bluuebunny/crossref_metadata_2025_split huggingface dataset:
Coupling Reservoir and Well-Completion Simulators for Intelligent Multilateral Wells
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 164815, ’Coupling Reservoir and Well-Completion Simulators for Intelligent Multilateral Wells: Part 1,’ by G.A. Carvajal, N. Saldierna, M. Querales, SPE, K. Thornton, SPE, and J. Loiza, Halliburton, prepared for the 2013 SPE Europec/ EAGE Conference and Exhibition, London, 10-13 June. The paper has not been peer reviewed.
To maximize well productivity and reservoir oil recovery in mature fields, advanced lateral designs with intelligent completions have been implemented during the last decade. This paper describes an all-in-one system that combines nodal-analysis and numerical-simulation models to calculate the effect of intelligent-completion components—such as swell packers, internal control valves (ICVs), and inflow-control devices (ICDs)—on lateral production profiles. A 3D-grid, multiphase-flow, nonisothermal reservoir numerical simulator was used for advanced well design, and a wellbore nodal-analysis simulator was used to solve the partial-differential equations between the porous medium and the wellbore.
Introduction
Multilateral wells are often the best choice to maximize reserves recovery and contact with the reservoir and to extend the drainage area. However, several studies have revealed that multilateral wells exhibit a series of natural issues (e.g., high influx at lateral heels because of pressure drops). As a result of such issues, increased water or gas production can decrease oil production over time. Use of intelligent-valve technology can mitigate these problems significantly.
Reservoir Complexity and Heterogeneity
The reservoir model used here is a synthetic reservoir with an almost constant porosity of 20% and significant areal permeability variation from 1 to 500 md. The main depth is 8,000-ft true vertical depth subsurface. The net pay is 100 ft, and net/gross ratio used for the simulation is 0.8. A 3D sector numerical- simulation model was built with the following dimensions: x=100 cells, y=50 cells, and five layers, for a total of 25,000 cells.
The areal permeability distribution is taken from a geostatistical model. The permeability distribution is con-strained by spatial carbonate-facies distribution honoring log and core data of injector and producer wells in the sector model. Reservoir-quality index (RQI) is calculated to screen areas with best reservoir quality; an area where RQI equals 10 is considered the best area to place multilaterals.
However, the reservoir exhibits strong permeability contrast, not only among layers but also inside the carbon-ate body, as shown in Fig. 1.
Dynamic-Simulation Applications Support Challenging Offshore Operations
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156146, ’Dynamic-Simulation Applications To Support Challenging Offshore Operations: A Kitan Oil Field Offshore East Timor Case Study,’ Ryosuke Yokote, SPE, and Vanni Donagemma, Eni Australia, and Juan Carlos Mantecon, SPE, SPT Group, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed.
The Kitan oil field consists of three subsea intelligent wells. The intelligent completions were modeled in detail using commercial dynamic-simulation software to establish a sound and safe operating procedure for the well cleanup and well test. The simulation results provided the petroleum engineer on the rig with key operational information, such as the time for the oil to arrive at surface and expected pressure at the downhole gauges (DHGs) and upstream of the choke manifold. This enhanced the ability of rigsite supervisors to anticipate well behavior, enabling a significant risk reduction.
Introduction
The Kitan oil field is approximately 200 km south of the East Timor coast and 500 km offshore of the northern coast of Australia (Fig. 1). The Kitan field development consists of three vertical producing wells, 6-in. production subsea flowlines and risers, 2-in. gas-injection lines, umbilical lines, and a floating production, storage, and offloading (FPSO) vessel. Each well has a designated flow-line and riser tied back to the FPSO vessel (Fig. 2). Fig. 3 shows the intelligent completion for the Kitan development wells. The intelligent completion was de-signed to control flow from two separate zones, upper and lower. Flow from each zone is controlled by flow-control valves (FCVs) that have eight positions (fully opened, fully closed, and six intermediate choke positions).
Pressure and temperature for each zone are monitored by three DHGs. The FCVs have a fail-as-is design and stay in the last position should a communications problem be encountered.
Because of the remoteness of the location, the functionality of the intelligent completion and the well performance needed to be confirmed with a minimum degree of uncertainty. To establish a sound and safe operating procedure for the well cleanup and well test, commercial dynamic simulation software was used to model the intelligent completion and selected operations. A few different well-cleanup procedures were investigated to predict cleanup time, pressure and temperature at different points of interest, and flow rates on the rig. The simulation results provided valuable information, enabling the petroleum engineer on the rig to predict flow conditions of the well during the operations. Following the successful well-cleanup and well-test campaign, the well models were validated with actual well-cleanup and -test data.
