bluuebunny/crossref_metadata_2025 huggingface dataset:
Expandable-Metal Technology Creates a Monobore Well
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 16670, "Using Expandable-Metal Technology To Create a Monobore Well," by Matthew Jabs, SPE, Baker OIl Tools, originally prepared for the 2004 Offshore Technology Conference, Houston, 3-6 May.

The introduction of expandable-metal technology into the oil and gas industry in recent years has allowed a change in traditional well-construction design. The advent of this technology is allowing operators to drill wellbores that do not subscribe to the traditional telescoping reduction in casing sizes as well depth increases. This capability allows deep wells to be drilled without sacrificing well hole size, which has many advantages, ranging from lower wellbore construction costs to greater production potential. The full-length paper outlines a method of creating a monobore well over a finite length of well path.

Introduction

The primary benefit of a monobore well is the ability to reach the desired drilling depth without sacrificing casing size. This capability can allow much deeper or deviated wells to be drilled because of the elimination of the hole-size reduction. Should an unexpected hole problem be encountered while drilling, a monobore-well design provides the ability to set a section of casing across a problem zone and continue wellbore construction without sacrificing hole size. By developing wells from the surface to total depth using a monobore design, it is possible to reduce surface-equipment size. Use of smaller-sized equipment and casing may translate to direct cost savings.
Hydrodynamic Aspects of Gravity- Based Structures in Shallow Water
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 16716, "Hydrodynamic Aspects of Gravity-Based Structures in Shallow Water," by B. Buchner and G.E. Loots, Maritime Research Inst., The Netherlands, and G.Z. Forristall and E.J. van Iperen, Shell Intl. E&P, prepared for the 2004 Offshore Technology Conference, Houston, 3-6 May.

Concrete gravity-based structures (GBSs) are being studied for shallow-water oil and gas developments. Three subjects must be considered: wave amplification with respect to deck elevations, the hydrodynamics of liquefied-natural-gas (LNG) carriers moored to GBSs, and wave run-up and possible green water on the deck of the GBS.

Introduction

A concrete GBS for offshore oil production usually consists of a base caisson supporting several vertical columns, which in turn support a deck containing production facilities. Some of the first were built for deepwater fields in the Norwegian sector of the North Sea. The Troll platform in 303 m water depth remains the tallest object moved over the face of the Earth. Soils in the Norwegian sector were strong enough to support the massive structures, and their mass is sufficient to resist the overturning forces caused by environmental loads. Because the base of a GBS is large, it is easily adapted for oil storage. Production can be stored until a load large enough to fill a tanker is accumulated.

Malampaya is a good example of GBS use in shallow water. The Malampaya gas field is in water approximately 820 m deep, but the production is sent by pipeline from the subsea wells to the GBS in 43 m water depth, where it is processed. The dry gas is sent to power plants in the Philippines, and the condensate is stored in the base of the GBS for eventual shipping by tanker.

Two GBSs are planned for the Sakhalin II project in the Sea of Okhotsk. In this case, another advantage of this type of structure is exploited: they are able to resist forces from seasonal ice cover and ice movement.

Recently, several companies began investigating the possibility of building a GBS as an offshore terminal for importing LNG, as shown in Fig. 1. The structures likely will be rectangular caissons, which also will serve as breakwaters for the LNG tankers. They also will store the LNG and support the regasification equipment.
In-Situ Characterization of Formation-Fluid Samples - Case Studies
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90932, "In-Situ Characterization of Formation-Fluid Samples - Case Studies," by H. Elshahawi, SPE, and M. Hashem, Shell Intl. E&P Inc., and C. Dong, SPE, P. Hegeman, SPE, O.C. Mullins, SPE, G. Fujisawa, SPE, and S. Betancourt, SPE, Schlumberger Oilfield Services, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.

Fluid sampling in the early stages of exploration and development provides key information for field planning and facilities design. In many deepwater and other high-cost wells, formation-tester samples may be the only reliable source of fluid properties for economic screening. Real-time in-situ fluid characterization can ensure sample quality and optimize the sampling process. Techniques for downhole fluid characterization include real-time composition measurement, fluid-type identification, and single-phase assurance.

