bluuebunny/crossref_metadata_2025 huggingface dataset:
Digitizing E&P: Accelerating the Pace of Change
Authors: Deskus Archana (Archie)
Published: February 2015

Guest editorial

The pace of change is accelerating on a global scale, and the agent of this accelerated pace is digitization. Digitization has had a profound impact on our personal lives. It has transformed and created industries and has creatively destroyed some existing business models. Certain industries, such as finance, automotive, aerospace, communications, and media, have led the way. Others have been slower to adapt.

The oil and gas industry is a major driver of high-performance computing development, particularly for upstream seismic processing and permanent field monitoring. The oil and gas industry currently has the highest refresh rate across all industry sectors that high-performance computing addresses. Yet findings from leading information technology research and advisory firms such as Gartner and AMR indicate that the exploration and production (E&P) industry is in the low quartile for digitization.

Realizing the Digital Vision

“Digital oilfield” is an umbrella term for technology-centric solutions that allow E&P companies to leverage limited resources and improve decision making to maximize production; minimize capital and operating expenses and environmental impact; ensure the safety of the people involved; and protect the integrity of associated equipment across the entire upstream process. It encompasses both tools and processes surrounding data and information management. Its success depends on capability, organizational alignment, and—ultimately—attitude.

The industry has crossed many of the technology barriers to enabling the digital oilfield. Remote sensing is available for almost all facets of drilling and production operations, and the number of choices for network transmission of data continues to expand. The industry has invested heavily in knowledge management systems, real-time operations centers, and collaborative decision environments. It has become adept at moving data gathered from field devices into software applications and using it to enhance some specialized field operations. However, the industry has not yet succeeded in achieving the cross-disciplinary data transparency, information sharing, process integration, and collaboration that are essential to realizing the ultimate vision and value of the digital oilfield. Examining other industries’ paths to digitization may help us in our quest.

A Look at Aerospace

A number of parallels can be drawn between the aerospace industry and E&P, including the fact that both involve “flying in the dark”; both rely on close, long-term partnerships among operators, service companies, and equipment manufacturers to generate economic value; and both envision varying degrees of “unmanned flight” to reduce the margin of error, address safety and cost opportunities, and open additional opportunities to create value.
Fiber Optic Feed-Through Packer Technology Assists Multizone Fracturing and Production Monitoring
Authors: JPT staff _
Published: February 2015

Young Technology Showcase

Fiber optic pressure and temperature (P/T) sensing technology for multizone fracturing and production monitoring is enabled by a new feed-through (FT) technology that integrates the optical fiber within the multiple elastomer elements of a compact, swellable openhole packer system to achieve competent zonal isolation.

It is important that a continuous length of optical fiber be installed across the multiple zones isolated by the swellable packer system. Splicing the fiber is problematic because the process is time c4onsuming, and the splice point degrades faster than uncut fiber. Over time, the splice presents a weak point that can limit system life. This is compounded in long, multizone completions that may require as many as 40 isolation points along the well.

Weatherford’s Fraxsis FT technology facilitates deployment of continuous lengths of optical fiber across multiple zones as part of a modular packer system made up of short (24-in.) swellable elastomer sections that provide high-pressure zonal isolation. The FT technology is also a key enabler in the development of a faster, spoolable fiber deployment capability.

Fiber optic monitoring of a fracture stimulation and the resulting production across every stage of the completion provides engineers with the information to improve stimulation and completion design, and optimize production over the life of the well. The FT technology enables fiber-optic monitoring using a proven packer technology that achieves high-pressure zonal isolation with a much shorter inflatable element, which reduces packer stiffness and makes the system easier to run.

Technical Details

The FT packer design is based on a modular approach that uses single or multiple swellable elastomer elements to create isolation points for the completion (Fig. 1). Each element incorporates a proprietary metal backup system to achieve a higher pressure rating with less than half the length of a conventional swellable packer.

The metal backup system expands concurrently with the elastomer to prevent extrusion of the rubber element and form a higher pressure seal. Depending on the completion’s pressure requirements, 24-in. elastomer sections are added to the packer system to achieve 1,500 psi (one element), 3,000 psi (two), and higher-pressure specifications. As a result, the technology allows a packer only 7 ft long to seal up to 5,000 psi with the same hole-conformance of traditional swellable packers.
New Techniques in Interpretation of Closure Pressure in the Montney Formation
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163825, ’Interpretation of Closure Pressure in the Unconventional Montney Using PTA Techniques,’ by Robert V. Hawkes, Pure Energy Services; Irene Anderson, Talisman Energy; R.C. Bachman, Taurus Reservoir Solutions; and A. Settari, SPE, University of Calgary, prepared for the 2013 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 4-6 February. The paper has not been peer reviewed.

The Montney formation in Canada is one of the largest resource plays in North America. Horizontal multistaged fracturing is the best method for developing this vast resource. Before hydraulic fracturing of the wellbore, the toe stage is frequently minifractured to obtain reservoir and geomechanical properties. Various pressure-transient-analysis (PTA) -based interpretation techniques have been introduced to the industry over the last few years for the determination of closure pressure. From a theoretical viewpoint, unification of the fields of traditional PTA and minifracture interpretation has been achieved.