Thin-Oil-Column Extended-Reach Drilling at Sakhalin
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163487, ’Case History of a Challenging Thin-Oil-Column Extended-Reach- Drilling Development at Sakhalin,’ by Vishwas P. Gupta and Shea R. Sanford, SPE, ExxonMobil Development Company; Randall S. Mathis and Erin K. DiPippo, SPE, Exxon Neftegas; and Michael J. Egan, AIPC, Consultant to Exxon Neftegas, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed.
ExxonMobil, operator for the Sakhalin-1 project, planned an additional drilling campaign at the Chayvo field, Sakhalin Island, Russia. The focus of this campaign was to develop a thin-oil-column reservoir by use of extended-reach drilling (ERD). This overview describes the planning of these wells at the edge of the ERD envelope, the associated technical and operational challenges, and the complexity of targeting a thin oil column in an ERD environment. Planning of these wells involved building upon the operator’s previous experience and the use of additional tools and methods to address unique challenges.
Introduction
The Sakhalin-1 project comprises the Chayvo, Odoptu, and Arkutun Dagi fields off the east coast of Sakhalin Island, Russian Federation, as shown in Fig. 1. Development drilling at the Chayvo field started in 2003 with extended-reach wells drilled from an onshore wellsite pad with the Yastreb drilling rig. In 2005, further development drilling commenced from the offshore Orlan platform. In 2008, the Yastreb rig was moved approximately 75 km north to the Odoptu onshore wellsite pad and drilled nine ERD wells as part of the initial-stage development of Odoptu. Following the Odoptu campaign, the Yastreb rig was moved back to the Chayvo onshore wellsite in 2011 for further development and infill drilling of the Chayvo reservoirs.
As of October 2012, 15 of the 20 longest ERD wells in the world had been drilled in the Sakhalin-1 project, with the recently completed Well Z-44 at Chayvo field setting a new measured-depth (MD) record at 12 376 m. Significant well-design parameters, tools, and techniques that enabled these challenging wells are detailed in the complete paper. The technical challenges included uncertainties in the location of the oil column and fluid contacts, the need for very accurate well placement for effective reservoir drainage and for preventing early gas/water breakthrough, completing long horizontal intervals, and high-torque/drag effects. The geologic uncertainties and wellbore-positioning challenges were addressed with a combination of a single near-horizontal pilot hole to locate the fluid contacts and a novel technique to minimize vertical-position uncertainty by use of formation-pressure measurements while drilling. Extensive torque/drag modeling and wellbore-stability modeling were performed to design the wells and equipment and define operational parameters. Completion designs were optimized to ensure successful placement in long horizontal intervals.
Unconventional Shale Play: Multilateral Technology and Selective Fracturing
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163959, ’Unconventional-Shale-Play Selective Fracturing Using Multilateral Technology,’ by Doug G. Durst, SPE, and Mario Vento, SPE, Halliburton, prepared for the 2013 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 28-30 January. The paper has not been peer reviewed.
Drilling, completing, and fracturing of unconventional-formation wells in North America have become commonplace for producing natural gas. It is less common to drill, complete, and fracture treat multiple lateral branches from a single main wellbore. Augmenting a multilateral well with selective fracturing of each leg is as straightforward as fracturing a single-horizontal well. In this project, a plug-and-perforate system was used to address ten or more intervals in each leg, with average stimulation pressures of up to 9,000 psi.
Introduction
Multilateral solutions enable working within a limited surface area, generating a reduced footprint while draining a much larger volume of reservoir from a single surface location. A few multilateral wells can minimize the effect, visibility, and liability of drilling operations to drain the entire reservoir, especially in environmentally sensitive or protected areas. Potential advantages of a multilateral system can be broken into two broad categories. First, reserves can be increased or production can be increased or accelerated over the life of the well. Second, the tangible and intangible costs of the project can be reduced.
Stimulating a Multilateral Well
Earlier techniques in vertical wells used conventional perforating, typically followed by ball diversion for isolation. Horizontal wellbores were treated with a few widely spaced intervals (four to eight zones), then longer horizontal sections were treated (with up to 90 zones) by use of newly developed techniques and systems.
Originally, ball-actuated fracturing-sleeve completions were limited to 15 to 20 intervals because ball-size increments were limited by the internal diameter (ID) of the fracturing string. New systems are available in which additional subintervals are created within the original primary intervals. With this system, five metering valves, plus one baffled valve, can be placed within the previously defined single interval. Thereby, it is possible to have six valves within each of the (up to) 15 primary intervals, for a maximum of 90 valves or 90 points to initiate fractures within a horizontal wellbore, compared with the previous limit of approximately 15 intervals.