Introduction

To develop deepwater prospects and other capital-intensive E&P projects, it is essential to understand the precise nature of the hydrocarbon fluids in terms of chemical and physical properties, phase behavior, and commingling tendencies. This understanding is essential to optimize completion and facilities design and reservoir-production strategies. Gas/liquid ratio, saturation pressure, and viscosity are fluid parameters that determine whether and how production is pursued. Phase transitions such as asphaltene onset, wax and organic-scale deposition, gas-hydrate formation, and diamondoid accumulation can reduce production substantially. Consequently, getting the correct answer at the beginning of a project is necessary.
Chain Failure by Bending on Deepwater Mooring Systems
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17238, "Failure of Chains by Bending on Deepwater Mooring Systems," by P. Jean, Single Buoy Moorings Inc.; K. Goessens, Total E&P Angola; and D. L'Hostis, DV Offshore, prepared for the 2005 Offshore Technology Conference, Houston, 2–5 May.

The premature rupture of mooring chains of the Girassol buoy after only a half-year of service was caused by bending fatigue of the first free chain link inside the chain hawse (fairlead). Although the mooring system had been designed according to offshore industry standards, it failed because of this bending-fatigue mode. A study of this bending phenomenon led to a redesign of both the top chain segment size and the hawse connection, which now includes a new chain-connecting arm (CCA). A new method was developed to estimate the fatigue damage in the chain subjected to bending, which was used to design a new CCA for the Girassol buoy.

Introduction

The Girassol loading buoy was installed in September 2001 at the Girassol oil field off-shore Angola in 1350-m water depth. The buoy allows export, by use of two midwater 16-in. export lines, of the stabilized crude oil processed onboard the floating production, storage, and offloading vessel, moored 1 naut mile away.

The buoy is anchored to the seabed by means of three groups of three anchor legs. Before the incident, the anchor legs comprised collinear segments of 81-mm studded chains and 130-mm-diameter polyester ropes. Within each group, the legs are spread 5° apart, and the group centers are spread 120° apart. The chain segments are at the upper and lower ends of the anchor legs.

In May 2002, 235 days after buoy installation, one group of anchor legs (B4, B5, and B6) broke almost simultaneously, followed 1 month later by the rupture of another anchor leg (B1).

The ruptures in Anchor Legs B4, B6, and B1 occurred at exactly the same location—at the fifth link of the upper chain segment connected to the buoy inside a standard-type curved chain hawse—while Leg B5 broke in the upper rope segment. This rope-segment rupture was caused primarily by an earlier accidental cut of the rope through two-thirds of its section. The total rupture of Leg B5 followed the rupture of Legs B4 and B6 as a result of load transfer. However, the fifth link of Leg B5 was found severely cracked, thus confirming the same failure mechanism for all four legs.

Studies identified the root cause as the out-of-plane bending (OPB) stress (fatigue stress), combined with tension variations, occurring mainly in the fifth link inside the chain hawses. As Fig. 1 shows, Link 5 is the first link to oscillate with respect to the Link 4, which is fixed onto the internal curved shape of the chain hawse.
Overview: Drilling and Cementing Technology (February 2007)
Authors: Dupuis Dominique
Published: February 2015

2006 confirmed foreseen changes. The demand for oil was near the offer or production capacity and the rather stable high oil prices induced new drilling programs. The result was a drilling-rig market with use near 100% and new rig construction for the offshore fleet nearing 100 rigs. The wake-up was rather sudden. If current programs use mostly conventional drilling technology while constant technology evolution improves productivity, new prospects soon will require new drilling technology. Papers highlighted here and listed for additional reading describe recent technology advances.

R&D programs in 2005 and 2006 anticipated the need for new technology.In the ultradeep offshore, water depth more than 10,000 ft, conventional riser architecture has reached its limit; the hyperstatic riser is one solution.In deep prospects and extended-reach wells that require multiple intermedi-ate casings, monobore architecture renders these projects feasible.In deep buried reservoirs, the effects of high temperature require careful review of the cement formulation.In some mature or shallow unconsolidated prospects with low fracture gradients, the use of ultralight cements may be required.For production from acidic environments, long-term cement-sheave durability must be studied.

Noticeable efforts have been made to improve more-conventional drilling.Understanding drillstring behavior and taking into account contact forces related to string bending will improve trajectory prediction, and its monitoring will certainly increase the overall rate of penetration.Various methods of cuttings disposal exist, and the understanding of cuttings reinjection is improving.The reliability of cement-bond logs has improved with respect to zone isolation, especially when communication tests are impractical or cost-prohibitive.

