bluuebunny/crossref_metadata_2025 huggingface dataset:
Comments: The Future Continues
Authors: Donnelly John
Published: February 2015

Editor's column

A year ago, BP Chief Executive Officer Tony Hayward—amid an environment of a world steeped in recession and oil prices that had crashed more than USD 100/bbl—said that the future had not been canceled, only perhaps postponed a year or so. That prognosis appears to be coming true. Oil prices have rebounded to approximately USD 70/bbl, which appears to please producers as well as operators, and demand seems to be on the rise again.

Recent economic data indicate the recession is easing and oil consumption returning, particularly in China and parts of Asia. Global demand is rising for the first time in a year, and Chinese demand grew by 6% in August, with industrial output surging. Those figures have taken the pressure off of OPEC to tighten supply, and it voted during its meeting last month to keep member production quotas unchanged. Saudi Oil Minister Ali Naimi said during the meeting that, at least for now, the price of oil would be driven by economic growth.

In a report released last month, Cambridge Energy Research Associates (CERA) predicted that world oil demand would grow next year for the first time since 2007, and then return to prerecession levels by 2012. The recovery will be quicker than previous industry recoveries because of the strength of emerging markets and lack of adequate alternatives for hydrocarbons. IHS CERA expects oil demand growth to increase 900,000 BOPD in 2010 and return to its 2007 high of 86.5 million BOPD by 2012. That would be a much quicker recovery than from the major collapse that occurred in the 1980s.

The futures market currently values oil closer to USD 90/bbl, although there is much industry convergence around a price closer to USD 70/bbl, Paul Horsnell, managing director and head of commodities research at Barclays Commercial, told an audience at the Offshore Europe conference last month. Not only does Saudi Arabia currently favor a USD 75/bbl oil price, but the costs of incremental production, the price that brings about alternative energy investment such as Canadian oil sands, and the break-even price on new investment that generates a 15% rate of return, are all approximately USD 65–75/bbl, he said.

The past year may have been a time for the industry to catch its collective breath. This recent rise in demand is good news but a reminder of the daunting predictions that government agencies, analysts, and operators have made about the immediate to long-term future—sharply rising demand, more difficult to find oil, and shortages of technical talent. Recently announced discoveries—Occidental's California find, BP's Tiber in the Gulf of Mexico, and several big discoveries in Brazil—will only help, and are proof that E&P investment in times of both low and high oil prices pays off.
The Myth of the Oil Crisis
Authors: Mills Robin
Published: February 2015

Guest editorial

"Our supplies of...oil and natural gas are being rapidly depleted, and many of the great fields are already exhausted." Not a warning from last year, when oil prices set a record of USD 147/bbl, but the words of pioneering conservationist Gifford Pinchot in 1910.

Fears of "peak oil" are nothing new. The economist William Jevons forecast in 1865 that falling coal resources threatened the British Empire. Predictions of imminent decline came from petroleum geologists in 1885, 1919, and 1956; from US President Jimmy Carter in 1977; and from the US government in 1980. A prominent "peak oiler," Colin Campbell, claimed in 1989 that oil output had peaked; another, Kenneth Deffeyes, put the peak date, rather precisely, at 16 December 2005. The high prices of 2008 seemed to give credibility to the idea that we had reached the physical limits of production. But now that prices have fallen, peak oil advocates raise a new alarm—that decline will be hastened by a lack of investment.

The opening years of the 21st century have been marked by milestones in the world of oil: the war in Iraq, the Shell reserves downgrade, hurricane Katrina, and the breaking of the once unthinkable USD 100/bbl barrier. Many have seized on these events as evidence that we are crossing the threshold of peak oil. Behind us, a century-and-a-half of abundant, cheap oil that fuelled industrial civilization and brought unprecedented prosperity to a fortunate global minority. Ahead of us, permanent declines in oil production, scarce and unaffordable energy, wars over dwindling resources, disastrous climate change, perhaps the collapse of modern society. But these ideas are based on misconceptions, flawed reasoning, and excessive pessimism. The world has abundant oil and gas for decades to come, geopolitical conflicts can be avoided by adroit policies, and we can learn to use hydrocarbons without unacceptable environmental damage.