Introduction

Despite low natural-gas prices, the Montney- play region of northeast British Columbia remains one of the most active of such plays in North America. Operators continue to push drilling activity in the Montney, with increased liquids production within many portions of the trend. Characterization techniques and stimulation and production mechanisms continue to make economics favorable. Prefracture diagnostic testing is an approach that regulators and operators are now more commonly using in unconventional and tight formations. Industry’s current use of minifracture analysis for the determination of fracture closure and after-closure reservoir properties, however, still presents several challenges.

The conventional approach to all minifracture analysis is the 1D Carter leakoff model, which leads directly to the concept of G time. For more than 30 years, G time (or the G-function) has played the dominant role for the determination of closure stress, but there remains ambiguity in performing minifracture analysis. Part of the problem is that the recommended plots do not rigorously identify the various flow regimes that occur during a minifracture/falloff. Minifracture analysis requires a general theory that accounts for all of the actual observed flow regimes (both before and after closure).

The objective of this paper is to create and perform a consistent workflow process of four Montney diagnostic injection tests (one vertical and three horizontal wells) on the same pad, with a systematic approach highlighting the characteristic flow-regime slopes when using the Bourdet log-log derivative plot. In brief, the Bourdet derivative function used in the PTA-based log-log derivative approach accounts for rate variation before the analyzed shut-in period. The workflow we present is also dependent upon plotting the primary-pressure derivative (PPD) in combination with the Bourdet log-log derivative plot.
High-Performance Water-Based Drilling Fluids Offshore Cameroon
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163502, ’High-Performance Water-Based Drilling Fluids: An Environmentally Friendly Fluid System Achieving Superior Shale Stabilization While Meeting Discharge Requirement Offshore Cameroon,’ by Anuradee Witthayapanyanon, SPE, Baker Hughes; Jerome Leleux, SPE, Julien Vuillemet, Ronan Morvan, and Andre Pomian, Perenco; and Alain Denax and Ronald Bland, SPE, Baker Hughes, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed.

Historically, invert-emulsion drilling fluids are the preferred system for drilling offshore Cameroon. However, with a regulatory environment moving toward zero discharge, associated costs are rising. Therefore, an operator planning to drill in this environment investigated high-performance water-based-mud (HPWBM) -system alternatives. HPWBM systems offer the potential advantage of offshore discharge of drilled cuttings and effluents (owing to the absence of oil contamination) and lowered waste-management costs. Experience in the field demonstrated that the selected drilling fluid met expectations by achieving the required drilling performance and high shale stabilization with zero environmental impact.

Introduction

Drilling with an overbalanced pressure is a common operational technique used to prevent formation fluids or gas from entering the wellbore, thereby minimizing the risk of well kick and blowout. However, overbalanced drilling can cause drilling fluid to invade the formation, resulting in formation damage, differential sticking, and sloughing if the formation consists of highly reactive clay and shale. To avoid these consequences, invert-emulsion drilling fluids have always been preferable for drilling highly reactive clays and shale formations.

The HPWBM system is formulated with a concept of total inhibition. Unlike a conventional water-based-mud system, designed chemical additives are used explicitly in the formulation to achieve desired drilling characteristics that are similar to those of invert-emulsion mud. The key features of HPWBM systems include high shale stability, clay and cuttings inhibition, rate-of-penetration (ROP) enhancement, minimized bit balling and accretion, torque and drag reduction, and environmental compliance.

A complementary benefit of its aqueous base is that HPWBM captures the growing need for more-environmentally- friendly drilling fluids. During the past 10 years, more-stringent regulations on drilling-waste disposal have been implemented worldwide. The industry anticipates that the zero discharge of oil-contaminated drilling wastes will soon be the global standard. By switching from invert-emulsion drilling fluids (oil-/synthetic- based mud) to an HPWBM system, operators can achieve substantial cost savings on waste management and logistics. These savings result from the use of on-site, offshore discharge allowed by an absence of oil contamination.
Comments: Iraq's Potential
Authors: Donnelly John
Published: February 2015

Editor's column

Iraq may eventually alter the global production landscape, but the initial steps taken last year and in early 2010 to revive its oil sector have been cautious. Questions about infrastructure, security, export ability, and contract terms continue to hold back any change of a quick recovery.

Iraq contains the world’s third-largest proven reserves of conventional oil and eventually could rival Saudi Arabia as OPEC’s top producer, but the oil industry is so far skeptical of the country’s plans to boost production from the current 2.5 million BOPD to 6–7 million BOPD in 6 years. Some analysts say that number could be higher. James Burkhard, director of oil research for energy consultants IHS-CERA, believes that Iraq’s untapped oil fields could add almost 10 million BOPD within 10 years, changing the dynamics of OPEC. 