Drilling and Cementing Technology additional reading available at the SPE eLibrary: www.spe.org

SPE 99105 "Durability of Oilwell Cement Formulations Aged in H2S-Containing Fluids" by E. Lecolier, SPE, Inst. Français du Pétrole, et al.

SPE 98124 "Ultralightweight Cementing Technology Sets World Record for Liner Cementing With a 5.4-lbm/gal Slurry Density" by D. Kulakofsky, SPE, Halliburton, et al.

SPE 99005 "First Hyperstatic Riser Joint Field Tested for Deep Offshore Drilling" by Y. Poirette, SPE, Inst. Français du Petróle, et al.

SPE 98965 "Advancements in 3D Drillstring Mechanics: From the Bit to the Topdrive" by S. Menand, SPE, École des Mines de Paris, et al.
Fixed-Offshore-Platform Performance in Hurricane Ivan
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18325, "Assessment of Fixed-Offshore-Platform Performance in Hurricane Ivan," by F.J. Puskar, R.E. Spong, and A. Ku, Energo Engineering, and R.B. Gilbert and Y.J. Choi, U. of Texas at Austin, prepared for the 2006 Offshore Technology Conference, Houston, 1–4 May.

Hurricane Ivan provided an opportunity to evaluate the American Petroleum Inst. (API) RP 2A design process for fixed platforms to ensure that it provides for well-designed structures. Specific findings and trends are reported related to global platform performance as well as component performance. A quantitative assessment to determine the adequacy of the API RP 2A design process uses a probability-based process that compares analytically predicted platform damage and survival to that actually observed after Ivan.

Introduction

Ivan was one of several hurricanes in the last 12 years that have damaged or destroyed fixed offshore platforms. Previous hurricanes were Andrew in 1992 and Lili in 2002. Katrina and Rita in 2005 also caused significant platform damage and destruction. These types of events provide an opportunity to determine how fixed platforms in the Gulf of Mexico (GOM) perform in hurricanes on both a qualitative and quantitative basis. The qualitative basis includes a review of the typical types of damage to topsides and jackets, as well as the general trends observed, such as the number and type of platforms with wave-in-deck damage. The quantitative basis involves the comparison of observed damage with what would have been predicted by API RP 2A, which is the basis for design of fixed platforms in the GOM. This provides a quantified assessment of the accuracy of API RP 2A and whether it is adequate for design. The full-length paper describes these assessments for Ivan on the basis of an in-depth study performed for the U.S. Minerals Management Service focusing on fixed platforms.

Path

By late afternoon on 15 September 2004, Ivan was in the east-central GOM, approaching the deepwater oil and gas facilities. During this time, the hurricane was a Category 4 storm on the Saffir-Simpson scale, with maximum sustained wind speeds of more than 135 miles/hr. Ivan tracked north over the deepwater facilities in the Mississippi Canyon blocks and into the Viosca Knoll (VK) and Main Pass (MP) block areas. The majority of the destroyed or damaged fixed platforms were in the VK and MP block areas. Ivan continued its northerly track through the eastern edge of the Mobile block area, making landfall as a major hurricane with maximum winds of 130 miles/hr on the early morning of 16 September just west of Gulf Shores, Alabama.
Building Bridges: My Journey Continues... What SPE Is Doing To Improve Peer Review
Authors: Cobb Bill
Published: February 2015

President's column

Happy New Year, Fellow SPE Members.

Yes, this is February, but as I finalize these comments it's January 1st. I hope 2008 will bring good health, happiness, and prosperity to you and your families.

During the holiday period, I have had discussions with several of our members and the SPE staff regarding SPE's technical-paper peer review. I would like to share with you some of our thoughts and action items for the near future.

Peer review is very important to SPE. While peer-approved papers comprise a small part of our eLibrary collection, peer review plays an important part in SPE's mission as a technical society. It enhances SPE's reputation as a learned society, and benefits both authors and readers.

Regardless of whether his/her paper is accepted for publication, the author benefits from suggestions for improving the work from individuals with special expertise or experience. Having a paper published in an SPE peer-reviewed journal merits a lot of prestige in our industry—only about 22% of submitted papers are accepted for publication.

Readers benefit because the review process selects among the enormous number of papers written each year and gives them a literature base of papers that subject-matter experts have found to be exceptional in some manner.

Today, we have some significant issues with the performance of this important part of SPE. In recent years, the average time that it takes for a paper to complete peer review has stretched to 8 months or longer. Several factors have contributed to this unsatisfactory state.