Cheap Oil and Underinvestment

Recent high prices certainly seem to give some credibility to the idea that we are approaching some fundamental limit of oil resources. But we should remember how we arrived at this situation, because the culprit is not constraints on oil in the ground: it is the long 1986–98 period of cheap oil and underinvestment. Low prices decimated the oil industry, while the rise of energy-hungry new powers in Asia, combined with robust demand in the developed world and geopolitical upsets in major producers, stealthily ate up spare production capacity. As oil prices rose, investment increased, but much was consumed by cost inflation, while the most promising areas were mostly off-limits for political reasons. Supply growth was therefore disappointing. The inevitable result, perhaps amplified by speculation and market nervousness, was a sharp rise in the oil price.
Well-Intervention System Focuses on Better Measurement
Authors: McNicol Jim , Joppe Bart
Published: February 2015

Technology Update

Until recently, most wells were of a relatively simple geometry, with the most complex having an initial vertical section followed by a straight tangent section that ended with a liner dropping into a vertical reservoir section. Workovers and wellbore-intervention operations in these well profiles were also comparatively simple, where the biggest challenge to evaluating the operation of service tools was overcoming sliding friction in the tangent section. Well profiles now are more complex and three-dimensional. In creating these complex well profiles, the drilling industry has developed some sophisticated and reliable downhole technologies to operate in extremely hostile physical environments.

The next phases of a well's life, however, present significant challenges in workover, cased-hole sidetracking, or any wellbore-intervention operation that has to manipulate service tools, whipstock systems, or fishing tools—often at great depth—in these same complex well profiles. Now the sophisticated drilling systems are missing, and the tool operators revert to relying on surface measurements of hookload, revolutions per minute (rpm), torque, etc. While these surface readings were reliable indicators for verifying a service tool's manipulation cycle position or condition decades ago, they are now often positively misleading. In these new well profiles, it can be difficult to ascertain, for instance, if a mill is rotating off-bottom, operating with optimum weight on mill (WOM), or crushing the cutters with excessive set-down weight. The more delicate the operation—retrieving a lightweight latch or fish for instance—the more difficult and risky the operation becomes.

With many of these intervention operations, the situation is further complicated by having to wait for a trip out of the hole to view the tool before the status of the downhole operation can be verified. Problems with performing intervention operations in this manner include technical risk (cost of failure), nonproductive time, and the cost of tripping in and out the hole to ascertain tool condition and job status.

New Intervention System

To try to counter these problems, a "smart" system has been developed for wellbore intervention. The new system aims to take accurate measurement of all static and dynamic downhole physical forces on intervention tools and transmit them to surface for real-time viewing on the rig floor. The system is integrated into current rig-data systems, such as Wellsite Information Transfer Specification, where the information can be forwarded on to offsite locations for evaluation. Decisions can also be made in real time, rather than having to wait for status-verification trips in and out the hole.
"Bright Star" Vietnam Moving into Unchartered Territory
Authors: Redden Jim
Published: February 2015

Though it may not contain the known reserve base or production rates of neighboring Indonesia or Malaysia, Vietnam nonetheless has emerged as a "bright star" in Southeast Asia. So says Bob Fryklund, IHS vice president of global E&P critical information analysis, who adds that both proven reserves and daily production are expected to increase appreciably as the nation's eclectic group of operators move into more exotic plays.

"For years in Vietnam, everybody just worked a couple of basins. Now, with the country wide open, companies are working all these other unexplored basins. Traditionally, they tended to focus on just the basement play, which was all fractured, but some of it was carbonates, some of it was granitic-type rock, and some of it was volcanic rock. Now, clastic plays are starting to pan out and some of those will move out into the deeper water," he said.

To date, Vietnam has proven oil reserves of approximately 600 million bbl, which Fryklund predicts will reach 1 billion bbl with the fields that came on line in late 2008 and those scheduled to begin production this year and early next year. State operator PetroVietnam, however, says the results of earlier studies suggest that total offshore and onshore reserves could be as high as 6.5 to 8.5 billion bbl of oil and 75 to 100 Tcf of natural gas. Figures from the US Department of Energy's Energy Information Administration show that the nation's production rate, which is entirely from offshore, is 283,000 BOPD, compared to 943,000 and 601,000 BOPD for Indonesia and Malaysia, respectively.

Between existing fields, those expected to come on line over the next 2 years, and prospects for frontier plays, research analyst Business Monitor International predicts that Vietnam oil production will increase by 6.5% between 2008 and 2018, peaking at 400,000 BOPD next year. Gas production, it predicts, will rise from the estimated 10 billion m3 produced in 2008 to 27 billion m3 in 2018.

According to IHS, last year a total of 31 exploratory wells were spudded, of which 16 were classified as wildcats. The 2008 drilling campaign technically resulted in six discoveries, but the actual count is eight when the two wells spudded the previous year are taken into account.

"Vietnam certainly is not a giant in Southeast Asia like Indonesia and Malaysia, but its [reserves] are respectable and will be very important as the country continues to grow," Fryklund said.
Common Sense Economics for E&P Projects
Authors: Schulz Rodney
Published: February 2015

Management

This article has two parts, both of which enhance established econometric paradigms and traditions commonly held by petroleum engineers. But instead of moving toward mathematical complexity, both parts move toward mathematical simplicity. The methods will add pieces to traditional econometric analysis, but the pieces are simple and easy to apply while adding significant value to the organization.

