bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-Time Optimization of Drilling Parameters
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 129126, ’Real Time Optimization of Drilling Parameters During Drilling Operations,’ by Tuna Eren, SPE, Eni E&P, and M. Evren Ozbayoglu, SPE (currently with the University of Tulsa), Middle East Technical University, 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 The paper has not been peer reviewed.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 objective of real-time optimization of drilling parameters is to optimize weight on bit (WOB) and bit rotational speed to achieve maximum drilling rate and to minimize drilling cost. An extensive literature survey of drilling-optimization research was conducted for the study described in the full-length paper. The general equation for rate of penetration (ROP) was optimized using actual field data.
Introduction
The objective of optimizing drilling parameters in real time is to arrive at a methodology that considers past drilling data and predicts drilling trends to advise of optimum drilling parameters to save drilling costs and reduce the probability of encountering problems. To achieve effective optimization, an extensive literature survey was conducted and the results of previous researchers were considered in developing a drilling-optimization methodology in a real-time environment. The linear drilling-ROP model introduced in 1974 that is based on multiple regression analysis was used in real time to:
Achieve coefficients of multiple regression specific to the formation.
Determine an ROP-vs.-depth prediction as a function of certain drilling parameters.
Determine optimum drilling parameters specific to the formation being drilled.
The following assumptions are considered to be satisfied so that the equations given in this study function properly:
Bottomhole cleaning is achieved effectively.
The bit and bottomhole-assembly combination in use is one that is selected properly for the formation being drilled.
The formation interval being drilled is considered to be homogeneous.
The rig and auxiliary equipment are functioning efficiently.
Data from three directional offshore wells in the Mediterranean area were used to test the methodology.
Literature Survey
Numerous detailed research studies have been performed for optimization of drilling activities with the objective of maximizing footage drilled and minimizing drilling costs. Drilling optimization can be achieved by preselecting the magnitudes of the controllable drilling parameters.
Most of the early studies described in the literature have foreseen a static drilling-optimization process. In the past, drilling parameters were required to be investigated off site because of the lack of ability to transfer data in real time. Recent studies have performed drilling optimization in real time; however among the investigated references, there is no work with statistical correlations in a real-time environment.
What Oil Can Learn from Forestry
Authors: Feunekes Andrea , O'Marah Kevin 
Published: February 2015

Guest editorial
In his JPT March column, 2011 SPE President Alain Labastie made a compelling call for innovation and creativity. In “Innovation and Creativity Needed,” he said, “Innovation will be one of the keys for unlocking future production—new problems will need new solutions. Our innovation will be dependent on how rapidly we develop technology and our creativity in applying that technology. … Our creativity will be required to find really new solutions, through step-changes in applications as well as significant new uses of technology.”
He is right. Moving forward requires innovation and creativity—and risk taking. Some of the ways to accomplish this may lie in lessons learned from other sectors.
Forestry, for example.
Forestry is a tough industry, dealing with a mix of public and private lands, and facing a heavy regulatory environment, established competition, and the very low margins of a nearly pure commodity. Operating under these pressures for many decades has forced the sector to dig deep, both in terms of operational efficiency and long-term risk management, to assure survival.
The oil industry in many ways shares this same set of pressures, but with dramatically better long-term profitability and a more strategic place in the economies of nations and the world. However, oil may be able to learn a few lessons from foresters who have wrestled with these issues for a longer time and with fewer margins for error.
Consider first the urgency to watch every nickel. The Fortune 500 list for 2010 includes only four forest and paper products companies. These four had combined profits for the year of only USD 590 million. The top four oil companies, by contrast, delivered USD 61.2 billion in profits for the year. Forestry has been around for hundreds of years and in the process has become so commoditized that most companies have had to radically rethink their operating and capital structure just to stay afloat. Like Weyerhaeuser, the best of them have been able to stay on top strictly because their approach to optimization in long-term operations prevents wasteful spending and maximizes market timing of the harvest.
Simple but expensive activities such as building and maintaining access roads, servicing equipment, and buying fuel are watched with extreme precision to assure some payoff for investors. Oil production, by contrast, is more often a race against time than budgets when new production is coming online. Considering the similarity in operational spending across the two sectors, it is worth looking at how the best foresters are able to keep the business going while operating under thin margins.
Hydraulic Effect of Tool Joints on Annular-Pressure Loss
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142282, ’The Hydraulic Effect of Tool Joints on Annular-Pressure Loss,’ by Majed Enfis, SPE, and Ramadan Ahmed, SPE, University of Oklahoma, and Arild Saasen, SPE, Det Norske and the University of Stavanger, prepared for the 2011 SPE Production and Operations Symposium, Oklahoma City, Oklahoma, 27-29 March. The paper has not been peer reviewed.