First, the number of papers submitted for peer review has grown by more than 25% since 2004, tracking the increase in SPE conferences offered each year—32 were held last year. In 2007, nearly 2,200 papers were submitted for review.

Second, too often, authors submit papers for peer review automatically when they submit papers for SPE meetings, without fully considering whether their papers are right for peer review. As a result, reviewers (who are all volunteers) spend considerable time sifting through papers that fall outside the coverage areas of our journals or that don't contribute something new to the industry's literature.

Third, at this busy time in our industry, our volunteers have less time than ever to devote to peer review. (Many years ago, I served as a reviewer, and I know how much time and effort our volunteers put into selecting and enhancing the best papers that ultimately become a part of our industry's archival literature. Currently, more than 800 volunteers review submissions for the five SPE journals.)
Overview: Offshore Facilities: Construction and Design (February 2008)
Authors: Valenchon Claude
Published: February 2015

Overview

Deepwater and the Arctic, which, today, represent more than half of the world's undiscovered oil and gas resources, often are associated when it comes to the current challenges in exploration and production. But even if deepwater and the Arctic share a few common problems, those associated with arctic conditions present many unique specificities and a much wider range of technological issues.

Among the reasons, arctic areas are interpreted as those with prevailing cold-climate conditions and include, in addition to the whole area north of the Arctic Circle, the subarctic regions down to northeast Canada, Sakhalin, and the Caspian Sea (just to name the more active ones). Also, arctic means not only offshore deep and shallow areas—sometimes including areas with many challenges for very shallow developments (e.g., Kashagan) and for all shore approaches—but also onshore, with long pipelines, large plants, and all the associated infrastructure (e.g., roads and buildings).

Common features include high-technological content, heavy logistics, high sophistication of required equipment, and, certainly, high cost of development and production. In addition, subsea processing (separation, boosting, and compression) that enables solving deepwater flow-assurance issues and increasing recovery rates should bring the same advantages to Arctic production and ultimately, in some cases, could allow subsea-to-beach configurations, thus greatly reducing interaction with ice.

Remoteness, personnel safety, and environmental footprint (already very important in deepwater) take an even more important place in the highly sensitive Arctic zones. Obvious unique specificities of the Arctic are those related to the low temperatures (i.e., ice, icing, and interaction of ice, ridges, and icebergs with structures and pipelines), leading to ice strengthening and/or disconnect-ability of structures, deep burial of pipelines, ice management for offshore developments, and (for both onshore and offshore) all the difficulties linked to the presence of permafrost. All of these concerns have common major uncertainties linked to the current situation, as well as to their evolution in the future.

Even with all the unique challenges of the Arctic, these offshore developments will certainly benefit from the great experience that operators and contractors have already gained in the deepwater scene. However, developments in the Arctic will have to cope with even-more-difficult environmental challenges and larger uncertainties.

Offshore Facilities: Construction and Design additional reading available at the OTC Library: www.otcnet.org

OTC 18768 "Polyester Mooring Lines on Platforms and MODUs in Deep Water" by John F. Flory, Tension Technology International, et al.

OTC 18903 "Development of Revised Gulf of Mexico Metocean Hurricane Conditions for Reference by API Recommended Practices" by E.P. Berek, ExxonMobil, et al.
Alternative Approach to Wellhead Flowline-Pressure Protection
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18613, "An Alternative Approach to Wellhead Flowline-Pressure Protection," by Angela E. Summers and Bryan Zachary, SIS-Tech Solutions, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.

For many years, pipe-specification standards have required that piping downstream of the wellhead be adequate to sustain a full wellhead shut-in. This inherently safe design practice ensured that the flowline pipe was specified with a maximum allowable working pressure (MAWP) equal to or greater than the maximum pressure expected to be produced by the well. This practice has proved to provide adequate protection in thousands of wellhead installations throughout the world. Inherently safe practice has been challenged when retrofitting electrical submersible pumps (ESPs). In such cases, the maximum discharge pressure under block-in conditions is greater than the MAWP of existing flowline pipe. A safe alternative to replacing the pipe is the use of a high-integrity protective system (HIPS) designed and managed as a safety-instrumented system (SIS) with a Safety Integrity Level (SIL) of 3.

Introduction

When the price of crude oil rose above USD 50/bbl, oil-producing companies pursued efforts to increase or renew production in existing oil wells. One solution, especially in ultradeep (4,000-ft water depth) subsea applications, is to boost well pressure. A major challenge in developing these deepwater solutions is the MAWP limitation of the downstream flowline pipe. An HIPS can close block valves placed in front of the low-specification pipe, protecting the lower-rated downstream piping.