The Common Protocol

Traditionally, economic calculations utilized by petroleum engineers to evaluate and rank projects include internal rate of return (IRR) and net present value (NPV), with profit-ability index (PI) and payback possibly being considered as well. However, if one were to ask a petroleum engineer what metrics get discussed on a daily, monthly, or annual basis, the answer would likely be metrics such as achieving daily production targets and/or operating cost targets. Hence, we often have a significant disconnect between the metrics used to evaluate, qualify, and rank projects and the metrics that receive the most attention.

Additionally, if IRR, NPV, PI, and payback are discussed after a project's approval, it is likely to be in a post-audit a year or two out that receives little attention as long as minimal hurdles were reached. Because metrics such as daily production, operating costs, and staying within capital targets are the most discussed metrics, does it not make sense to evaluate projects on factors akin to the metrics most discussed?

A Common Sense Metric Set

One way to align project analysis and prioritization with daily, monthly, and annual objectives is to consider adding the following metrics to the traditional set of metrics:Initial incremental barrels of oil per day (BOPD) per dollar investedYear 1 average incremental BOPD per dollar investedReserves added per dollar investedOther similar metrics that agree with management objectives

Although the above metrics more directly align with the most commonly discussed objectives, one may argue that such metrics focus on the short term at the expense of the long term. However, taking an analogy from baseball yields another way to look at adding the above metrics.

Focusing on the above "common sense" metric set is like trying to win a baseball game by simply "moving the runners around the bases" instead of "swinging for the fence." This is particularly true when "swinging for the fence" requires one to make multiyear assumptions on things such as production, prices, operating costs, and tax-rate/government-intervention issues. In contrast, the common sense metric set is like moving the business forward one measurable step at a time.
Santos Basin Presalt-Reservoirs Development
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19953, "Santos Basin's Pre-Salt Reservoirs Development - The Way Ahead," by J.M.F. Filho, SPE, A.C.C. Pinto, SPE, and A.S. de Almeida, SPE, Petrobras, originally prepared for the 2009 Offshore Technology Conference, Houston, 4–7 May. The paper has not been peer reviewed.

The full-length paper describes the current studies for the future development of the presalt reservoirs in the Santos basin presalt cluster in deepwater offshore Brazil. Development of the area is divided into three phases. The first phase is a dynamic information-gathering phase comprising extended well tests and production pilots. The second phase, extending to 2017, will comprise conventional subsea completion systems. The third phase will consider nonconventional solutions.

Introduction

The area known as the presalt cluster, in the Santos basin, is in ultradeep water between 1900 and 2400 m, approximately 290 km offshore the Rio de Janeiro coast in southeast Brazil. Fig. 1 shows the main blocks of the presalt cluster, currently in the appraisal-plan phase.

At the beginning of the current century, the "cluster blocks" in the Santos basin were considered one of the most important exploration frontiers of the Brazilian continental shelf, given the size of the structures and the perfect seal created by the salt layer. In 2002, as the operator of different consortia, Petrobras obtained, through a bid process, the concession to explore several blocks in the Santos basin area. The first location, known as Parati (RJS-617), was approved in March 2004. At that time, just two wells had been drilled in the proximal portion of the basin, having crossed thick intervals of the presalt section. The existence of source rocks with characteristics similar to those found in the Campos basin was inferred through geochemical correlations, but there was significant uncertainty regarding the maturation, migration, and volumes that could have been generated and trapped. Despite these uncertainties, the most important risks associated with the locations were related to the existence and quality of the reservoirs. The Parati location was intended to test the stratigraphic traps in multiple objectives in the post-salt section and, additionally, to test a domic structure in the presalt. The sandstone reservoirs above the salt contained water, and the decision was made to go ahead with the well. After drilling 500 m of basalt, with several operational problems, the well drilling stopped at 7600 m true vertical depth subsea (TVDSS). Gas condensate was found in reservoirs of the presalt, confirming the presence of a petroleum system in the area, stimulating the drilling of RJS-628 in the presalt, which resulted in the Tupi discovery.
Effect of Salinity on Wettability Alteration of Porous Media From Liquid-Wetting to Intermediate Gas-Wetting
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 121724, "Effect of Salinity on Wettability Alteration of Porous Media From Liquid-Wetting to Intermediate Gas- Wetting," by Stanley Wu, SPE, and Abbas Firoozabadi, SPE, Reservoir Engineering Research Institute, prepared for the 2009 SPE International Symposium on Oilfield Chemistry, The Woodlands, Texas, 20–22 April. The paper has not been peer reviewed.

