bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comments: Upstream Spending Optimism
Authors: Donnelly John 
Published: February 2015

Editor's column
More than halfway through the year, signs point to a continued steady recovery in the upstream oil and gas sector. Several new surveys show that companies are increasing E&P spending this year, in spite of a shaky global economic situation and reduced drilling in the US Gulf of Mexico because of the Deepwater Horizon accident.
This month’s Guest Editorial lays out the case for increased merger and acquisition (M&A) activity, based on economic optimism, which may continue for the rest of this year and into the next. The rise in shale gas appears to be the major source of momentum in M&A as large operators seek a stake in the game-changing unconventional play and oil reserves become more valuable in a potentially gas-saturated market.
Two major E&P spending surveys released recently forecast growth in E&P spending. The IHS Herold 2010 Global Upstream Capital Spending Report and Barclays Capital Original E&P Spending Survey both see significant rises in upstream capital spending this year. IHS Herold forecasts that E&P spending, excluding acquisitions, will increase 8% to USD 353 billion in 2010 compared to last year. The survey queried 110 of the largest publicly traded oil and gas companies.
This year’s rise compares to a 22% decline in upstream spending in 2009, when the global recession and tight credit markets forced companies to cut back. Smaller E&P companies in particular are benefiting from easier credit. The survey also confirmed that many companies are shifting their E&P focus away from gas to oil as oil prices continue to stay above USD 70/bbl. The survey predicts that because of the growing uncertainty over regulation caused by the Deepwater Horizon accident, some E&P spending will flow to onshore US activity or leave the US altogether.
Barclay’s spending report—a survey of 427 companies—forecasts that global E&P expenditure will rise 12% this year, with North American upstream spending rising faster than expected. US spending is increasing because of higher oil price expectations, the success of shale plays, and drilling to hold leases, but the threat of a deepwater drilling moratorium in the US Gulf of Mexico will lead to some spending reductions.
The report notes a decline in spending among Latin America companies. Venezuelan national oil company PDVSA has reduced its E&P spending by 25%, while spending by Mexico state energy firm Pemex has fallen 18% this year, according to the survey. Spending in Europe, the Middle East, and Africa is up slightly from a December 2009 survey forecast.
More than half of the companies surveyed expect upstream spending to continue to grow into next year. The survey says that 37% of the companies said they expect their spending will increase 20% or more, while 16% said they expected to increase spending by 10 to 20%.
Technology Focus: Formation Evaluation (August 2010)
Authors: Harrison Bob 
Published: February 2015

Technology Focus
Analysts of conventional logs, who routinely evaluate complex formations, may be less productive when faced with more-esoteric responses from modern tools, especially because the latter often are interpreted by the logging contractors themselves. This situation arises because available petrophysical software may not be capable of handling the new log responses, and the required interpretive algorithms often are claimed as proprietary and, therefore, are withheld.
Logging-contractor-generated results from new logs may bring additional insight that is not readily apparent from basic logging suites, but end users must beware of blindly accepting these results and the implication that the new tools are necessary.
Many published case studies that claim new logging services are essential do not prove that basic logs are inadequate. Readers should be skeptical if these conference papers do not conform to Richard Feynman’s exhortation, “The idea is to try and give all the information to help others to judge the value of your contribution, not just the information that leads to judgment in one particular direction or another.” We should always ask ourselves three questions:
Was the log really necessary?
Does it add new information or simply confirm what could have been determined from a basic logging suite? For example, a nuclear-magnetic-resonance log in shaly gas-bearing sands with oil-based-mud-filtrate invasion may be able to distinguish gas from oil, but invaded-zone fluids also can be solved for by use of a combination of conventional logs.
Is the logging-contractor interpretation correct?
New logs should be validated against careful traditional-log analysis, which has been calibrated against core.
Can operators improve on the logging-contractor interpretation?
Yes! Operators have more relevant data and local knowledge, so they can use the log data more effectively. Petrophysical software and a log analyst’s time cost much less than log acquisition.
Logging contractors should run a safe and efficient operation while acquiring good raw data. If they also can supply an interpretation, then this is a bonus. End users must not abdicate their responsibility for the interpretation of log data that their employer pays to acquire.
Formation Evaluation additional reading available at OnePetro: www.onepetro.org
SPE 125342 • “Reservoir-Rock-Types Application—Kashagan” by A. Francesconi, Eni, et al.
SPE 128013 • “Residual Hydrocarbons—A Trap for the Unwary” by T. O’Sullivan, SPE, Cairn India, et al.
