill models.
Uncertainty is reduced by very precise measurements of wellbore pressure profiles in real time. Just as important, MPD complements this information with equally precise real-time control. This dynamic solution is proving a key enabler for enhancing safety, efficiency, and operational capabilities in deepwater drilling.
To achieve these capabilities, MPD builds on the inherent characteristics of a closed loop system. Within this contained, pressurized wellbore environment, pressure is closely monitored. Pressure changes, such as those caused by an influx, loss, or ballooning, are rapidly detected and controlled in increments as small as a few barrels. Accurate fingerprinting of these minute pressure oscillations quickly identifies the event, which both informs an effective response and avoids a misdiagnosis that can exacerbate the condition.
The MPD control response is initiated at the surface by automatically or manually varying the annular backpressure by using a specialized MPD choke manifold. These changes within the closed fluid system are used to manipulate downhole pressure without the delay, cost, and imprecision of changing mud weight.
The ability to immediately dial in and hold the desired wellbore pressure changes the well control equation fundamentally with a new set of proactive and reactive pressure management options.
Micro influxes that are the precursor to well control events are quickly managed before they can escalate into a kick. When kicks occur, they are rapidly identified, controlled, and circulated out of the well. This mitigates a significant source of risk and nonproductive time (NPT).
Well Capping Becomes an Industry of Its Own
Authors: Rassenfoss Stephen 
Published: February 2015

Well Control Improvements
The word to describe offshore well capping is more. There are more people being hired to manage more hardware in more places around the world, and there are more things under development.
A niche business within the offshore exploration and production sector has sprung up since the Macondo disaster destroyed the Deepwater Horizon in 2010, which killed 11 and flowed for months before it was finally capped. This growing industry is going to be a “lasting and ever-evolving” part of the business, said Kurt Kriter, Americas regional director for Oil Spill Response Ltd. (OSRL), which is one of the interlocking network of industry-owned organizations responsible for this growth.
Oil Spill Response is an industry-owned cooperative whose responsibilities include owning and managing equipment to quickly respond to out-of-control wells around the globe for another group created by nine big oil companies, called the Subsea Well Response Project (SWRP).
The four recently established hubs covering major oil regions around the globe feature four high-capacity capping stacks, which were built using design advice from the engineering departments of the SWRP members. The two highest-performance units can shut off a well flowing at 15,000 psi, and divert up to 100,000 B/D to surface vessels. When the last of the caps is delivered later this year to Brazil by Trendsetter Engineering, it will mark a transition for this business, which has been focused on building capping stacks, going from zero before Macondo to around 20 currently. The focus is shifting toward operations and developing improved response methods.
This year, OSRL is staffing hubs in Stavanger, Norway; Cape Town, South Africa; Angara dos Reis, Brazil; and Singapore, with six in each location, and 10 in its British well response center, said Jan Strom, director of subsea well intervention services for OSRL. The local teams are charged with maintenance and logistics, with support from outside advisors, such as Trendsetter, which has built nine caps, making it one of the largest companies active in this field.
Well capping companies began in the US, with Marine Well Containment Corporation (MWCC) and Helix Well Containment Group (HWCG). They were created to allow offshore exploration companies to share the cost of buying and maintaining the equipment needed to respond to well incidents. Macondo showed the need, and led to US regulations requiring operators to demonstrate they have access to the equipment and expertise needed to stop an offshore blowout. Now governments around the world have similar regulations.
Sour Gas Interest Grows in Middle East
Authors: Henni Abdelghani 
Published: February 2015