The introduction of high-pressure ESPs in many offshore fields has increased the maximum shut-in pressure beyond the MAWP of the downstream flowline pipe. The design of the instrumented-system response is complicated by the need to respond quickly. Upon shut-in, the ESP can produce pressure sufficient to challenge the mechanical integrity of the flowline very quickly. The pressure rise is related to the compressibility of the material, but the pressure rise generally is rapid, resulting in a very-short process safety time (e.g., in liquid service, the time may be less than 5 seconds).

In typical onshore process-industry applications, an overpressure hazard such as that encountered by the ESP-well flowline would be addressed by a pressure-relief device (PRD) and a disposal system, such as a flare or scrubber to safely process the material relieved during an overpressure event. When PRDs are installed in conventional flowline designs, they typically are sized to mitigate only thermal expansion of the material when the flowline is blocked-in. For HIPS flowline designs, the PRD sizing also should consider possible block-valve leakage.

A safe and reliable alternative to replacing the existing wellhead flowlines relies on the use of an HIPS to detect unacceptable operating pressure and initiate closure of block valves. An HIPS is a special class of SIS.
Integrating Pressure-Transient-Test Data With Seismic-Attribute Analysis To Characterize an Offshore Fluvial Reservoir
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 110272, "Integrating Pressure- Transient-Test Data With Seismic-Attribute Analysis To Characterize an Offshore Fluvial Reservoir," by Akshay Sahni, SPE, Ken Kelsch, SPE, Hathaiporn Samorn, and Chalatpon Boonmeelapprasert, SPE, Chevron, prepared for the 2007 SPE Asia Pacific Oil & Gas Conference and Exhibition, Jakarta, 30 October-1 November.

Interpreting pressure-transient tests in complex faulted and stratigraphic environments can be difficult. In fluvial-depositional environments, in which sand continuity is a significant uncertainty, pressure-transient-test interpretation can generate several nonunique solutions, all of which may match test data. Use of seismic-attribute analysis to constrain pressure-transient-test interpretation leads to a better understanding of reservoir heterogeneities and boundaries.

Introduction

The integration of geology with well-test interpretation has been discussed in industry literature, as noted in the full-length paper. It has been stated that integration of geoscience and well testing reduces uncertainty in reservoir description, especially in fluvial reservoirs. This paper builds on work done in the past, use of a data set comprising seismic-attribute analysis and a long-duration pressure-buildup test, along with core, well-log, and production data.

Reservoir

Reservoir sands in the area of interest primarily are Tertiary sequences, predominantly of nonmarine origin, and deposited in fluvial to lacustrine environments. The net-to-gross ratio over the entire reservoir interval (more than 3,000 ft) typically is between 0.15 and 0.20. At this low ratio, the vertical connectivity of sands generally is very poor. Areas with a greater concentration of high-amplitude seismic events likely are associated with a high probability of better net-to-gross-ratio development (more sand prone), but not directly related to better pay (hydrocarbon-bearing sands). It can be difficult to distinguish better sand quality from pay sand. Seismic modeling of sands indicates that gas sands yield higher seismic-reflection amplitudes, but only 5 to 10% gas saturation is necessary to change the acoustic impedance significantly.

Reservoir-compartment size of the hydrocarbon-bearing sands identified in wells can be estimated by use of the seismic inlines, crosslines, and time slices. For the reservoir area under consideration, time-slice mapping indicates that the average reservoir compartment size is relatively small and is supported in most cases by well-test interpretation, production, and pressure data. There is a high level of faulting, subdividing the channel systems, and thus reducing the connected-sand area to approximately 30 to 50 acres. Larger connected areas (250 acres or more) are found on structural shoulders or outer fault blocks of a fault complex. The sand area/volume connected to a well remains one of the largest uncertainties in estimating reserves.
Comments: Recessions and Oil
Authors: Donnelly John
Published: February 2015

Editor's column

Steep or sudden oil price spikes and recessions often have gone hand in hand. Some economists contend that a causal relationship exists between oil price shocks and global recessions, noting that nine of 10 post-World War II recessions were preceded by oil price run-ups, although the timing of the two has varied.