That may be too much to ask a country hampered by years of war, sanctions, post-war violence, and messy politics. But even if it met half its goal, the impact would be huge. Saudi Arabia, long OPEC’s swing producer with the ability to affect oil prices by raising or curtailing production, currently produces 8 million BOPD but has a capacity of at least 12 million BOPD.

Iraq has held two international bid rounds to try to attract investor interest in reviving its E&P with mixed results, although the globe’s largest operators appear to be key to fixing and reviving the energy landscape there. In January, Iraq awarded the last of 10 international licenses to develop fields during the two rounds, just half of the 21 fields on offer. Fifteen firms won the rights to develop fields under 20-year contracts, the first outside company access to Iraq since foreign firms were banned in the 1970s. The country apparently remains one of the few regions in the world that has vast reserves that have not been well-exploited.

There are already some optimistic signs. One of the country’s largest fields, Rumaila, is scheduled to begin producing an additional 100,000 BOPD in July. BP and CNPC won the rights to that field in the first auction last June. The field is estimated to contain 15% of Iraq’s total reserves.

Among the January winners were Shell and Petronas, which won the rights to develop Majnoon, one of the largest unexploited fields; CNPC, Petronas, and Total, which won the rights to the Halfaya field; and Lukoil and Statoil, which were the high bidders on perhaps the most valued property, West Qurna-2. Other winners were Eni for the Zubair field and ExxonMobil and Shell for West Qurna-1.

Elections scheduled for this month could be critical for Iraq’s future oil development. Nonviolent elections that lead to a more stable political and business environment will go a long way to attracting the type of investment needed to develop its vast potential. Of particular need is an oil law that will protect the rights of foreign oil investors.
New Zealand "Open for Business" and Operators Responding
Authors: Redden Jim
Published: February 2015

In the late 1880s, New Zealand’s Taranaki provincial government issued a proposition: It would pay then-fledgling operators “400 pounds for the discovery of a spring of petroleum, sufficiently copious to be profitably worked.”

Fast-forward more than a century and it is clear that the passage of time has not swallowed the spirit of that offer. Declaring their country “open for business,” the federal contemporaries of those Taranaki visionaries have renewed the appeal, pulling out all stops to bolster their claim that New Zealand is a secure, relatively undrilled, and very fertile haven for exploration dollars. Along with providing attractive tax incentives, the government has initiated a USD 20-million government-funded seismic-acquisition program with the resulting data shared freely with operators.

The multifaceted campaign appears to be working. Government figures show a considerable increase in oil production in 2008, offsetting a slight reduction in gas output. Even though the total well count was down in 2008, increased focus offshore resulted in operators spending an aggregate NZD 114 million more on exploration than the previous year. According to the New Zealand Ministry of Economic Development’s Crown Minerals Group, total expenditures in petroleum exploration rose to NZD 314 million in 2008, up from NZD 200 million the previous year. That, according to the ministry, was the highest exploration spend in a decade.

The increased expenditure largely was a result of the drilling mix. During the previous year, a total of 42 wells were drilled, of which all but 16 were exploratory. Between January 2008 and July 2009, a total of 34 wells were drilled, but the composition changed dramatically, with 26 higher-cost appraisal and development wells completed. While the most recent year-end numbers are yet to be tallied, “the total number of wells drilled, including exploration, looks to have increased in 2009 over 2008,” said Crown Minerals spokesperson Tracy Dillimore.

Final 2008 oil-production figures fell a just short of the national record that has held since 1997, according to the ministry. At the end of 2008, total crude oil, condensate, and naphtha production totaled 21.298 million bbl, 29,000 bbl short of the 21.327 million bbl record set more than 10 years earlier when the Maui B gas and condensate extension began full production. Maui B is expected to help extend production from New Zealand’s oldest producing field to 2020 or beyond. Oil production in 2008 represented a 43% increase over 2007. The two largest contributors to the 2008 increase were the newly commissioned Tui and Pohokura fields that delivered 13.44 and 4.58 million bbl, respectively.
Technology Focus: Hydraulic Fracturing (March 2010)
Authors: Chipperfield Simon
Published: February 2015

Technology Focus

Edward de Bono (physiologist and lateral thinker) said: “You can’t dig a new hole by digging the same one deeper.”

The “same hole” refers to current beliefs or work processes and a “new hole” refers to new ideas or concepts. This quote alludes to the “psychological inertia” that tells us to stay in the hole we have been digging since “how could we possibly let it go to waste?”* In our fast-paced world it can seem more acceptable to continue digging the same hole than be seen “sitting back” considering where to dig next.

This is general societal commentary, but how does the fracture-stimulation industry compare? The diagram shows the proportion of papers reviewed for the 2010 hydraulic-fracturing feature and which phase of the project cycle they focus on (i.e., initiation, planning, implementation, or review).

These data imply that we spend the least amount of dedicated effort conducting detailed look-back reviews of our work. It begs the question—Are we doing our best to learn from the past (i.e., using existing information to reflect on where to “dig”), or are we happy just to “dig the same hole deeper?”

