bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comments: JPT Reader Survey
Authors: Donnelly John 
Published: February 2015

In May, JPT surveyed SPE members to get their assessment of this magazine and their suggestions for ways to improve it and make it more relevant to them. The online survey was sent to a random sample of members worldwide. Of the respondents, one-third were from the U.S. and two-thirds outside the U.S.; half were engineers, and a quarter were managers; and 32% work for service companies and manufacturers, while 21% work for international oil companies, 19% for independents, and 7% for national oil companies. To the more than 2,000 members who responded, thank you for taking the trouble to complete the survey. It will help us do a better job of giving you the information you need in your work and in your careers.
Now, to the findings. The overall content of JPT was rated “good” to “excellent” by 95% of the survey respondents. This is slightly higher than the feedback we received in our most recent reader survey 2 years ago. JPT is considered to be “useful in their jobs” by 88% of readers; again, a little higher ranking than the previous survey. Employees at national oil companies find the information most useful.
The most popular features in the magazine, in order, are Technology Update, Technology Applications, the summaries of the technical papers, and the quarterly Case Study feature. The Case Study article was added after the 2003 survey found that our readers wanted more case study and practical application information. The most popular technical topics, in order, are: field development; high-pressure/high-temperature challenges; multilateral/extended reach; mature field revitalization; well stimulation; horizontal and complex trajectory wells; reservoir performance and monitoring; formation evaluation; production operations; and well testing. The most favored nontechnical topics include career development articles, compensation and salary surveys, project management information, industry software reviews, and oil and gas industry politics.
Techbits: Drivers of Deepwater Development in the Asia Pacific Region
Authors: JPT staff _ 
Published: February 2015

Ramlan Malek, Petronas General Manager—Petroleum Management Unit, and Ricardo Beltrao, Petrobras General Manager, set the stage for discussion among 78 participants representing numerous countries at the SPE Applied Technology Workshop (ATW) “Managing Deepwater in the Asia Pacific Region.” Held in Bangkok, Thailand, the ATW featured two keynote speakers: Malek on “Challenges in Managing Deepwater Field Development in Malaysia” and Beltrao on “New Technologies for Field Development in 3000-m Water Depths.”
Water depth in the Asia Pacific Region is defined as follows.
- Shallow water—depth less than 200 m.
- Deep water—depth greater than 200 m but less than 1000 m.
- Ultradeep water—depth greater than 1000 m.
Highlighting some successful deepwater operations/development projects in the region and future projects on the horizon including Unocal’s Gendalo Subsea, Shell’s Gumusut/Kakap and Malikai, and some China Natl. Offshore Oil Corp. (CNOOC) ventures, production in the Asia Pacific Region will increase 60% by 2020, with most of the energy resources coming to production from deepwater assets. The challenge will be to develop these projects reliably, affordably, and in a timely manner, requiring close cooperation among host authorities, oil companies, and service providers. Speakers noted that a paradigm shift in mindset is needed to accommodate current operating experience in shallow water to the new potential deepwater environment. Commentary called for investment portfolios to be reshaped to address the need for technical proficiency and for efficient operations requiring a highly focused group to develop, build, and integrate deepwater business.
The topic of “value erosion” in gas-handling projects and the industry’s need to invent and apply novel market solutions were other pertinent topics on which speakers and audience members presented their views. Also, cost reduction in Asia Pacific’s deepwater projects will come from the impact of new technology. While much of the technology is remotely operated, people will have a significant impact on how that technology is leveraged and in combining these technologies to create full-life-cycle savings.
In addition to exploring the different corporate strategies for managing deepwater field development and operating experiences of the various regional operators, such as Shell in the Philippines, Unocal in Indonesia, and Petronas in Malaysia, the workshop focused on technical and commercial challenges. Participants conferred on eight technical challenges, from obtaining accurate metocean data for design development to geohazards.
Overview: Cementing Technology (August 2005)
Authors: Benge Glen 
Published: February 2015