SPE 130414 • “Fulmar Sandstones—Correcting Some Received Wisdom in the Greater Kittiwake Area (North Sea)” by G. Coghlan, SPE, Centrica Energy, et al.
Fluid-Pressure Gradients in Tight Formations
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 121982, ’Fluid- Pressure Gradients in Tight Formations,’ by J.A. Larsen, SPE, Statoil/ Consultant, and H. Urkedal and A. Lonoy, Statoil, prepared for the 2009 SPE Europec/EAGE Annual Conference and Exhibition, Amsterdam, 8-11 June. The paper has not been peer reviewed.
Economical production from low-permeability reservoirs is a challenge. The oil/water contact (OWC) may not be at a precise level in the reservoir, and the vertical span of the oil/water transition zone may be large in such reservoirs. Traditionally, the free-water level (FWL) and, hence, the water and oil zones are determined from the oil- and water-pressure gradients. Pressure gradients are, however, difficult to obtain in low-permeability media, and supercharging effects may be the result of mobile oil and water being at the same place in the reservoir.
Introduction
In the studied cases, vertical equilibrium between gravity and capillarity could imply that a large zone exists between oil and water that is frequently called the “oil/water transition zone” or “capillary-transition zone.” The fluid gradient derived from wireline-formation-tester (WFT) measurements showed a water gradient in the studied reservoir. The 130-m-thick vertical section was evaluated to have oil saturation generally higher than expected for residual-oil saturation, although the heterogeneous nature of the reservoir prohibited any direct conclusions. The main objective was, from a conceptual approach, either to verify a consistent relationship between water gradient and residual oil (paleozone) or, if no such conclusion could be made, try to quantify oil mobility. Only wells drilled with water-based mud were considered.
Initial Fluid Distribution in the Transition Zone. The capillary-transition zone can be defined as regions in the reservoir in which both oil and water are present, the water saturation is higher than the connate-water saturation, and the oil saturation is higher than the residual-oil saturation (i.e., both phases are mobile). Such regions need special attention for characterizing the initial conditions and for designing special-core-analysis programs for generating input data for dynamic simulations. The precision of production forecasting for primary-, secondary-, or tertiary-recovery methods relies on the proper description of the initial conditions in the reservoir.
Three types of initial fluid distributions can be defined and classified according to their distinct behavior. The main challenges are to select the correct oil/water capillary pressure function for deriving the water saturation and to find the correct position of the FWL. The OWC will, in most cases, be imprecise, and reference should always be made to the FWL, which may be above or below the OWC (deepest mobile oil).
Perdido Development: Subsea and Flowline Systems
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 20882, ’Perdido Development: Subsea and Flowline Systems,’ by G.T. Ju, H.S. Littell, T.B. Cook, M. Dupre, K.M. Clausing, E. Shumilak, SPE, and W.W. Schoppa, Shell, and W.A. Blizzard, Seahorse Deepwater Technology, prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.
The Perdido development is in the western Gulf of Mexico in 7,817 ft of water. It is being developed with sub-sea technologies to mitigate key development challenges including extreme water depth, rugged seafloor terrain, low-pressure reservoirs, and aggressive hydrate-formation tendency. An overview of the subsea and flowline systems and the associated flow-assurance strategy is presented. The enabling technologies were a subsea-boosting system (SBS) and the surface blowout preventer (BOP) for drilling and completing subsea wells.
Introduction
The Perdido development includes the Great White, Silvertip, and Tobago fields and is in the Perdido basin and fold belt in the Alaminos Canyon Protraction Area. This area is 200 miles south of Freeport, Texas, USA, and 8 miles north of the Mexico maritime border. All three fields are developed with subsea wells tied back to the host, which is a spar with full offshore-processing capabilities and pipelines for export.
Significant challenges include the following.
Extreme water depth—7,800 to 9,600 ft, representing significant installation, operation, maintenance, and flow-assurance challenges.
Problematic seafloor terrain—rugged seafloor terrain in this area includes geologic features such as fluid expulsion, seafloor erosion, and steep slopes. These features make the subsea-equipment layout and choice of host location extremely challenging.
Subsea-Hardware Installation From an FDPSO
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 20495, ’Subsea-Hardware Installation From an FDPSO,’ by Thomas J. Stensgaard, Murphy West Africa, and Charles E. White and Kevin R. Schiffer, Doris Inc., prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.