Hydraulic Fracturing additional reading available at OnePetro: www.onepetro.org

SPE 123586 • “Proper Evaluation of Shale-Gas Reservoirs Leads to a More Effective Hydraulic-Fracture Stimulation” by Donald Kundert, SPE, Halliburton, et al. (See JPT, July 2009, page 59)

SPE 124327 • “Coupled 3D Numerical Investigation of Hydraulic-Fracture Cleanup for Both Slickwater and Gelled Fluids” by Hector A. Wills, SPE, Colorado School of Mines, et al.

SPE 124227 • “Evaluation of Haynesville Shale Vertical-Well Completions With a Mineralogy-Based Approach to Reservoir Geomechanics” by Brian LeCompte, SPE, Baker Hughes, et al.

SPE 122315 • “ Geomechanical Factors Affecting the Hydraulic-Fracturing Performance in a Geomechanically Complex, Tectonically Active Area in Colombia” by J.G. Osorio, SPE, BP plc, et al.

SPE 122185 • “The Use of Saturated Fracturing Fluid To Cope With Hydrate in Gas Wells Located in Ultradeep Waters” by C.A. Pedroso, SPE, Petrobras, et al.

*Mann, D., www.triz-journal.com/archives/1998/08/b/index.htm, accessed 27 January 2010.
Technology Focus: Production Operations (March 2010)
Authors: Alhanati Francisco J.S.
Published: February 2015

Technology Focus

I was joking with my colleague Todd Zahacy that we should write a series of papers about the number of things we production engineers usually do not know when trying to design or optimize a production system and, therefore, the risks we take that things may not go exactly as planned.

Zahacy was quick to forward me a link to the now-famous quote of former US Secretary of Defense Donald Rumsfeld (explaining the limitations of intelligence reports): “There are known knowns. There are things we know we know. We also know there are known unknowns. That is to say, we know there are some things we do not know. But there are also unknown unknowns, the ones we don’t know we don’t know.”*

I was thinking mostly of our lack of scientific knowledge in certain areas, but Zahacy reminded me that bad-quality data or bad assumptions also can lead to devastating results. We both believe that engineers should often question the source of information and the validity of assumptions, and then make a conscious effort to think about significant effects that may not have been considered.

Some of the papers featured in this issue stress the importance of knowing as much as possible about a production-operation issue before trying to address it: knowing where (and why) the produced fluids or solids are entering the wellbore before planning a workover or knowing how a downhole device is likely to function (or not) under certain operating conditions before installing it in a well, among other issues. Other papers listed here stress the importance of questioning one’s source of information (e.g., the validity of some meters’ readings and/or the representative nature of some fluid samples).

Usually, we are good at sharing our successes, but we can also learn much from our failures. Let us share more often the troubles we sometimes get ourselves into, and save our peers in the industry some grief.

Production Operations additional reading available at OnePetro: www.onepetro.org

OTC 20204 • “The Impact of Reservoir-Fluid Compositional Variation and Valid Sample Acquisition on Flow-Assurance Evaluation” by Oliver C. Mullins, SPE, Schlumberger, et al.

IPTC 14068 • “Multiphase Metering in Siberian Gas and Condensate Wells—Lessons Learned in Multiphase Well-Testing Operations Since 2006” by Bertrand Theuveny, SPE, Schlumberger, et al.

SPE 123949 • “Case Study: Successful Application of a Novel Conformance Treatment in an Extended-Reach Horizontal Well in the Al Shaheen Field, Offshore Qatar” by M.H. Pedersen, SPE, Maersk Oil Qatar, et al.

IPTC 13765 • “Successful Field Application of an Inhibitor-Concentration-Detection System in Optimizing the Kinetic-Hydrate-Inhibitor (KHI) Injection Rates and Reducing the Risks Associated With Hydrate Blockage” by Orlin Lavallie, Dolphin Energy, et al.

OTC 20013 • “Operation of Multiphase Flowmeters in the Sour Environment of the Qatif Field, A Case Study” by Faisal M. Al-Dossary, SPE, Saudi Aramco, et al.

*www.scientiﬁ camerican.com/article.cfm?id=rumsfelds-wisdom accessed 27 January 2010.
Novel Thermal Technology Uses Two-Wellhead Wells
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 120413, ’A Novel Thermal Technology of Formation Treatment Involves Bi-Wellhead Horizontal Wells,’ by R.R. Ibatullin, SPE, N.G. Ibragimov, SPE, R.S. Khisamov, A.T. Zaripov, and M.I. Amerkhanov, Tatneft, originally prepared for the 2009 SPE Middle East Oil and Gas Show and Conference, Bahrain, 15-18 March.

The Republic of Tatarstan possesses significant reserves of heavy oil and bitumen. The first pilot project on heavy-oil production through vertical wells dates back to the 1970s. A number of thermal methods were tested including in-situ combustion, cyclic-steam stimulation, and gas/steam-mixture injection. However, all these methods demonstrated their insufficiency. In 2006, a new pilot project was launched. This is a modified technology of steam stimulation through a pair of U-shaped horizontal wells.