For a successful drilling operation, downhole pressure, or equivalent circulating-density (ECD), control is critical. Conventional drilling techniques require maintaining the bottomhole pressure (BHP) at a level between the pore and fracture pressures. In deepwater wells, the margin between these pressures is very narrow; therefore, the BHP and ECD must be predicted accurately and be maintained within that narrow margin to avoid kicks and circulation losses. The presence of a tool joint changes the annulus geometry between the drillpipe and the casing or hole, resulting in strong turbulence and fluid acceleration that generate additional viscous dissipation and pressure losses. Theoretical and experimental studies examined the hydraulic effects of rotating and nonrotating tool joints.
Introduction
While drilling oil and gas wells, drilling mud is circulated in the wellbore to transport cuttings to the surface and control the BHP. In conventional drilling operations, the mud is injected into the well through the drillstring (drillpipe) with a high-pressure pump. The mud flows through the drillpipe and exits the drill bit where it enters the annulus and flows up the annular space to the surface carrying rock cuttings. Significant pressure losses occur as the mud flows through the drillpipe and the annulus. The BHP, which is a critical parameter in any drilling operation, is a function of the hydrostatic head of the mud and annular-pressure loss. Hence, accurate prediction of the annular-pressure loss leads to a good estimation of the BHP and the ECD to prevent kicks and circulation losses. The ECD is a commonly used drilling term that represents the BHP in terms of equivalent fluid density. This means that it combines the density of the fluid and annular-pressure loss.
Previous studies focused on the hydraulic effects of a nonrotating tool joint. The purpose of this study was to examine hydraulic effects of tool joints under both static and dynamic conditions, and to develop models for predicting the change in annular-pressure loss caused by the tool joints.
Analyzing Variable-Rate/-Pressure Data in Unconventional Gas Reservoirs
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 149472, ’Analyzing Variable-Rate/-Pressure Data in Transient- Linear Flow in Unconventional Gas Reservoirs,’ by P. Liang, SPE, L. Mattar, SPE, and S. Moghadam, SPE, Fekete Associates, prepared for the 2011 Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed.
Often, wells in unconventional gas reservoirs exhibit linear flow during their transient period, and this transient behavior can last for several years. Currently, industry uses the type-curve-matching technique to analyze this linear flow. The common type curves assume that wells produce at constant rate. However, the production rate usually is variable and, in fact, is closer to a constant-pressure operation. The constant-pressure type curve is useful, but not suitable when both rate and pressure vary. It is necessary to have an easy-to-use method for analyzing variable-rate/-pressure data in linear flow.
Introduction
First, the formulation, type curve, specialized graphs, and superposition time used to analyze transient-linear flow for a deeper understanding of the theory are reviewed. Second, a practical and effective method for analyzing variable gas-production data is illustrated. In this development, the effect of skin on the type curve and on the specialized graph was studied. The constant-pressure solution was converted to its constant-rate equivalent by use of material-balance time, and it was found to be acceptable for practical purposes. Real time was converted to corrected pseudotime to account for variable gas properties, and it was determined that the effect would be small in the analysis of actual production data. The effect of outliers on superposition time also was investigated.
The dominant flow regime for wells in most unconventional gas reservoirs is linear flow. The reservoir model in Fig. 1a demonstrates linear flow. A vertical well is drilled in the center of a rectangular reservoir with a biwing hydraulic fracture. The length of the fracture is the same as the width of the reservoir, and the fracture is assumed to have infinite conductivity. These assumptions form the basic reservoir model of linear flow, from which the linear-flow solution was developed. Although this model is simple, it is suitable for analyzing more-complicated reservoir geometries. For example, Fig. 1b represents a cased-hole horizontal well with a number (nf) of equally spaced fractures. All the fractures are assumed to have the same fracture half-length xf. No-flow boundaries (dashed lines in Fig. 1b) form between the fractures. The performance of this system is equal to nf times that of the biwing fracture shown in Fig. 1a.
Permian Basin Oil History: Mirroring the Rise in Hydraulic Fracturing
Authors: JPT staff _ 
Published: February 2015

Permian Basin
What gave rise to oil drilling in the Permian Basin—in particular the Spraberry trend area? Why now the focus on the various Wolfcamp plays? What strategies and techniques have proven useful in exploiting the potential of the Spraberry—and now, of the Wolfcamp source rock? Who are some of the players, where are they buying, where are they holding leases or developing them—and how?
According to J. Michael Party, vice president for Exploration Reliance Energy, writing in the May 2012 AAPG Explorer, “The early exploration efforts in the Permian Basin started in Mitchell County on the basin’s eastern shelf, with a 10-barrel-a-day well [the W.H. Abrams No. 1 well] that opened the Westbrook field in 1920. This set off a frenzy of activity in the basin,” due in large part to the availability of inexpensive leases from the University of Texas Land System.