Subsea installation for deepwater-field developments requires specialized vessels to carry out the work. A floating drilling, production, storage, and offloading (FDPSO) vessel positioned directly over the drill center provides an alternative to traditional methods. Unique challenges related to subsea-hardware installation from an FDPSO and the methods developed to overcome those challenges are presented.
Introduction
The FDPSO is over the wells for direct access (Fig. 1). Therefore, performing subsea-construction and -intervention activities directly from the host becomes possible. The FDPSO provides a large stable platform from which these activities can be accomplished, but it has limited access and maneuverability, and challenges that must be addressed. These challenges were overcome in the Azurite field in the Mer Profonde Sud Block offshore the Republic of Congo. The FDPSO was fitted with a remotely-operated-vehicle (ROV) spread and a crane sized to install heavy hardware.
Subsea Scope and Field Architecture
The Azurite field subsea architecture was driven primarily by the excursion capability of the FDPSO, which was in turn determined by the mooring system, flexible-production-riser limitations, and water depth. All production and injection wells were required to be within a 45-m radius, enabling access by the drilling rig on the FDPSO. This close well spacing supported either a template development or a tight cluster of wells in a radial array around a subsea manifold. The cluster configuration was chosen, with wells surrounding a combined production/water-injection manifold as shown in Fig. 2. The multiphase pumps and a subsea distribution unit (SDU) were placed nearby but outside of the drilling circle to permit intervention activities from the FDPSO if problems arose.
FDPSO vs. Subsea-Construction Vessel
Several functional requirements must be provided for nearly all subsea-installation campaigns and include the following.
Transportation of equipment to the offshore worksite
Lifting capacity offshore
Means to lower equipment to and land equipment on the seafloor
Underwater control and intervention
Subsea-positioning capability
Typically, a subsea-construction vessel equipped for these functions is used. However, these vessels are expensive and have limited windows of availability. With the FDPSO, with the host directly over the drill center, an alternative to traditional subsea installation was studied. The FDPSO provides an inherently stable work platform from which to perform installation operations.
En Route: Increasing Recovery Factors: A Necessity
Authors: Labastie Alain 
Published: February 2015

President's column
To satisfy the increasing energy needs of the world during the next decades, adding substantial new oil reserves will not be an option, but a necessity. There are different ways to achieve that:
Continuation of exploration. Exploration for new resources will continue to play an important role but will become more difficult and will not be sufficient to meet our needs.
Development of unconventional oil, like oil sands and oil shales. Unconventionals are quite promising, but production will increase slowly.
Improvement of the recovery efficiency of our producing fields. This means producing a fraction of the enormous amount of oil that is currently being left underground.
The current ultimate average recovery factor for oil fields, on a worldwide basis, is about 35%. This means that about two-thirds of the oil that has been discovered is left within the reservoir. We have under our feet, in well known locations, enormous prospects for booking new reserves. Increasing the average ultimate recovery factor from 35% to 45% would bring about 1 trillion bbl oil! The questions are how to achieve that goal, and is it realistic?
How? Technology will be the key, in many domains: advanced wells with more contact with the reservoir, more efficient lifting systems, devices such as downhole or seafloor separation, better reservoir monitoring and management, and, very importantly, tertiary recovery or enhanced oil recovery (EOR).
Is it possible? We know the answer, it’s “yes.” Why? Because this has been done in one place already, Norway. In this country, a continuous policy of incentives for developing and, more importantly, deploying new technology has been in place for the last 30 years. And the overall results are quite impressive. Thanks to many new technologies the average ultimate recovery factor has been increased by more than 10% during this period.
I would like to elaborate a little on EOR, as it will certainly play an important role. EOR was promising 30 years ago, but it never developed as well as many people anticipated. However, it is interesting to note that although EOR production is relatively small today, it is still significant—around 3 million B/D. I recently visited the giant Daqing oil field in China. This field is now very mature, with a water cut of more than 90%, but the oil production rate has maintained constant over years thanks to a progressive deployment of polymer flooding, which is now implemented in about one-third of the field. That is an impressive success story and an example for rejuvenation of mature fields. Also, a number of EOR projects have been launched recently. This includes small-scale pilots, but also a lot of large-scale operations.