Introduction

There are many applications of the steam-assisted gravity-drainage (SAGD) method in Alberta, Canada. The efficiency of the SAGD method greatly depends on the presence of water-saturated and shale interlayers in the reservoir section.

In 2006, a new pilot project was launched in Ashalchinskoye field to test a modified low-pressure SAGD technology using a unique pair of U-shaped horizontal wells (two-wellhead wells) (Fig. 1). This technique overcomes some disadvantages of classic SAGD technology.

This deposit occurs at approximately 78 m and has a rather complex structure. Water-saturated interlayers are found in the top and in highly oil-saturated zones of the formation, while shale stringers are found in the middle of the sequence. Both aquifers and tight, low-permeability, calcareous sandstones or a low-saturated reservoir can serve as the bottom of the formation. 

New Solutions

To date, three pairs of U-shaped horizontal wells have been drilled in this area, with the length of horizontal wellbores from 200 to 400 m. The wells were drilled with a vertical drilling rig, hitting the surface at an angle, thus having two wellheads–vertical and slanted.

Two parallel horizontal wells were completed with sand screens and were drilled one above the other at a vertical distance of 5 m between them. The process monitoring is carried out through vertical evaluation wells, and a fiber-optic cable is used for temperature measurement along the horizontal wellbore.

The wells were completed by swabbing until mud and solids stopped being produced; then, steam was injected into both wells with the subsequent placing of the lower well on pump production; temperature was monitored along the wellbore length to determine lost-circulation zones and to control the profile of the wellbore heating.
Technology Focus: Seismic Applications (March 2010)
Authors: Kleemeyer Gerd
Published: February 2015

Technology Focus

Finding and producing hydrocarbons from increasingly complex reservoirs and the push to maximize recovery stimulated a decade of steady growth in high-end seismic solutions covering the full E&P life cycle. In challenging imaging environments, the improvements achieved with the latest acquisition and processing technology are significant. Not surprisingly, associated cost pressures and budget constraints increasingly force geophysicists to strive for adequate and cost-effective solutions. Simultaneously, we experience a renewed focus on adding value by pushing the integration with other disciplines to new levels.

Papers reviewed for the new Seismic Applications feature highlight how seismic technologies pay dividends on the basis of an improved understanding of the subsurface. Several contributions discuss wide-azimuth seismic, which has become the norm in complex-imaging environments such as the Gulf of Mexico. Advances are not confined to marine surveys, and densely sampled wide-cross-spread surveys are being acquired onshore also. The logistical efforts for these modern surveys are large. Accurate planning and detailed survey design are essential for efficient and successful delivery. Beyond improved imaging, rich-azimuth seismic, probably in combination with multicomponent acquisition, has a realistic potential to enable fracture detection on the basis of azimuthal-anisotropy analysis. This technology can provide considerable value in carbonates and tight reservoirs in which fractures have a strong effect on connectivity and production rates.

Robust and accurately calibrated rock-physics models are a prerequisite to bridge the gap between seismic and reservoir modeling. For carbonates, this is notoriously difficult, and enhanced physical models are being developed that result in more-reliable reservoir-property predictions. Reservoir models only approximate the actual subsurface, and seismic constraints are used more routinely to reduce remaining uncertainties. Next to static-model updates, repeated 4D-seismic surveys provide information about the dynamic-reservoir behavior. Permeability maps derived from 4D seismic can be incorporated during the history-matching process, providing a promising leap toward real integration of subsurface disciplines and improved recovery.

Seismic Applications additional reading available at OnePetro: www.onepetro.org

IPTC 13692 • “Multicomponent-Seismic Applications for Maximizing Efficiency and Production from Fractured-Carbonate Reservoirs in Idd El Shargi Field” by E. Maili, Occidental Petroleum of Qatar, et al.

IPTC 13882 • “Microseismic Reservoir Monitoring in a Deep-Wellbore Carbonate Environment in Kazakhstan” by K.G. Maver, SPE, Schlumberger, et al.

IPTC 13870 • “Wide-Azimuth Seismic Azimuthal Analysis in Offset Vector Domain for Velocity and Amplitude” by Jean-Luc Boelle, Total, et al.
Planning, Acquisition, and Processing of a 3D Circular-Shooting Seismic Survey
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 13363, ’Planning, Acquisition, and Processing of the First Industrial 3D Circular-Shooting Seismic Survey,’ by M. Buia, E. Tozzi, and L. Mapelli, Eni E&P, prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December.

Conventional offshore 3D acquisition is performed mainly with narrow-azimuth-streamer configurations, even in structurally complex areas. A full 3D circular-shooting seismic survey (coil) over the Tulip discovery in Indonesia during August and September 2008 acquired a full-azimuth data set with a single-vessel towed-streamer operation by sailing in circles. The circular geometry introduced several differences and a number of new challenges in the modeling, acquisition, and processing workflow.  