If only we knew.
Did we do it right? Did we get the results we wanted? These simple questions have been difficult to answer for cementing since the first job was pumped. We usually can tell when things did not go as planned. Proving we got it right is an entirely different matter.
There are many methods and tools available to try to prove the job actually gave the desired results.
We can evaluate with pressure testing. If the test passes, then the cement job is deemed a success. Then there are logs. These attempt to tell us if we got the cement in the right place, and maybe something about the quality of the cement. However, even with the most sophisticated logs, we still cannot be sure we have hydraulic isolation in every well.
If only we could be sure we would do our job right. Maybe then we could have the confidence to change our casing designs and take advantage of the added support from the cement. If only we could be certain we did our job right. We would have more confidence that the seal we put in place would really last for the life of the well.
Did the cement set up in the right place at the right time? Are the cement properties what we need for the life of the well? Is there isolation in the wellbore that will last for the economic life of the well and beyond?
Designer slurries, sophisticated spacers, and advanced computer simulators are readily available. We still face the challenge of knowing the cement job actually went as designed and we got the results we wanted.
If only we knew.
Available from the SPE eLibrary: www.spe.org
SPE 88005 - “Use of Cement as Lost-Circulation Material—Field Case Studies,” by Fidan, E., SPE, Halliburton, et al.
SPE 90450 - “Characterizing Casing/Cement/Formation Interactions Under Stress Conditions: Impact on Long-Term Zonal Isolation,” by Mueller, D.T., SPE, BJ Services Co., et al.
SPE 94288 - “Should Horizontal Sections Be Cemented and How To Maximize Value,” by Ilseng, J.R., Dan A. Hughes Co., et al.
Subsea Oil/Water Separation: Main Drives and Challenges
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 97375, "Application of Subsea Oil/Water Separation: Main Drives and Challenges," by M.W. de Figueiredo, Petrobras, prepared for the 2005 SPE Latin American and Caribbean Petroleum Engineering Conference, Rio de Janeiro, 20-23 June.
Petrobras is developing a subsea system for oil/water separation to minimize the effect that high water-production rates cause to the topside facilities when waterflooding an oil field. Most of the produced water can be separated at the seafloor and reinjected into the reservoir or into a water-bearing formation.

Introduction
During the exploitation-design phase of an oil field, activities focus on oil-production optimization. The oil-recovery mechanism is defined to maximize the recovery factor according to the reservoir and fluid characteristics. In most of the oil fields in Campos basin, waterflooding is used from the beginning of production. After water breakthrough occurs, the handling of produced water, which is a mixture of injected seawater and reservoir water, is of secondary importance during the design phase. Its priority increases only after water production increases. Conventionally, this water is separated from the oil and disposed of into the sea. This procedure takes place onboard the floating production units (FPUs) by use of very-large-volume vessels on a deck where space is critical, especially with the increasing plant capacity of recent units.
The use of a subsea system to separate most of the produced water at the seabed and send it somewhere other than the FPU plant is an attractive option. Such a system would allow the production plant to continue handling only a residual amount of water, eliminating new construction onboard to increase water-handling capacity. This system could enable adding extra oil-processing capability and, in many cases, increase oil production because of the lower wellhead backpressure that results from reduced water-lifting energy requirements.
Subsea separation presents challenging issues such as compactness and reliability. The full-length paper details this development, including the most promising scenario and the main benefits and challenges related to this scenario.
Benefits of All-Electric Subsea Production-Control Systems
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 17106, "Benefits of All-Electric Subsea Production-Control Systems," by M. Theobald and C. Lindsey-Curran, BP plc, prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May.
The oil and gas industry currently is using electrohydraulic subsea control systems as the standard to manage hydrocarbon production from subsea oil and gas fields. While these electrohydraulic controls will continue as the system of choice for the next 5 years, a desire to improve reliability and operational routines will increase the opportunity to use all-electric subsea production-control systems. The first offshore trial of an all-electric subsea production-control system and wellhead tree system was completed recently at the BP Magnus platform in the North Sea.