Whole Core vs. Plugs: Integrating Log and Core Data to Decrease Uncertainty in Petrophysical Interpretation and Oil-In-Place Calculations
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 137679, “Whole Core vs. Plugs: Integrating Log and Core Data To Decrease Uncertainty in Petrophysical Interpretation and STOIP Calculations,” by S. Serag El Din, SPE, ADCO; M.R. Dernaika, SPE, Weatherford Laboratories; I. Al Hosani, ADCO; L. Hannon, Weatherford Laboratories; S.M. Skjeveland, SPE, University of Stavanger; and M.Z. Kalam, ADCO, prepared for the 2010 Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, UAE, 1–4 November. The paper has not been peer reviewed.
Most carbonate reservoirs are characterized by multiple-porosity systems that impart petrophysical heterogeneity to the gross reservoir interval. The specific types and relative percentages of pores present, and their distribution within the rocks, exert strong control on production and stimulation characteristics of carbonate reservoirs. The effects of heterogeneity on core and log measurements are presented. The challenge is to determine the reliability of applying relatively small-scale properties measured by a log or core to the large-scale reservoir property.
Introduction
Most sandstone reservoirs are single-porosity systems (i.e., interparticle pores) of relatively uniform (homogeneous) nature. However, most carbonate reservoirs are characterized by multiple-porosity systems. Reservoir heterogeneity results from physical and chemical reorganization processes over time (e.g., compaction, solution, dolomitization, and cementation). Heterogeneity complicates the reservoir-description task, in which reservoir properties (e.g., permeability, porosity, saturation, and rock types) tend to vary as a function of spatial locations in vertical and areal directions. Vertical heterogeneity has shown large effects on sweep efficiencies of waterfloods and conventional gas injection into mixed- to oil-wet carbonate reservoirs. These effects are a result of large variations in permeability between different strata. Permeability and other rock properties can vary along the areal (lateral) direction of the reservoir, which necessitates establishing an accurate and detailed understanding of geological heterogeneities and their effect on petrophysics and reservoir engineering.
The effect of rock heterogeneity becomes greater when petrophysical properties are measured at scales ranging from a small trim sample in the laboratory to log measurements in the field. Permeability variation of three orders of magnitude has been reported over a distance of a few centimeters in a carbonate-core plug. In heterogeneous reservoirs, the real challenge is predicting reservoir performance through the acquisition of representative measurements. The challenge would be to reconcile the variability seen in high-resolution (e.g., trim or plug samples) and low-resolution (e.g., wireline logs) measurements and to quantify the technical and physical considerations at the various scales.
Collaboration's Critical Role in Reaching Total Depth
Authors: Emerson Brent 
Published: February 2015

Guest editorial
Drillers around the world share a common goal: to get their well to its targeted depth with the proper hole size such that reservoir contact and, ultimately production, are optimized.
However, given the diverse drilling environments that operators work in today—from reactive shales and tar zones to salt domes and depleted zones commingled with high-pressure zones—the challenges are as varied as each well drilled. How do we safely reach total depth with the right hole size to ensure that kicks or losses are minimized and wellbore integrity is assured? And how do we achieve optimal efficiency to avoid the time and money lost by drilling delays?
As exploration and production operators know, collaboration is key to success in reaching total depth—in particular, collaboration between the operator and an integrated service provider who brings complementary services and technologies to well construction. The ultimate benefit of this collaborative approach can be fully realized only if the service provider is involved as early as possible. Indeed, the contributions made in the predrill planning stage can have a positive knock-on effect for subsequent stages—from engineering to execution and, eventually, to operation. Everything the operator and its service partners do ahead of the well’s onset of production can bolster, or undermine, the long-term viability of a well.
So, what can an integrated service provider help deliver? Early collaboration helps deliver on the promise of well integrity—the concept of having no uncontrolled inflows of drilling mud into the formation or outflows of formation fluid into the wellbore—throughout the life cycle of the well. Armed with an in-depth understanding of the operator’s well integrity challenges, the service provider can help the operator determine the best way to run casing to depth, ensure high-integrity cementing, and achieve proper zonal isolation to generate reliable and long-term production from the well.
A close working relationship between operator and integrated service partner also helps ensure drilling reliability, which is tied to having the right products and services available that consistently deliver the well plan with a minimum of nonproductive time (NPT). While much of today’s drilling equipment is highly reliable, with an uptime of 98% or more, the industry must develop even more reliable equipment. This is because of the additive nature of equipment downtime in wells of increasing complexity, which lowers the reliability of the cumulative technology offering and increases NPT. Our industry must continue to develop better equipment designs that push reliability gains rivaling the electronics industry, that is, greater than 99%. And while next generation products may cost more both in up-front research and development investments and price, they will more than pay for themselves by boosting overall system reliability and lowering NPT.