The true potential of the prolific and problematic Permian Basin, however, was not evident until the Santa Rita #1 well erupted on 28 May 1923. Spudded at a place called Texon in Reagan County, Texas, the project endured 21 months of cable-tool drilling that averaged less than 5 ft a day. After the Texon Oil and Land Company struck oil, the well produced until May 1990, and was named by Texas Monthly Magazine as the “Oil Well of the Century.”
This field, which came to be known as Big Lake, proved to be 4.5 sq miles. Its wells revealed that vast oil reserves in west Texas originated in both shallow and deep horizons.
The Westbrook and Big Lake field successes were followed by a series of discoveries, including the World and McCarney fields in 1925 and the Yates field in 1926. In 1928, a Big Lake well was drilled deeper than any in the world up to that time, to a depth of 8,525 ft.
According to the Texas State Historical Association (TSHA), before the Hobbs field discovery in 1928, all Permian Basin discoveries were made as a result of random drilling or surface mapping using Cretaceous outcrops that could give indication where structures were in the subsurface. “The Hobbs field discovery,” states the TSHA, “was made after magnetometer and torsion balance surveys both showed the area to be anomalous.”
Emerging Frontiers: Focus on Myanmar
Authors: Spath Jeff 
Published: February 2015

President's column
In this third column on emerging geographic frontiers, I want to focus on what may be the fastest developing country in the Eastern Hemisphere—politically, demographically, and certainly from the standpoint of upstream oil and gas. Myanmar, often referred to as Burma, has been largely isolated from the global economy for roughly 50 years due to oppressive military rule and extensive human rights violations. In 2012, under newly appointed president Thein Sein, Myanmar began to reform its foreign direct investment laws about the same time the US and the European Union began suspending sanctions. E&P industry players, large and small, have been watching and waiting for just such reformations and are now being attracted by the potential for huge growth in the existing gas production and the potential of the country’s 17 sedimentary basins, largely offshore and unexplored.
Production History
Myanmar is one of the world’s oldest producers of oil; it exported its first barrel of crude in 1853. Two oilfields discovered in 1887 and 1902 are still in production. Today, the country is a net importer of crude oil as 90% of production is gas, most of which is exported to Thailand. With a current production of 21,000 B/D, primarily from only two fields, the need and attraction of foreign investment is clear.
The sedimentary basins are extremely underexplored and much of the available geological data were acquired with outdated technology. Estimates of reserves therefore vary widely. In 2012, the Ministry of Energy estimated offshore Myanmar crude oil reserves at roughly 540 million bbl and natural gas reserves at 65 to 72 Tcf.
Myanmar Oil and Gas Enterprise (MOGE) was created in 1963, shortly after nationalization of the oil and gas industry, in an effort to consolidate the oversight and management of the various local and global efforts to increase reserves and production. However, foreign operators were not allowed to participate in the efforts until 1988, when generic foreign investment legislation was passed. The Ministry of Energy held its first formal licensing round for onshore blocks in 2011, but due to the existing sanctions, western companies were largely absent. More recently, 30 offshore blocks were offered for licensing in June 2013, including shallow- and deepwater blocks.
Participation was prolific, including most major international oil companies. In fact, according to an energy ministry source, foreign companies’ tenders will be given priority, as they have the technology and expertise required to bring the complex and costly deepwater resources to market. Significantly, the government waived the initial requirement that foreign companies partner with a Myanmar-owned firm for the deepwater blocks, which increased the participation greatly. Results of the bidding are expected in early 2014 but one thing is clear – interest in finding and developing deepwater resources is widespread and intense.
Developing Long-Distance Power-Distribution Systems
Authors: Jacobs Trent 
Published: February 2015

The vision of installing large subsea production facilities in remote offshore locations is today, simply not feasible. The problem is that subsea power systems are not designed to transmit high-voltage electricity to a production facility or pipeline tieback that may be under thousands of feet of water and 100 miles away from the nearest power plant.
Today’s subsea power-distribution technology is largely based on alternating- current (AC) technology, which, because of its electrical characteristics, can only be efficiently transmitted across a distance of 90 miles. In most cases, however, the effective distance is much less. On average, subsea tiebacks receive power from a platform or vessel located not more than 10 miles away and, in the case of most subsea processing systems, even closer. In an AC-supplied system, the flow of electricity alternates back and forth across the transmission line and is the form of electricity most commonly used in homes and businesses around the world. When long distances are involved, AC power distribution becomes a complicated operation and requires a great amount of attention to detail because of the physics involved with voltage regulation.