Tests Detail Effects of Weighting Materials on Performance of Thermal Cements
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 163544, ’Performance of Thermal Cements With Different Weighting Materials,’ by Jean-Philippe Caritey, SPE, and Jason Brady, SPE, Schlumberger, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed.
To maintain zonal isolation throughout the life of a high-pressure/high-temperature (HP/HT) well, the cement sheath must perform reliably at temperatures that can exceed 315°C. Weighting materials have largely been assumed to be inert with respect to set Portland cement; however, the present study reveals that this assumption may be false in HP/HT environments in which well temperature exceeds 260°C. Some weighting agents may react with the set Portland cement, causing strength loss and increased permeability. Fortunately, this effect can be prevented, and the set-cement integrity can be preserved.
Experimental Procedures
Cement Blends. Five solid cement blends were prepared; their compositions are presented in Table 1. The blends were formulated according to the engineered-particle-size concept, wherein the volumes of coarse, medium, and fine particles are optimized to maximize the packing volume fraction (PVF). An increase in the PVF reduces the amount of mix fluid required to pre-pare a stable and pumpable slurry, and it increases the strength and reduces the permeability of the set cement.
The five blends contained 50% by volume of blend (BVOB) silica, which is sufficient to allow formation of the calcium silicate hydrate mineral xonotlite [Ca6Si6O17(OH)2] upon curing at temperatures above approximately 160°C. The weighting-agent concentration was held constant at 15% BVOB.
The slurries were prepared according to the recommended American Petroleum Institute (API) procedure.
Strength. The five slurries were placed in an ultrasonic cement analyzer (UCA) fitted with a dual-cylinder high-pressure pump that provided pulseless metering. They were cured at a final temperature and pressure of 302°C and 122 MPa, respectively, for periods of up to 100 days. Two additional tests were conducted at 274 and 288°C at a final pressure of 122 MPa.
It should be kept in mind that the UCA does not provide absolute strength values at such elevated temperatures because the transit time increases significantly during the heating period; therefore, one should consider strength trends vs. time. When possible, the cured- cement samples were crushed with a hydraulic press to obtain an accurate compressive strength. The recommended API procedure was followed.
Permeability. When possible, water-permeability measurements were per-formed on 5.08-cm-long, 2.54-cm-diameter cement cores with a liquid permeameter operating at a confining stress of 2.76 MPa.
Emerging Frontiers: The Progresssion of the SPE Strategy
Authors: Spath Jeff 
Published: February 2015

President's column
As you may remember, SPE adopted a new Strategic Plan in March 2013. The plan revolves around four major objectives:
Capability development
Knowledge transfer
Promoting professionalism and social responsibility
Public education about the petroleum engineering profession and industry issues
Since then, the Board committees and several Board-level work groups have been examining high-priority initiatives in each of these areas. Many of these were discussed at the recent Board of Directors meeting in Yangon, Myanmar. I would like to share with you updates on some of these important initiatives.
Capability Development
Our industry will continue to undergo a significant demographic shift over the next decade. SPE is devoting resources to support competency development (technical and soft skills) and assessment, assistance with the challenges of university faculty development and retention (to educate new engineers), and efforts supporting engineers in lifelong learning. So far the work group has addressed competency assessment and development in two ways. First the group mapped SPE products and services against several stages of life-cycle learning (pre-university, university, early career, midcareer, late career, retirement). SPE will be conducting a gap assessment and developing an action plan including a competency assessment.
Ensuring that we have enough petroleum engineering faculty is a key element in capability development. This is a topic that is close to my heart. I strongly feel SPE should help support faculty to gain and retain the brightest for the future of our industry. For this initiative, the work group made several suggestions to tackle this issue that the Board approved.
SPE held a Forum in August 2013 that resulted in a white paper, “SPE Forum Series: 2020 Foresight—Ensuring Educational Excellence for Upstream Engineering Resources,” available from OnePetro. Two pilot regional task forces are being established in the eastern US and Nigeria to identify and address local issues for university petroleum engineering education and to recommend actions.
SPE’s Board agreed to enhance its faculty awards and grants program and to launch an R&D competition. Also, the Board approved a modification to the SPE bylaws to include a permanent Board position for academia.
Knowledge Transfer
Knowledge transfer is the backbone of SPE. It is our mission. So the quality, timeliness, and delivery of knowledge are imperative for the industry’s growth. This covers a number of initiatives, including maintaining the highest technical quality within SPE programs, enhancing volunteer participation, making knowledge available on demand and in user-friendly ways, and taking full advantage of communications technologies to disseminate information.