The synergetic effect of salinity and fluorochemicals on wettability alteration from water-wetting to intermediate gas-wetting was studied. NaCl salinity increased water-wetting when a core was saturated with brine. NaCl also reduced absolute gas permeability. CaCl2 salinity had a minor effect on permeability. NaCl, KCl, and CaCl2 brines have an adverse effect on wettability alteration.

Introduction

A reduction in effective gas permeability, observed in tight formations and in low-permeability gas reservoirs, often is attributed to water blocking and condensate accumulation. Water blocking is induced by the injection of water during hydraulic fracturing. Condensate accumulates at the wellbore as the pressure drops below the dewpoint pressure. A major factor of liquid retention in a rock is the liquid's low mobility because of strong liquid-wetting. By altering the wettability of the rock from liquid-wetting to intermediate gas-wetting, an increase in liquid mobility can be achieved resulting in a higher rate of gas production.

One concern about the salinity in chemical treatment is that the dissociated ions may destroy the stability of chemical polymers, resulting in colloidal coagulation leading to permeability reduction. The alcohols, which often are used as a solvent for chemical solutions to reduce gas-hydrate formation in drilling and production operations, have a significant and adverse effect on the solubility of salts, increasing the risk of salt deposition. An understanding of the effect of salinity and initial liquid saturation on chemical treatment is necessary for effective design and implementation of wettability-alteration strategies in complex systems. This study reported the gas absolute-permeability and gas/water effective-permeability data before and after treatment with fluorinated polymeric surfactants in isopropanol (IPA) solutions.

Experiments

Wettability alteration was carried out by injecting a chemical solution into Berea and reservoir-sandstone cores and aging them at high temperature and pressure. Treatment conditions were analyzed by varying the fluids used in initial saturation and pretreatment process before chemical injection. The effectiveness of chemical treatment was evaluated by measuring gas/liquid/rock three-phase contact angle, liquid saturation in imbibition tests, gas mobility in single-phase gas flow, and liquid mobility in two-phase gas/liquid flow.
CT Fracturing Method With Downhole Mixing Designed To Optimize Shale Completions
Authors: McNeil Fraser
Published: February 2015

Technology Update

The challenge in recovering hydrocarbons from shale is the low permeability, making cost-effective fracture stimulation treatments essential to economic production. Technology advances and improved operational efficiency have made shale production around the globe far more viable.  However, while the wells being completed are proving reasonably economic, are they achieving their full potential?

The most common method of multistage hydraulic fracturing in horizontal completions in the United States is the plug-and-perforate technique. This stems from the successful work performed in the Barnett Shale, starting in the late 1990s, where production results were deemed economic and the completion technique advanced toward a factory approach to improve operational efficiency. This technique involves running in hole with conventional guns to perforate multiple clusters in the first treatment interval, pulling out of hole, pumping a high-rate stimulation treatment, pumping a plug down to isolate the interval, then repeating until all intervals are stimulated. The reality of the plug-and-perforate process is that the efficiencies are achieved at the cost of stimulation effectiveness (reservoir access) and accompanied by a high risk of excessive downtime. Some of these disadvantages are:

Uncertainty of the number of fractures initiated within the clusters of perforations.

Uncertainty of proppant distribution along perforation clusters and across multiple fractures within the clusters, leading to potentially poor long-term production performance.

Underdesigned proppant schedules, intended to avoid screenout but that may not achieve adequate fracture conductivity.

Overflushing of the near-wellbore region, as a result of using pumpdown plugs. 

The need to displace the entire casing volume before changes on surface will affect the treatment at the perforations.

Significant cost and time required to recover from unplanned events, such as screenout or stuck plugs.

Increased environmental footprint, personnel, and hydraulic horsepower required on location.

Relatively long completion time to bring the well on production

Added safety concern and potential downtime, both of which are inherent in running guns and pumping plugs.

Near-wellbore damage that can result from perforating conventionally (with explosive shaped charges).

To address deficiencies associated with the plug-and-perforate method, a fracturing technique deployed by means of coiled tubing (CT) has been developed by Halliburton that maximizes stimulated contact area (reservoir access) and reduces the risk of excessive downtime, thus improving operational efficiency.
Nanotechnology for Sale: The Once-Theoretical Becomes Practical
Authors: Rassenfoss Stephen
Published: February 2015

The magic of nanotechnology is on display in the form of a dull silver ball created by Baker Hughes.

What looks like solid metal is a composite that is light enough to flow through a well, strong enough to stand up to the impact and pressure associated with opening a sleeve on a multistage fracturing job, and then disappear when it is done.

The company is making 1,500 of the balls each week and based on customer calls, it could sell a lot more, said James King, director of applications engineering for sales and operations support at Baker Oil Tools, US Land. The company plans to increase sales, and add new products, but the supply of the material used to make the balls is limited.