Introduction
To produce from greater water depths and harsher metocean conditions, the offshore industry has become technologically sophisticated. This applies both to the floating structures that support topside facilities in water depths greater than 200 m and the tieback technology to produce from long-distance remote step-out wells many tens of kilometers from the host facility.
In the early days of subsea tiebacks, each of the hydraulic valves needed to control the flow of hydrocarbons from the wellhead systems was controlled individually by a direct hydraulic connection back to the host facility and a topside control panel. The panel consisted of hydraulic pumps, motors, valves, and accumulators. This was a very successful and reliable concept because of its simplicity and relatively low cost. However, the limitation of direct hydraulics resulted in slow subsea-to-host actuator response times, and this limited tieback distance to approximately 15 km. In addition, the size and weight of the connecting umbilical hoses in all but the simplest of systems resulted in difficulties with transportation and installation. These limitations, together with the increasing requirements to collect reservoir-pressure and -temperature data, prompted the industry to develop more-sophisticated technology, including subsea control systems.
High-Quality Technologies as Pivots for Hydrocarbon-Reserves Expansion
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 94915, "Key High-Quality Technologies as Pivots for Hydrocarbon-Reserves Expansion," by J.B. Navarro, SPE, Delta Are & Capillary Services Ltd., prepared for the 2005 SPE Latin American and Caribbean Petroleum Engineering Conference, Rio de Janeiro, 20-23 June.
Digital-technology trends transform hydrocarbon-production dynamics and could increase world oil reserves. Several inherent systems and techniques are commercially available, although the support of specialized hardware is required to complete truly integrated projects. This paper highlights high-resolution crosswell-seismic visualization, downhole-sensors systems, massive data-capture and -integrating systems, and other technologies supported with digital resources, such as intelligent drilling and completions, which increase productivity in many scenarios and reservoirs in Mexico and worldwide.

Introduction
Technology is nothing more than applying the human mind to the task of finding a new or better solution. Development and application of a wide array of sophisticated technologies will be the hallmarks of successful companies in the future.
Within intelligent drilling and completions, the industry uses multidisciplinary technology including 3D and 4D seismic, highly propped hydraulic fracturing, tubingless well designs, multiple completions, high-resolution logging tools, numerical reservoir simulation, expert systems, and optimized multiple perforating systems for hard formations.
In Mexico’s northern-region wells, tubingless completions, integrated with advanced stimulation practices and reservoir analysis, improve production results from low-permeability formations. However, stimulation procedures depend on the well-completion method used.
Combining the use of propellants with perforating improved early production of the treated wells as well as propped-fracture treatments did. The concept of combining the propellant on a sleeve with the perforating gun is unique, and this technology shows promise of solving many inherent perforating problems.
Value of Information for a 4D-Seismic Acquisition Project
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 94918, "Value of Information for a 4D-Seismic Acquisition Project," by P.R. Ballin, SPE, G.S. Ward, C.V. Whorlow, and T. Khan, BP Trinidad and Tobago LLC, prepared for the 2005 SPE Latin American and Caribbean Petroleum Engineering Conference, Rio de Janeiro, 20-23 June.
Decisions regarding data acquisition should involve a cost/benefit analysis. While cost identification usually is easy, determining the value gained from new data is especially difficult when the benefits are mostly indirect. This is the case with 4D-seismic projects in which the main contribution is to reservoir and production management. This work describes the decision-tree process used in the life of complex seismic (LOCS) value-of-information study.

Introduction
In 2004, BP Trinidad and Tobago faced the challenge of valuing several seismic-survey options over the Greater Cassia Complex in the Columbus basin, Trinidad. The complex contains large gas reserves in five currently producing fields, several new field developments, and future exploration potential. Development of these reserves is complicated, having 27 stacked reservoirs with reserves trapped in more than 100 separate compartments. With an aggressive well program planned, the team had to identify and value the style of survey required to accomplish the following.
- Improve the static seismic image over the southern half of the complex, which is affected by shallow-gas imaging problems.
- Value the dynamic benefits that 4D seismic could offer for reservoir management and future well placement.
Seismic-While-Drilling Using a Swept-Impulse Source
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 92114, "Seismic-While-Drilling Using a Swept-Impulse Source," by J.J. Kolle, SPE, and K. Theimer, Tempress, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February.
This paper describes a prototype swept-impulse hydraulic tool capable of generating a broadband seismic signal at the bit while drilling. The source was designed to overcome the limitations of drill-bit seismic services by allowing operations with polycrystalline-diamond-compact (PDC) bits in inclined wells and in soft formations. The swept-impulse seismic source generated a broadband, high-intensity compressional-wave (P-wave) signal that can be used for high-resolution seismic profiling and look-ahead imaging while drilling.