Matrix Acidizing Innovation Surpasses Competing Methods in Saudi Carbonate
Authors: Rahim Zillur , Al-Anazi Hamoud , Ahmed Mahbub , Al-Kanaan Adnan , El-Mofty Wael 
Published: February 2015

Technology Update
Matrix acidizing is a method of stimulating carbonate reservoirs for oil and gas production. Unlike acid fracturing, matrix acidizing creates conductive flow channels, also known as wormholes, which possess much higher conductivity than the reservoir rock. These conductive channels transport reservoir fluids from within the formation matrix directly into the wellbore overcoming both low permeability and near wellbore damage. In matrix acidizing of moderate to prolific carbonate reservoirs, efficient acid placement is a major challenge, as acid tends to flow preferentially toward intervals with the highest permeability. It can result in overstimulation of these areas, leaving the low-permeability intervals untreated.
A significant percentage of matrix acidizing treatments do not meet expectations because of an improper job design and acid placement. In some cases, an increase in water production occurs after a stimulation job as a result of preferential stimulation of high-permeability sections associated with water.
Case Study: Khuff Carbonate
Khuff is a carbonate formation deposited on a shallow continental shelf in the Ghawar structure of eastern Saudi Arabia. It is divided into four intervals, A to D, with production mainly coming from the two gas-bearing layers: Khuff-B, a tight dolomite, and Khuff-C, a more prolific calcite.
Since its initial appraisal in the late 1970s, the majority of Khuff’s development activities have focused on the Permian Khuff-C formation. Extensive heterogeneity in stress, reservoir quality, and reservoir fluids throughout the field, combined with the deep and hot nature of the reservoir, makes effective stimulation of all layers a challenging task. All Khuff gas-producing wells require acid stimulation either by acid fracturing or matrix acidizing to obtain high production rates and sufficient flowing wellhead pressure to be tied into production facilities.
Until mid-2011, the majority of Khuff horizontal gas wells were drilled toward the maximum horizontal in-situ stress (σmax) to enhance wellbore stability and achieve the best penetration rates. However, when multistage fracture stimulation is desired and the well is drilled in the max direction, the fractures will grow longitudinally (parallel to the wellbore) and cause potential risk of overlapping with subsequent fractures. Therefore, initiation of the second and third fractures becomes a challenge because of possible pressure communication across the first induced fracture.
To avoid fracture overlapping, a well slated for multistage fracturing should be drilled toward the minimum horizontal in-situ stress (emin), which allows transverse fracture growth (perpendicular to the wellbore). Drilling wells toward min often poses challenges, such as wellbore instability and differential sticking, but the improved long-term productivity justifies the strategy.
Industry Flexes Muscles Again in Gulf of Mexico
Authors: Parshall Joel 
Published: February 2015

The oil and gas industry is flexing its muscles once again in the US Gulf of Mexico (GOM) with a surge of activity expected to support a robust level of deepwater development through the end of the decade.
While headlines worldwide have gone to onshore North American shale drilling, the GOM remains a premier objective for the world’s largest international companies. A single deepwater well can produce more than a large number of onshore shale wells combined, which translates to a lower capital cost per barrel for companies with the financial and technical wherewithal to develop deepwater resources.
The doubt cast over the future of GOM development in the aftermath of the fatal BP Macondo well blowout and oil spill in 2010, and the ensuing deepwater drilling moratorium, has receded.
Containment Advances
Two multicompany organizations, the Marine Well Containment Company and the Helix Well Containment Group, have now developed capping stack and spill recovery systems designed to contain a Macondo-sized blowout with equipment and resources permanently located in the GOM. The development and availability of sufficient containment technology was a necessary condition for the United States government’s decision to resume issuing deepwater drilling permits.
In addition, the government completed a major reorganization of its offshore regulatory system, strengthening offshore development oversight and the safety and environmental enforcement functions.
With the resumption of deepwater drilling permits and renewed acreage leasing, GOM activity has steadily increased over the past 2½ years.
As a final symbol of restored drilling and development momentum in the GOM, BP placed the high bids on 24 deepwater blocks in the federal lease sale for the central Gulf on March 19. Days earlier, the US Environmental Protection Agency (EPA) had lifted a suspension enacted after Macondo that barred BP from receiving new government contracts.
As a condition for regaining contract bidding rights, including bidding on government oil leases, BP agreed to retain an EPA-approved independent auditor to ensure that the company meets safety, ethics, and corporate governance standards.
Floating Rigs Increase
The number of floating drilling rigs that are active in the GOM—semisubmersibles and drillships that are designed for deepwater projects—has increased from 27 in October 2011 to 45 at the beginning of the year, according to data from IHS. Over the same period, the number of active jackup rigs—those rigs designed for shallow waters—fluctuated between 30 and 36 and at the start of the year stood at 31. The figures suggest the growing share of deepwater projects in total GOM activity.