Producers see value in the balls because that expense is considerably less than the value of the production lost if a ball gets stuck during fracturing, blocking the flow from downhole. What looks like aluminum is a nanomaterial the company calls In-Tallic, which combines magnesium, aluminum, and other alloys. It is one of a class of materials called nano-structured metal composites that offer both strength and the ability to “dissolve” away under certain conditions.

The balls are far from the first product engineered to take advantage of the growing understanding of how to take the unique properties observed at nanoscale—generally 100 nanometers (nm) or less—and build those characteristics into products.

Tougher coatings using nanomaterials have been around for a while. In-Tallic balls stand out as an example of how nanotechnology can do things that otherwise would not be possible. The balls’ relatively short 18-month development period also shows what has been learned about engineering nanotechnology into products. “We are looking for ways to break that performance envelope,” said Gaurav Agrawal, director of enterprise research at Baker Hughes. 

 But it is not indicative of the time, effort, and barriers to acceptance more often faced by those creating products with nanotechnology for exploration and production (E&P).

“New generation materials can sell consumer products, but you cannot sell oilfield tools by saying it is nano,” said Jeff Bahr, chief executive officer (CEO) of NanoComposites, a company that uses carbon nanomaterials to develop polymers for uses such as high performance seals.

Oilfield buyers are not averse to nanotechnology, but the focus is on solving difficult problems, not on whether this hard-to-define technology was used. “Customers eyes glaze over when you start talking about how you used nanotechnology,” said Dore Rosenblum, CEO of Sub-One Technology, which makes pipe coatings.

One indication of the interest in applying nanotechnology is the list of oil companies doing research and development work. They include ConocoPhillips, Saudi Aramco, and Shell.
Results of Dual Career Couple Survey
Authors: Sprunt Eve , Howes Susan
Published: February 2015

Talent & Technology

One of the growing issues facing companies is managing employees who are part of a dual career couple. Traditionally, corporate policies were based on the assumption that even if one spouse worked, that person’s income would make up a relatively small fraction of the total household income. The spouse was assumed to be available to handle numerous house-hold responsibilities so the employee could focus on work. Much of the workforce is now juggling more complex personal logistics because both spouses are employed outside the home.

One of the objectives of the SPE Talent Council is conducting surveys and statistical analysis to highlight potential capability/expertise gaps and to identify possible solutions. To obtain information on the prevalence of dual career couples and the challenges facing them, SPE emailed a survey in May to 46,777 professional members, of which 5,570 responded. The results showed that dual career couples make up about half the workforce. Dual career couples will probably form a larger proportion in the near future, because those in such relationships are younger than those who are not. This article is a summary of the survey results, which are available in SPE-151971-MS at www.onepetro.org.

The largest number of survey responses, with similar percentages, came from the United States, Canada, and the United Kingdom, where SPE has the largest number of members. Members in 93 countries responded.

Of the total number of responses, 47% reported they were part of a dual career couple, 11% said they were previously part of a dual career couple, and 42% considered themselves to be single career. We also examined the results for two other groups. The first group was those in which the respondent said he or she is contributing between 33% and 67% of the household income, so that each partner is contributing at least a third. The second group was made up of those who reported contributing between 40% and 60% of household income. Of those who identified themselves as “dual career,” 47% said the lower-paid partner provides at least a third of the household income and 37% said that each partner provides nearly equal portions of the household income. Of all the survey responses, 22% came from couples where the minimum income contribution is a third and 17% came from those where the contribution is nearly equal. The days when the spouse’s salary could be viewed as providing an insignificant fraction of the household income that could easily be covered by a relocation bonus are gone.
Technology Focus: Field Development Projects (October 2011)
Authors: Rebelo Mauricio P.
Published: February 2015

Technology Focus

From the time that an oil field is discovered by an exploratory well until it begins production of its first oil, the development-project team faces many technical decisions. Making correct choices is most critical to the project and is very challenging to the team, which must deal with several uncertainties.

Information acquisition is an important step in helping the team to understand the field and to make correct decisions. At this phase, a series of activities, including drilling appraisal wells, geology and seismic studies, reservoir simulations, and many others, are key factors that are necessary to achieve the most-accurate information from the reservoir. It is through such important information gathering and correct decision making that oil companies can define the appropriate development method for the oil field.

Optimizing costs and maximizing oil recovery are factors that will make field production more economically viable. A wrong decision may translate into a disastrous choice for the project. Oil-price uncertainty is another important part in this process that the companies must deal with. Well design and architecture, completion design, well stimulation, production facilities, and many other factors are important items to be defined to make a development project successful.

The papers selected for this feature are good examples of focusing on some of the factors just mentioned. It is interesting to read about different types of field-development projects in different areas. Specific project solutions and several studies and simulations used by the companies are shown in the articles and in the listed additional reading.