The global recession of 1958 curtailed oil demand and job prospects and contributed to a dramatic decline in student interest in petroleum engineering schools. However, SPE membership continued to grow during this time and it was then that the Society launched some of its most important initiatives, including the Distinguished Lecturer Series and its first technical journal. The student decline would continue to 1963 as the industry faced some of the same challenges it does today—competition from seemingly more glamorous professions, the cyclical nature of supply and demand, a weak public image, and reports that the world might no longer rely on oil in the near future. The resulting industry staffing shortage that occurred in the mid to late 1960s gave many young professionals opportunities and prosperous careers they otherwise might not have had.

In 1973, the so-called Arab oil embargo that occurred during the Arab-Israeli War led to a sudden price spike that plunged industrial nations into recession and caused steep inflation. The 1974–75 recession would cause petroleum demand to drop by 4.5%. Then the Iranian revolution and Iran-Iraq War caused another price spike in 1979. The inflation of the 1970s led to tighter monetary policies, which contributed to the deep recession of the early 1980s and significantly lower oil demand. Oil's share of global energy consumption fell to under 50% by 1985. By 1986, oil prices had plummeted to USD 9/bbl, leading to major layoffs and industry consolidation.

Subsequent recessions have had less impact on worldwide petroleum demand. The recession of 1992 saw consumption fall by about 3.5% and the recession of 2001–02 had little effect on demand. Asia's recession in the late 1990s and OPEC's slowness in reacting to it is largely blamed for the steep collapse in prices to USD 10/bbl in 1998. That price collapse helped touch off a wave of megamergers that ended the existence of such well-known companies as Arco, Amoco, and Mobil.

Economic downturns and price drops have caused significant structural changes in the oil and gas industry in the past. The shift in research and development from operators to the service sector, the loss of personnel that has led to today's shortage of technical talent, the swings in petroleum engineering enrollment, and the dramatic consolidation that occurred in the 1990s all were products to some degree of price volatility and supply/demand corrections. Some analysts caution that sharp cutbacks in capital spending, R&D, and personnel this time may only complicate things for the industry in the future. How the industry reacts to the current economic downturn will no doubt help determine its future as well.
Comments: Positive Forecasts
Authors: Donnelly John
Published: February 2015

Editor's column

Higher oil prices, continued enthusiasm over shale, and the influx of capital are combining to paint a bright picture for the oil and gas industry this year. Both operators and the service sector appear optimistic for growth opportunities—despite some uncertainty surrounding offshore drilling—as the industry quickly rebounds from recession.

The Original E&P Spending Survey by Barclays Capital forecasts that global E&P spending will increase 11% this year, from USD 442 billion in 2010 to USD 490 billion in 2011. The survey is based on information from 402 international oil companies, national oil companies, and independents. The outlook for spending in Latin America, the Middle East and North Africa, and Southeast Asia appears particularly bright. International oil companies will post the largest increases in spending, says the study, a reversal from previous years when national oil companies led spending increases. BP, Chevron, ConocoPhillips, ExxonMobil, Shell, and Total are expected to boost expenditures by 18% in the aggregate.

Factors driving the increased spending by operators include engineering and construction spending for several large liquefied natural gas projects, increased spending in Iraq, and an increase in deepwater activity, the report said.

A recent Wood Mackenzie analysis reported that global upstream capital spending for 2010 would hit USD 380 billion and that many regions and sectors of the upstream industry are regaining confidence. Spending last year was about USD 19 billion higher than in 2009 but 10% lower than 2008. The Wood Mackenzie report said it expects spending to continue to increase in the short term and recover to 2008 levels by 2012 or 2013. The industry’s recovery is largely being led by spending on developing unconventional resources such as shale, the report said. Although most of the spending to date has been in developing US shale plays, operators are increasingly eyeing opportunities in Eastern Europe and elsewhere.

Also boosting recovery is the influx of capital. More than half of chief financial officers (CFOs) in the oil and gas industry report that their companies’ ability to access capital and credit is either the same or better than it was a year ago, according to a study by BDO USA, an accounting and consulting organization. That renewed access to capital is allowing companies to aggressively pursue the acquisition of new properties, technologies, and other companies. In addition, 95% of the CFOs surveyed expect to maintain or increase the number of personnel employed by their companies this year.

The oilfield services sector also appears healthy. The annual IHS Herold Review of the Oil Field Services Sector reported that key oil company financial performance for service companies by late last year had greatly improved, including for Baker Hughes, Halliburton, and Schlumberger as well as for offshore drilling contractors Transocean, Diamond Offshore, and Oceaneering International, among others.
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.”