Introduction

Tulip is a complex structure in the Bukat Block offshore Kalimantan, Indonesia. The water depth ranges from 350 to 1800 m. Several unfavorable geological conditions cause a very poor seismic response in the area. Methane hydrates represent the main problem. The hydrates layer in this area generates a very reflective sea bottom that causes up to seven multiple bounces. The presence of shallow free gas is suggested by an abrupt frequency-amplitude dimming below this bottom-simulating reflector. The well drilled on the structure indicates a seismic-quality factor of less than 70. Moreover, the rough geomorphology of the water bottom, characterized by canyons and irregularities, causes a nonhomogeneous behavior of the illumination in the subsurface and a complex 3D ray path for surface and internal multiples. Complex deep geology (steeply dipping thrust with two culminations) represents a third critical factor, posing severe structural-illumination doubts. Also, the low reflectivity of the target sequence often falls below the noise level. Therefore, vintage seismic in the area is of very poor quality. Circular shooting is an acquisition technique in which the vessel follows a circular preplot line. Circles are repeated in the x- and y-directions to increase fold, offset, and azimuth distribution. This method allows for full-azimuth acquisition by use of a single vessel shooting on a continuous turn. Line changes are short, on the order of minutes, resulting in high acquisition uptime and efficiency. The offset and azimuth distribution of circular shooting is excellent, as good as and sometimes better than the wide multiazimuth techniques.
Carbonate-Rock-Physics Issues
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 13850, ’Carbonate-Rock Physics Issues,’ by Enru Liu, Michael A.Payne, Shiyu Xu, Gregor Baechle, and Christopher E. Harris, ExxonMobil Upstream Research, prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December.

Limestone and dolomite reservoirs account for approximately half of oil and gas production worldwide, yet seismic responses in carbonate rocks are poorly understood. Development of a carbonate-rock-physics model is extremely difficult because the pore systems are more complex in carbonates than in clastics. In addition to pore types and shapes, other factors that need to be included in a physics-based rock model include lithology, grain shapes, multiphase-fluid and wetting effects, rock/fluid interactions (poroelasticity), stress effects, anisotropy, heterogeneity and scale effects, chemical changes to the framework, and corrections for environmental effects for logging conditions. The effect and validation of several of these factors are presented.  

Introduction

Carbonates can have a variety of pore types, such as moldic, vuggy, interparticle, or intraparticle. The complex pore system creates significant scatter in the porosity/velocity relationship. Pore shape appears to be the dominant factor in carbonate-rock physics. Moldic, intraframe, and vuggy pores tend to be rounded and make the rock stronger (faster) than pores that are interparticle. Micropores (e.g., microcracks) tend to be flat and make the rock weaker. To characterize carbonate reservoir rocks effectively, it is critical to develop a rock-physics model that is capable of handling different pore types. Any rock-physics model should be calibrated and validated with controlled laboratory experiments, field measurements, and computational rock physics.

Carbonate-Rock Physics Model

An analytical-rock-physics model was selected rather than an empirical one because of the analytical model’s predictive power without the need to acquire considerable analog data and because it is physics based. Empirical rock-physics models often are used because of their simplicity in fitting a relationship between parameters. With an analytical model, once parameters that describe the physical controlling factors are determined, the model can be applied anywhere that the controlling parameters can be estimated. This method achieves better predictions and a deeper understanding of the subsurface than empirical models, with less data. Nonlinear physics-based inclusion models are attractive because they handle various factors that affect seismic response in an internally consistent manner.
Israel's Gas Bonanza
Authors: Beckwith Robin
Published: February 2015

In late December 2010, Noble Energy confirmed one of the world’s largest gas finds of the decade—the 16-Tcf (450-Bcm) Leviathan field—located in approximately 5,400 ft of water approximately 80 miles offshore Haifa, Israel. The find is 29 miles southwest of the Tamar field, which is approximately 56 miles offshore west of Haifa and which yielded the world’s largest gas discovery in 2009: an estimated 8.4 Tcf. (See Fig. 1.)

Noble Energy (39.66%) operates Leviathan, with Delek Drilling and Avner Oil Exploration (22.67% each) and Ratio Oil Exploration (15%). Noble also operates Tamar and Dalit, with 36% working interests.

Supported by 3D seismic acquisitions in 2009 and 2010, Noble has identified a number of additional prospects and leads on its significant acreage position offshore Israel and Cyprus.

Israel now faces the unprecedented prospect of at least partial energy independence—that afforded by the domestic presence of natural gas offshore in the subsalt and Plio-Pleistocene reservoirs of the Levant basin province.

The Gas Bonanza: Sudden or Gradual?

While news of the gas bonanza appears dramatic, the shift in Israel’s energy stance represents the continuation of a trend building since the discovery offshore Ashqelon in 1999 of the Noa gas field and the Mari-B area in 2000. The impact of this trend started to be felt early 2004 when Mari-B—Israel’s first offshore natural gas production facility—began supplying significant quantities of natural gas to the country’s domestic market.