Field Development Projects additional reading available at OnePetro: www.onepetro.org

SPE 137220 • “GOM Deepwater-Field-Development Challenges at Green Canyon 468 Pony” by Michael H. Weatherl, Hess Corporation. (See JPT, April 2011, page 70.)

OTC 21583 • “Field-Development Planning and Floating-Platform Concept Selection for Global Deepwater Developments” by Richard D’Souza, Granherne, et al.

SPE 133874 • “A Completions Guidebook to Shale-Play Development: A Review of Successful Approaches Toward Shale-Play Stimulation in the Last Two Decades” by K.K. Chong, Halliburton, et al.
Ultradeepwater-Subsalt-Reservoir Characterization: Integrated Multiscenario Development Planning
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142280, ’Ultradeepwater- Subsalt-Reservoir Characterization: An Integrated Multiscenario Approach for Development Planning,’ by Olivier Pippi, SPE, Statoil ASA (formerly with BP plc), Mike Mayall, Mike Chandler, SPE, Tim Dodd, Paul Reid, and Paul Taylor, BP plc, prepared for the 2011 SPE Europec/EAGE Annual Conference and Exhibition, Vienna, Austria, 23-26 May. The paper has not been peer reviewed.

Subsea development of clustered deepwater subsalt fields is challenging, technically and economically. With the high cost of appraisal wells, the industry tends to rely on seismic technology, pushing the limits of imaging and characterizing the reservoir by use of seismic attributes. A fully integrated approach that uses all available data should be followed to describe the uncertainty fully and to make an optimized business decision. This work shows a systematic method to integrate information available from a limited data set to validate the description of the field and to perform a full risk and uncertainty analysis supporting the field-development strategy.

Introduction

Many exploration plays in deepwater basins around the world involve structural closures associated with stratigraphic-trapping elements that are above or against salt diapirs or canopies. Below these often-large salt bodies, seismic imaging can be impaired significantly, which makes the crest of the structure particularly complicated to map. Updip volumes that are close to the salt can be difficult to describe with confidence, yielding large uncertainty about hydrocarbon volumes in place.

Reservoir faulting induced by the movement of the salt over geological time introduces significant structural complexity. This complexity adds to common stratigraphic and depositional complexity of deepwater reservoirs deposited in turbidite slope settings. Deepwater turbidite reservoirs can be large erosional channels (typically 1 to 3 km wide and 50 to 200 m thick) or can be sheet-like sands (typically 1 to 5 km wide and 5 to 30 m thick) with various degrees of channel amalgamation. Each type of reservoir poses specific development challenges in terms of continuity and connectivity.

Multiscenario Risk and Uncertainty Analysis

Given the structural complexity of the field, the wide range of oil-in-place estimates results in making risk and uncertainty analysis difficult to address at the same time. A project close to sanction would have a firmer resources-in-place definition before making a decision. Alternatively, the decision would have flexibility to be phased in over a certain time as new production data become available.
Technology Focus: Tight Reservoirs (October 2011)
Authors: Kubala Gregory
Published: February 2015

Technology Focus

Multistage fracturing of long horizontal wells remains the cornerstone for maximizing reservoir contact and drainage in low-permeability reservoirs. Operators are no longer satisfied with the “standard” design methodology of the past. Leading exploration and production companies are beginning to adopt a well-by-well design strategy for drilling and orienting the lateral to optimize the multistage fracturing treatments.

As experience continues to grow, engineers develop increasingly more-accurate models and workflows for exploration, development, and production of tight hydrocarbon-bearing reservoirs. Geomechanics, petrophysics, and geophysics are coupled with microseismic, fracture-treatment-pressure signatures, and production data to place, drill, and perforate wells better, all in an effort to maximize production derived from multistage fracture-stimulation treatments.

The best effective fracture half-length is not achieved automatically just by putting away millions of pounds of proppant with millions of gallons of water. Perforation strategies and pumping techniques do affect proppant placement for enhanced fracture conductivity. Hydraulic-fracture conductivity also is influenced by near-wellbore and far-field issues. Several papers indicate that production may increase significantly if actions are taken to address these issues.

As our industry enjoys the privilege of developing these reservoirs, it is incumbent upon us to meet environmental challenges, comply with regulatory requirements, and ensure public trust.

Tight Reservoirs additional reading available at OnePetro: www.onepetro.org

SPE 144279 • “Shale-Gas Developments in North America: An Overview of the Regulatory and Environmental Challenges Facing the Industry” by S.L. Sakmar, University of San Francisco Law School.

SPE 141597 • “Polymer Chemistry Improves Productivity in Tight Gas Hydraulic Fracturing” by Rick Hutchins, SPE, Schlumberger, et al.