The search for an alternative to conventional AC systems has revealed the need for multiple technological advancements, from pressure compensated electrical switches to highly-conductive cables able to deliver power more efficiently. About 5 years ago, “We were looking at going to farther distances with alternating current instead of direct current (DC) because most of the equipment we have right now is AC powered,” said James Pappas, vice president of the Research Partnership to Secure Energy for America’s (RPSEA) ultradeepwater program.
He said that, after studying the issue, however, it was determined that using AC power could result in a 35% power loss in a 100-mile-long cable because of resistivity and other factors. Not long after that conclusion was reached, General Electric (GE) approached RPSEA with a concept to transfer all the power to a deepwater field with DC and then use a subsea transformer module located within the field to convert some of the power to AC. With this system, the expected power loss over 100 miles could be as low as 25%. “So, if you have AC components, it can convert power to AC for those components, and if you need DC, then it has DC components,” Pappas said. “It all sounds pretty simple until you want to put it in a package and then set it down in 10,000 ft of salt water.”
Technology Focus: Nanotechnology (February 2014)
Authors: Fleming Niall 
Published: February 2015

Technology Focus
Nanotechnology has enormous potential in the oil industry, with numerous applications currently under investigation. These include, for example, improvements in material design for enhanced resistance to corrosion or erosion, improved and enhanced oil recovery, improved understanding of reservoirs through use of nanosensors, nanocoatings that prevent the adherence of deposits, and use of nanotechnology in drilling and completion fluids along with production chemicals.
The key word with regard to nanotechnology applications in the oil industry is “potential.” Realizing that potential is another matter. A survey of SPE papers published in 2013 describing nanotechnology applications that have been implemented in the field showed only two. There are, of course, numerous explanations for the apparent lack of papers describing field experiences, with the most obvious being that we are in an early-phase technology development and it will take time for new products to emerge in the marketplace. Our industry can be cautious when it comes to new technology, and this resistance to change could be another factor here.
A further influence is the potentially unknown consequences of introducing nanotechnology into the environment. For example, much research is focused on the environmental effect of releasing nanoparticles and the potential health risk through inhalation along with the potentially damaging consequences of these particles entering the food chain. It will take time to work through these issues before nanotechnology can be described as mainstream.
Where does the future lie for nanotechnology in the oil industry? It is too early to say, with too many unanswered questions remaining. Nevertheless, given the effect that nanotechnology has had in other disciplines (for example, medicine), it would be surprising if nanotechnology had little effect on the oil industry.
The papers selected this year include two examples presenting field implementation of nanotechnology. Let’s hope that, in the future, many more papers of this type will appear in the SPE literature. JPT
Recommended additional reading at OnePetro: www.onepetro.org.
OMC 2013-105 Nanotechnology Applications in Drilling Fluids by Katherine Price Hoelscher, M-I Swaco, et al.
SPE 164461 Illuminating the Reservoir: Magnetic Nanomappers by Abdullah A. Al-Shehri, Saudi Aramco, et al.
SPE 166140 Crosswell Magnetic Sensing of Superparamagnetic Nanoparticles for Subsurface Applications by Amir Reza Rahmani, The University of Texas at Austin, et al.
Slick-Water and Hybrid Fracturing Treatments: Lessons Learned
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 89876, "Slick-Water and Hybrid Fracture Treatments in the Bossier: Some Lessons Learned," by Mukul M. Sharma, SPE and Phani B. Gadde, U. of Texas at Austin; Richard Sullivan, SPE, Richard Sigal, SPE, Robin Fielder, SPE, and David Copeland, SPE, Anadarko Petroleum Corp.; and Larry Griffin, SPE, and Leen Weijers, SPE, Pinnacle Technologies, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
To better understand the process of fracturing tight gas sands, a comprehensive data set was gathered and analyzed for the Bossier formation in the Dowdy Ranch field. The bottomhole treating pressures were higher than expected on the basis of the measured stress profiles. Effective fracture lengths derived from pressure-buildup analysis and history matching of production data were significantly shorter than designed fracture lengths (or those predicted from uncalibrated fracture models). The data collected and analyzed provided valuable insight into the performance of water and hybrid fracturing treatments in tight gas formations.

Introduction
Waterfracs and hybrid fracs are the stimulation treatments used in many low-permeability reservoirs. Typically, improving the performance of gas wells in marginal gas plays requires improvement of fracturing technologies. To ensure that these gas wells remain economically attractive, even at modest gas prices, completion and fracturing practices must be optimized.
Research was aimed at improving the performance and reducing the cost of fracture treatments by acquiring and analyzing fracture-treatment data from the Bossier play in east Texas. Six gas wells (data wells) were identified in the Dowdy Ranch field for a detailed analysis of the well and fracture-treatment data before, during, and after a fracture treatment. The full-length paper details data acquired in Anadarko Petroleum Co.’s Anderson No. 2 well, summarizes findings, and presents recommendations for better fracture treatments on the basis of lessons learned.