According to online Israeli state records, Israel has produced gas since 1958. However, the largest annual amount—5.2 Bcf in 1969—represents only 12.4% of 2004’s 42.1 Bcf. And between 2004 and 2008, the entire production of 401 Bcf was 5.5 times greater than all the gas produced in Israel between 1958 and 2003. By 2009, more than half the natural gas consumed in the country was pro-vided by Israel’s Yam Tethys consortium, with the remainder supplied by Egypt-based East Mediterranean Gas Company (EMG).

The Levant Basin Province

A report issued by the US Geological Survey (USGS) in March 2010 assessed the undiscovered oil and gas resources of the Levant basin province (Fig. 2) in the eastern Mediterranean. The area, encompassing approximately 32,000 sq miles, covers onshore and offshore territory including the Gaza Strip, Israel, Lebanon, Syria, and Cyprus. The USGS estimates the area holds a mean of 1.7 billion bbl of recoverable oil and a mean of 122 Tcf of recoverable gas. The assessment relies heavily on work done in the prior decade by Michael A. Gardosh of the Geophysical Institute of Israel, and Yehezkel Druckman and Binyamin Buchbinder of the Geological Survey of Israel.
EOR Development Screening of a Heterogeneous Heavy-Oil Field
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 129157, ’EOR Development Screening of a Heterogeneous Heavy Oil Field- Challenges and Solutions,’ by J.P. Strauss, SPE, D.M. Alexander, SPE, N. Al-Azri, M. Al-Habsi, SPE, T. Al-Musallami, M. Koning, F. Eriavbe, Mukman Mukman, and, R. Al-Jarwani, Petroleum Development Oman, and A.J. Landman, SPE, Shell Technology Oman, originally prepared for the 2010 SPE EOR Conference on Oil and Gas West Asia, Muscat, Oman, 11-13 April. The paper has not been peer reviewed.

The full-length paper details an enhanced-oil-recovery (EOR) development-concept screening from a subsurface perspective. The field is a medium-sized heavy-oil field with complex geology and is in South Oman. The two primary concepts considered are steamflood and polymer flood, each of which presents its own challenges. Common to both concepts is the difficulty in obtaining adequate conformance in a field that is characterized by high and highly variable permeabilities in a channelized environment and that includes lateral extensive shales that break the system into vertically distinct sand units.   

Introduction

The field has been under primary production by use of progressing-cavity pumps (PCPs) since January 1989, with 35 vertical wells and one horizontal well drilled within the field oil/water contact.  The oil is medium heavy (18°API), has a low gas/oil ratio (less than 0.2 m3/m3), and is relatively viscous (400 to 1,000 cp), implying a very adverse-mobility-ratio for displacement of oil by water. In spite of this, many wells show a slow development of water cut, though they ultimately pro-duce at high water cuts.  Observations of pressure vs. depth show evidence of local differential depletion of individual sand units and, coupled with the slow water-cut development, support the concept of laterally extensive shales. Pressures in the deepest sand unit show an initial decline followed by recent recharge in spite of increased off-take. This is interpreted as representative of the changes in the regional aquifer pressures that are being driven by much larger off-take and water-disposal volumes at neighboring fields. Historical production has achieved a low recovery, given the relatively low rates achievable with vertical wells under cold production and the high water cuts once water breakthrough has occurred. Thermal recovery initially was identified as the only mature EOR approach that conceivably could achieve a reasonable recovery in such a system, and, as a consequence, the operator has embarked on a single-pattern steam trial that has been operating since 2008. Recent data-gathering and -analysis efforts including downhole sampling with a wireline formation-testing tool have revised initial estimates of oil viscosity downward, allowing a wider range of development concepts to be considered.
Riserless, Remotely Operated Technology Enables 10,000-ft Intervention Without Rig
Authors: Law Matthew
Published: February 2015

Technology Update

Intervention is necessary during the life cycles of most subsea wells. However, traditional methods can make it time consuming and very costly, with spread rates for drilling and semisubmersible rigs running at USD 1 million to USD 1.4 million per day. There are more than 4,000 producing subsea (wet tree) oil and gas wells worldwide, and the number is increasing by approximately 500 per year. With many wells more than a decade old, intervention is crucial to enable maximum oil and gas extraction.

The sustained rise in deepwater exploration has made the need for cost-effective intervention on wet well trees even more pertinent. With the challenging conditions encountered in deep subsea settings such as Asia, Brazil, West Africa, and the Gulf of Mexico, many wells have produced for several years without necessary intervention. This often results in suboptimal production and reduced ultimate recovery. 

The AX-S system, developed by Expro, is designed to provide a safe, riserless, and remotely operated subsea well intervention method that can complete a typical deepwater intervention in six to eight days, compared with 10 to 12 days for a rig intervention, at a cost savings of approximately 75% to 80% based on lower day rates and speedier job completion. The system, designed and built over a seven-year development period with the input of more than 200 vendors, is in the final commissioning stage. Commercialization is expected later this year.

Deployed from a monohull vessel (Fig. 1), the system is the first rigless intervention technology that can operate in waters up to 10,000 ft—several hundred feet deeper than the world’s deepest subsea well. The improved economics afforded by the system will allow operators to increase production and recovery rates in wet tree wells that otherwise might wait additional years for interventions.