SPE 142040 • “Optimization of the Design of Transverse Hydraulic Fractures in Horizontal Wells Placed in Dual-Porosity Tight Gas Reservoirs” by S.E. Gorucu, Pennsylvania State University, et al.

SPE 143304 • “The Effect of Fracture-Face Matrix Damage on Productivity of Fractured Wells With Infinite and Finite Fracture Conductivities in Shale-Gas Reservoirs” by Boyun Guo, University of Louisiana at Lafayette, et al.

SPE 140555 • “Design of Multiple-Transverse-Fracture Horizontal Wells in Shale-Gas Reservoirs” by Bo Song, Texas A&M University, et al.
Integrating New Seismic Technology and Regional Basin Geology Now a Must
Authors: Dribus John
Published: February 2015

Management

Since the discovery of the giant Tupi-Lula pre-salt complex in the Santos Basin of Brazil, explorers have been integrating new seismic technology advances with the fundamentals of regional basin geology to extend the pre-salt play across the Atlantic margin into deep waters and below the salt off the west coast of Africa. In 2005, Petrobras drilled a wildcat well on the Parati prospect in the deep waters of the Santos Basin, and encountered condensate gas below a thick layer of salt. The following year, Petrobras and its partners, BG Group and Galp Energia, announced that the Tupi wildcat, drilled to 16,060 ft in almost 7,000 ft of water, flowed at 4,900 B/D of sweet 30°API crude oil, 0.7 sulphur content, and 6.6 MMcf/D gas on a ⅝-in choke. This confirmed that a new geologic play had been discovered below the salt. Over the next few years, exploration efforts continued in this new pre-salt play, resulting in additional discoveries in the Santos and to the north in the Campos and Espirito Santo basins.

Agencia Nacional do Petroleo (ANP) studies suggested that the charge and accumulation models for this new pre-salt cluster area of the Santos Basin contained reserves exceeding 30 billion bbl and possibly as large as 60 billion bbl of oil reserves. Though the thick layers of salt above the oil accumulations create challenges in seismic imaging and exploratory drilling, the salt has also served, through geologic time, as a superb seal that allows thick columns of oil to accumulate and be preserved.     

Many exploration companies have already constructed regional geologic and plate tectonic models that recognize that these world-class pre-salt hydrocarbon accumulations off the east coast of Brazil may have counterparts on the conjugate margin of the Atlantic Basin in the deep waters offshore Congo, Gabon, Angola, and Namibia. A geologic model from Cobalt International shows a cross section of the Atlantic rift system that predicts similar geology between the two margins (Fig. 1).
Early-Life Field-Development Optimization of a Complex Deepwater Gulf of Mexico Field
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 22252, ’Early-Life-Cycle Field-Development Optimization of a Complex Deepwater Gulf of Mexico Field,’ by Patrick F. Angert, SPE, BP Exploration; Obiajulu J. Isebor, SPE, Stanford University; and Michael L. Litvak, SPE, BP Exploration, prepared for the 2011 Offshore Technology Conference Brasil, Rio de Janeiro, 4-6 October. The paper has not been peer reviewed.

A complex deepwater Gulf of Mexico field contains several stacked hydrocarbon-bearing intervals charged with volatile oil or rich gas condensate. Well locations, drilling schedule, and reservoir units into which wells will be initially completed and then later recompleted were optimized, maximizing net present value (NPV) while matching field-development constraints. Potential well locations and recompletion locations in geologically justified areas were evaluated. Drilling-rig pace and order and associated project and drilling economic constraints have been considered. BP’s Top Down Reservoir Modeling (TDRM) Option Evaluation (OE) technology has been extended to cover the simultaneous optimization of well completions and recompletions in reservoirs containing multiple stacked pay.

Introduction

Assisted-history-matching technologies have proved extremely useful for identifying multiple geologically plausible matches of historical production and surveillance data within existing fields. Assisted field-development optimization, although slightly newer, is nevertheless proving extremely useful in the identification, categorization, understanding, and ranking in economic and recovery terms of the multitude of possible development scenarios that could be implemented to produce oil, gas, or condensate from a field.

These technologies couple with existing full-physics reservoir simulators and rely on search-and-optimization algorithms such as genetic algorithms, Monte Carlo, or other optimization/search routines.

Typically, tens of thousands of possible development scenarios are generated in search of a much smaller set that meets all of the initial criteria specified while achieving higher overall project NPV and recovery. High potential cases are then investigated further, and, ultimately, a final development scenario is selected and refined further as a project progresses toward a final investment decision and commitment of project development capital.