Introduction
Seismic-while-drilling (SWD) services provide operators with real-time depth correction of seismic records to improve drilling accuracy and placement of liners. Pore-pressure prediction ahead of the bit would provide substantial benefits as a result of the reduced risk of blowouts. Between 1960 and 1996, there were more than 30 blowouts per year in Texas, Louisiana, and the U.S. Gulf of Mexico.
Seismic services offer the best approach to characterize formation pressures because of the substantial effect of pore pressure on seismic velocity. When integrated with other information (such as surface seismic, offset-well velocity profiles, and drilling parameters), it may be possible to predict pore-pressure levels at the bit and ahead of the bit. Through the Deepstar consortium, operators have developed the following criteria for pore-pressure-prediction services.
- No delay of conventional drilling operations.
- Prediction range of 1,000 ft ahead of the bit.
- Accuracy better than 50 ft.
- Provide formation velocities within 5% of a conventional wireline vertical-seismic profile (VSP) service.
- Real-time prediction—defined as less than 10 hours.
The service industry has developed a range of seismic techniques for seismic profiling and pore-pressure prediction. Existing practices include predrill seismic interpretation, wireline VSP, drillstring VSP, and drill-bit SWD.
Predrill seismic surveys can provide an indication of velocity anomalies. The value of seismic surveys is limited by the large depth uncertainty, particularly in exploration areas.
Wireline VSPs have been used to provide check-shot surveys using air-gun sources. On deepwater offshore rigs, the rig-time costs are high, and failure of the wireline may disable the blowout preventer, causing a loss of well control.
Drillstring VSP is a relatively new service that is similar to wireline VSP except that the receivers are on the bottomhole assembly. An air-gun array is deployed from the rig and fired multiple times while a connection is being made. Data from receivers are stored in a memory tool downhole for processing after the bit run.
Reply to Discussion of "Beyond Beta Factors: A Complete Model for Darcy, Forchheimer, and Trans-Forchheimer Flow in Porous Media"
Authors: Barree R.D. , Conway M.W. 
Published: February 2015

The authors of SPE 893251 would like to thank FracTech and Halliburton ERC for their discussion of the paper. The data presented in their discussion provide excellent examples of what drove Stim-Lab to investigate non-Darcy flow in more depth and to arrive at the conclusions presented in paper SPE 89325.
Although the data in the FracTech and ERC examples appear to fall on a straight line on the Forchheimer graph, the intercept value of permeability does not represent consistently accepted values of permeability for those proppants. For years, Stim-Lab had observed apparently linear Forchheimer graphs with an intercept value that failed to agree with the directly measured Darcy (low-rate) permeability. In this discussion we use ki as the apparent Darcy permeability from the intercept of the Forchheimer equation and kd as the directly measured Darcy absolute permeability at low rate. For Forchheimer’s equation to be valid, both slope and intercept, ki and β, must be equally valid. That is ki must equal kd and the straight line of slope β must intercept at ki = kd.
The FracTech data in Fig. D-1, representing test results for 20/40-mesh white sand at 1,000-psi stress, was digitized, and the apparent permeability at each point was computed from the inverse permeability. The data were plotted here in Fig. R-1 on the log-log inertial graph as the magenta diamonds. The coefficients from the FracTech linear regression of their Forchheimer graph were used to calculate kapp over a range of values of ρv/µ. The results are shown in Fig. R-1 as the solid blue line. Note that the FracTech data fall on a slope that is much shallower than −1.0, as indicated by the solid black line. The Forchheimer fit of their data yields an apparent value of Τ=34.86, kd=91.1 darcies, and does not approach a unit slope until ρv/µ approaches 1,000.
The red line on the graph is based on data from the Stim-Lab database and Predict-K. The database contains data sets for six 20/40-mesh sand proppants with 28 measurements of permeability at approximately 1,000 psi net stress. The average directly measured Darcy permeability for these 28 tests is 288 darcies, with no test showing less than 202 darcies. This curve fits the FracTech data better than their own regression, honors the actual Darcy permeability for this proppant, and yields values of β and Τ consistent with the mean particle diameter of the sample. In comparison, the reported Darcy permeability value from the FracTech data fails to correlate with any published or estimated Darcy permeability values for 20/40-mesh proppant at this stress. The separation between the red and blue lines in the figure shows the error in permeability generated by the flawed Forchheimer analysis.