To enable deployment of the system, Expro has entered into a multiyear charter party contract with TS Marine Asia Pacific to use its dynamically positioned (DP) multiservices vessel Havila Phoenix for worldwide operations. The DP 2 Class vessel is 361 ft long and 75 ft wide with a moonpool of 23.6 ft by 23.6 ft, a 94-ton fiber rope drum winch with deployment tower, a 276-ton wire rope subsea crane, and two ultraheavy-duty Work Class remotely operated vehicles (ROVs) rated to more than 13,000 ft. The winch and crane are equipped with active heave compensation systems.
Model Integration and Data Optimization Software Enables Integrated Project Modeling
Authors: Braswell Gentry
Published: February 2015

Technology Update

Integrated asset modeling and optimization is an underserved niche in an industry where its demand is increasing because of the growing complexity of operating environments.

Software called Pipe-It, which falls under the category of “integrated asset management tools,” and specifically “model integration and optimization,” was unveiled in December by Petrostreamz of Norway. It is designed for building integrated model-based tools for oil and gas asset optimization. Petrostreamz is a software spinoff of PERA, a consultancy firm in global pressure, volume, and temperature (PVT) modeling and gas enhanced oil recovery modeling.

Curtis H. Whitson, a professor at the Norwegian University of Science and Technology (NTNU) and the chief technical officer of Petrostreamz, said the software addresses a much needed, underserved segment. Although it is a commercial product, it is made available to university students and research institutes in order to cultivate a data stream translation user community in the oil and gas industry.

The company has published two Pipe-It integrated asset management (IAM) technical papers: the first in 2009 with paper SPE 121252, “Model-Based Integration and Optimization—Gas Cycling Benchmark,” and the second in 2010 with paper SPE 130768, “Multi-Field Asset Integrated Optimization Benchmark.” In both, all model data sets are made avail-able to the public, including the Pipe-It project itself, for those who wish to test their IAM solution against the company’s published results. The second benchmark is a complex integrated model publicly documented from NTNU’s Center for Integrated Operations (www.ntnu.edu/iocenter), with specific attention to the paper SPE 130768 benchmark (www.ipt.ntnu. no/~io-opt/wiki/doku.php).

“If the application runs from a command line, you can integrate it in Pipe-It. In the past, model integration was more limited, as market solutions were sold in packages from a single vendor,” said Petrobras production engineer Sthener Campos. “It was used as a commercial strategy to tie the client. This scenario goes against a smooth implementation as it clashes with the profile of final users. Preset integration packages require users to change the software they used to develop engineering, and the knowledge they already own.”

Streamz Technology

The software performs four main functions: data stream translation, the orchestration of multiple processes, parametric analysis, and project optimization. The data stream translation is based on a technology for translating data streams for oil, gas, and water, from one description to another, with each description being needed as input for different software applications.
Higher Resolution Subsurface Imaging
Authors: Neal Jack , Krohn Chris
Published: February 2015

R&D Grand Challenges - This is the fifth in a series of articles on the great challenges facing the oil and gas industry as outlined by the SPE Research and Development (R&D) Committee. The R&D challenges comprise broad upstream business needs: increasing recovery factors, in-situ molecular manipulation, carbon capture and sequestration, produced water management, higher resolution subsurface imaging of hydrocarbons, and the environment. The articles in this series examine each of these challenges in depth. The R&D Grand Challenges Series, comprising articles published in JPT during 2011 and 2012, is available as a collection on OnePetro (SPE-163061-JPT).

Introduction

It is hard to read road signs if you have poor eyesight, which is why driver’s licenses are issued with restrictions requiring that corrective lenses must be worn. Likewise, it is hard to find and exploit subsurface resources if you can’t clearly see your targets or monitor the movement of fluids in the reservoir.

Engineers now have powerful tools to precisely model subsurface reservoir production behavior, but a precise answer is still wrong if it is derived from an inaccurate subsurface description.  Geoscientists make maps and rock property models of the subsurface by interpreting images that are produced from remote sensing data. Analogs from modern depositional environments and outcrop exposures guide subsurface data interpretation to predict ahead of the bit, then postdrill geostatistics are used to fill in stratigraphic details between wellbore control points. Selection of the right depositional model, facies distribution, and geostatistical analog depends on having the sharpest, most detailed and accurate image of the subsurface possible—the Grand Challenge of Higher Resolution Subsurface Imaging.

Over the past century, the industry has relentlessly sought ways to improve subsurface imaging of hydrocarbons. Canadian inventor Reginald Fessenden first patented the use of the seismic method to infer geology in 1917. A decade later, Schlumberger lowered an electric tool down a borehole in France to record the first well log. Today, advances in seismic and gravity data acquisition, electromagnetics, signal processing and modeling powered by high-performance computing, and the nanotechnology revolution are at the forefront of improved reservoir imaging.

In this paper, we will examine the challenges of getting higher resolution subsurface images of hydrocarbons and touch on emerging research trends and technologies aimed at delivering a more accurate reservoir picture.