Field Background

For the field under investigation, rich-gas-condensate and volatile-oil accumulations sit in a water depth greater than 6,000 ft. The upper hydrocarbon-bearing intervals occur below approximately 24,000-ft true vertical depth subsea (TVDSS) and extend to greater than approximately 29,000-ft TVDSS. The highest initial pressure of a hydrocarbon-bearing interval is approximately 20,000 psia.
Infrastructure Sharing Creates Value for Brazilian Deepwater Offshore Assets
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23004, ’Infrastructure Sharing: Creating Value for Brazilian Deepwater Offshore Assets,’ by Daniel C. Pedroso, SPE, Demetrius C. Abdala, and Luiz A.G. Pinto, Petrobras, prepared for the 2012 Offshore Technology Conference, Houston, 30 April- 3 May. The paper has not been peer reviewed.

Investments in infrastructure for deepwater production require a significant scale for achieving minimum economic returns. The infrastructure is normally planned to accommodate the peak production, and many of the assets may not be recovered or reused. Therefore, a significant spare capacity may arise in such assets. The use of spare capacity by other fields is a typical process in which both parties, the producer and the receiving facility, will benefit.

Introduction

The development of deepwater offshore production is characterized by high capital expenditure (CAPEX), significant economy of scale, and, in many cases, the complete technical unfeasibility of reuse of the materials and equipment.

Production infrastructure, when located in deepwater, is normally initially installed for the exclusive use of a specific field that justifies a standalone development approach. Processing, compressing, and export capacities are designed to attend peak production. Therefore, some spare capacity will appear at some point, which may be constrained by the amount of water that is handled in the unit.

Evolution of the Production Infrastructure in Campos Basin

The production in the deepwater Campos basin of Brazil has guided the exceptional growth of Petrobras in the last two decades, providing the technological, human, and financial resources that enabled the discovery of the giant presalt fields in Santos basin, currently under development. Petrobras’ net daily production in the Campos basin (oil and gas) reached 1 million BOE (annual daily average) in 2000, 1.5 million BOE in 2004, and 1.8 million BOE in 2010 (1.66 million bbl of oil). Other companies produce approximately 150,000 BOE/D. The Campos basin is Petrobras’ main producing area, currently producing 83% of the companys total output in Brazil. This production comes from 43 fields, including eight large oil fields in deep and ultradeep water, many of them developed using multiple production units. Petrobras’ proved oil reserves in the Campos basin are on the order of 10.7 billion bbl. The infrastructure already installed is extensive: Petrobras alone operates 40 floating production systems, 14 fixed platforms, and 6680 km of pipeline and flexible pipes in the area.

More recently, the activities began to focus on carbonate reservoirs below the presalt layer in the Sao Paulo plateau in water depths from 2000 to 3000 m. Several discoveries have occurred recently below the presalt in areas that are already in concession and are in production, sometimes with an existing production unit that faces the challenge of maintaining the economical feasibility under a low-oil-/high-water-production profile.
Technology Focus: Sand Management and Frac Pack (October 2012)
Authors: Azeemuddin Mohammed
Published: February 2015

Technology Focus

Production from challenging environments is fast becoming the norm for the oil and gas industry. We increasingly drill long horizontal sections in high-pressure/high-temperature reservoirs, deep and ultradeep water, and unconsolidated, depleted, and narrow-margin fields. With the cost of each well often exceeding USD 250 million, there is very little margin for error in designing and placement of the completions to avoid sanding-related issues and costly workovers.

Novel materials such as light and ultralight proppants and shaped memory polymers, cutting-edge technologies, and robust hardware are all important elements for meeting the ever-growing challenges. Meticulous planning, bench testing, and field validation form a prerequisite for cost-effective and safe execution. Effective research and development (R&D) efforts and close cooperation among academia, R&D services, and industry experts (operators) pave the way for a technically successful and economically viable exploitation of our depleting reserves. One should also spend the time and effort to improve understanding of rock behavior in its in-situ stress environment, as well as accurate characterization of the unique stress conditions in the field. A mechanical Earth model satisfactorily calibrated to the drilling events and geologically consistent with the stress environment is often required to model and test various possible sand control methods and their economics accurately.

Despite these efforts, it may not be possible to completely avoid sand production and its detrimental effects. Detecting and monitoring sand production with downhole monitoring tools, knowing the limits of effective sand management, and staying within those limits can be practical means for safe and long-term economic field development.

The selected papers highlight areas of current research focused on developing solutions and proper planning of safe hydrocarbon exploitation. Other interesting papers involving field applications and case studies, in no way less important, have been identified for additional reading.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 146650 Mechanical Modeling of Shape-Memory Polyurethane Foam for Application as a Sand-Management Solution by Cem Ozan, Baker Hughes, et al.

SPE 147044 The Use of Slotted Expandable Liners in Multizone Openhole Frac Packs: A New Completion Concept by David Mason, BP, et al.

SPE 146721 Ceramic Screens, an Innovative Milestone in Sand Control by S. Mussig, Maersk Oil, et al.