Middle East Sour Gas
Growing global demand for natural gas has pushed oil and gas companies to increase the development of sour gas fields, which contain about a third of the world’s gas reserves.
The defining chemicals in sour gas are often hydrogen sulfide (H2S) and car-bon dioxide (CO2), though in some cases, other sulfurous compounds such as carbonyl sulfide and mercaptans are also found. The higher concentrations in sour gas demand more intensive and more expensive development processes.
In the Middle East, developing sour gas fields have become a priority of local governments because of soaring regional gas consumption. In addition to tapping the development of new sour gas fields, companies in the region are also facing the issue of increasing level of sourness in operating fields in which the levels of H2S and other contaminants that were negligible on startup have become a problem later in production.
UAE: Moving Ahead
Fareed Abdullah, senior vice president (Bab and Gas) at Abu Dhabi Company for Onshore Oil Operations (ADCO), said the development of sour gas fields in the United Arab Emirates is a priori-ty given the growing gas requirements for power generation, gas injection to boost oil production, and the rising petrochemical sector.
“It is expected that the Shah field will produce first gas in the fourth quarter of 2014, and the importance of future sour fields such as Bab, Hail, and Shuwaihat plus others under evaluation is underlined by the current activity levels and consideration within the Abu Dhabi National Oil Company (ADNOC) Group,” he said recently at the Sour Oil and Gas Advanced Technology conference in Abu Dhabi.
“When the Shah field is operation-al in 2014, it is expected to increase gas capacity by 10.34 Bcm/yr, and all aspects of this project will serve as bench-marks for future sour gas development,” he said.
ADNOC selected Shell to participate in a 30-year joint venture to develop the Bab sour gas reservoirs in Abu Dhabi. Shell will hold a 40% equity stake with ADNOC holding 60%. The two companies are beginning commercial and technical work leading up to the development of Bab, which is 150 km southwest of Abu Dhabi. Gas from the field will supply local markets.
During the bidding process for the USD 10 billion deal, Shell recommended exporting the sulphur while another major bid recommended reinjecting it back into the reservoir. Once developed, the Bab field will produce 500 MMcf/D to 800 MMcf/D, but expertise is required to handle the large amounts of sulfur generated from the estimated 15% H2S content of the gas.
ADNOC has also sent letters to companies inviting them to submit bids for the offshore Hail sour gas field. With a CO2 content of 11%, Hail is less toxic than Shah or Bab. Because it is located in ecologically fragile shallow waters, ADNOC will proceed cautiously. Estimates suggest that Hail could produce up to 1 Bcf/D.
Q&A with Ali Rashid Al-Jarwan, CEO, Abu Dhabi Marine Operating Company
Authors: Al-Jarwan Ali Rashid 
Published: February 2015

Q&A
What is the current production capacity of your company? What is your contribution to ADNOC’s overall production?
We are on the growth agenda, as is the case with all global oil and gas producing countries. As a subsidiary of Abu Dhabi National Oil Company (ADNOC), Abu Dhabi Marine Operating Company (ADMA-OPCO) is playing a major part in the ongoing efforts to increase oil production capacity by 35% to 3.5 million BOPD by 2018 from the current 2.7 million BOPD.
This production target is set to be achieved through three major subsidiaries of ADNOC: ADMA-OPCO, Abu Dhabi Company for Onshore Oil Operations (ADCO), and Zakum Development Company. For ADMA-OPCO, we are planning to increase production by 370,000 BOPD over current production levels of 550,000 to 600,000 BOPD. The new production target will be achieved mainly from the Lower Zakum field (100,000 BOPD) with 270,000 BOPD from the Umm Lulu, Satah Al-Razboot, and Nasr fields.
Added to the Umm Shaif production share, which currently stands at 275,000 BOPD, and Zakum production of 325,000 BOPD, we are targeting a total production of 1 million BOPD by 2020.
Are the fields under development on track? What is the main scope of work at these fields?
Phase I of the Umm Lulu and Nasr fields is to assess reservoir behavior; however, we are already now moving to full field development of Umm Lulu. We awarded two pack-ages: The first package consists of seven towers and flowlines and a pipeline to Zirku Island to join SARB. For SARB, the company is moving to a full field development to produce 100,000 BOPD, and all seven engineering and construction packages have been awarded.
For the full development of SARB oil field, we have selected the construction of two artificial islands, SARB-1 and SARB-2, which are currently under construction by the ADNOC Civil Projects Division. The location of the islands is 120 km off the north-west coast of Abu Dhabi.
The onshore facilities engineering, procurement, and construction work under-taken by Hyundai covers processing, storage, and export facilities on Zirku Island and wellhead facilities on two artificial islands. Meanwhile, the offshore work undertaken by Petrofac mainly includes around 200 km of subsea pipelines, 55 km of subsea cables, a single point mooring crude loading facility, four offshore flares, and two riser platforms, in addition to drilling utilities on the artificial islands.
ADMA-OPCO has taken advantage of these major projects to develop and train young United Arab Emirates (UAE) nationals in engineering and project management.