bluuebunny/crossref_metadata_2025 huggingface dataset:
Hybrid System Brings Flexibility of CT to Long, Extended-Reach Wells
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 142769, ’New Hybrid System Brings the Flexibility of Coiled Tubing to Long, Extended-Reach Wells,’ by F. McNeil, SPE, S.D. Lindsay, SPE, R. Lyons, and R.P. Gracey, Halliburton, prepared for the 2011 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 5-6 April. The paper has not been peer reviewed.

The number of long extended-reach wells being drilled in the oil and gas industry continues to increase. These wells present complex challenges in completion and intervention procedures because operators demand the same level of performance achieved on shallower wells while providing a cost-effective and safe solution. To reach deep target depths with coiled tubing (CT), smaller coil must be used because of reel capacity, which limits pumping rates because of pressure and velocity limitations. As an alternative, jointed pipe can be used; however, using jointed pipe reduces the overall efficiency of the process because continuous pumping cannot be achieved. A new hybrid system uses both CT and jointed pipe in a single work string. The system incorporates a unique flapper safety valve that enables seamless functioning of the string in a live well. The hybrid system enables larger CT and jointed pipe to be deployed, which results in higher pumping rates and greater depths.

Large CT

Reel Capacity. A major hurdle when considering large lengths of CT is reel capacity. For example, the maximum length of coil that can be stored on a standard reel [assuming 144-in. reel outer diameter (OD)] is as follows:

1¾-in.-OD CT: 19,670 ft

2-in.-OD CT: 14,795 ft

2⅜-in.-OD CT: 10,151 ft

Lockup. Another important consideration in the design of any CT job in a highly deviated deep-reach well is lockup. Lockup occurs when CT forms a helix inside the casing and high wall-contact forces prevent any additional forward movement. While this effect will occur in all CT, smaller CT is more susceptible to complete lockup at shallower depths than larger CT. Therefore, larger CT is more likely to reach target depths.

Wellbore Cleanouts. Accumulation of sand and solids in wellbores significantly impairs oil and gas production; an influx of sand can impair or stop the flow of oil from a reservoir. This is commonly dealt with by CT intervention; in fact, nearly half of all CT operations involve well cleanouts. Conventional CT units are limited to small-OD coil when performing remedial operations on deep wells because of limitations in reel size, as well as local laws regarding width, height, length, and weight restrictions.
Technology Focus: Well Construction (May 2012)
Authors: Carpenter Bob
Published: February 2015

Technology Focus

The number and economic contribution of unconventional (tight gas/shale and steamflood) wells continued to increase rapidly in 2011, as did the participation of major operators. That increased industry focus was evident again in the distribution of papers. Also, there were more papers relating advances in plug-and-abandonment, Arctic, high-pressure/high-temperature (HP/HT), and carbon-capture technologies.

Manny Gonzalez, Chevron Energy Technology Company’s Alliance Manager, noted that the huge interest in shale-formation completions calls for efficient controlled fracturing technology to ensure economic viability and an environmentally responsible well completion. SPE 152185 outlines a direct comparison of openhole vs. cased-hole fracturing in a tight gas reservoir. The presented results are surprising, and the effects on incremental production, fracture height, and fracture half-length are significant—a good read.

Operators have been plugging nonproductive and storm-damaged wells at an increasing rate, and effective abandonment operations can prove costly and challenging. SPE 148640 relates a novel and well-detailed approach to a more efficient plug-and-abandon process and to the process of confirming plug integrity across an uncemented section of annulus. Check it out.

Industry emphasis on long-term well reliability has continued to increase, especially for steamflood projects. SPE 150022 details a very thorough look into the many design and operational factors that affect well reliability in a high-temperature (285°C) steamflood. While only briefly mentioned, the authors undertook controlling the rate of temperature change, and thus controlling temperature disparity (∆T) between casing, cement sheath, and formation during injection cycles. Controlling injection events can have a strong effect on the reliability of a steamflood well or even a deepwater or HP/HT well. This is the first field effort at controlling such events that I recall.

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

CMTC 152259 The Cement-Industry Roadmap To Reduce Carbon Emissions by L. Barcelo, Lafarge, et al.

SPE 148639 An Integrated Fluids Approach To Enhance Zonal Isolation in Deep Khuff Gas Producers and Injectors Offshore Abu Dhabi by Mohammed A. Mehtar, SPE, Abu Dhabi Marine Operating Company, et al.

IPTC 14913 A Paradigm Shift in Testing and Completion of Deep HP/HT Exploration Wells—Polished-Bore Receptacle (PBR) Improves Results and Operational Flexibility by Anwar Ibrahim, Kuwait Oil Company, et al.
Extreme-Environment Cementing in the Schoonebeek Heavy-Oil Field
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150022, ’Contemporary Approach Coupled With Traditional Techniques Tackles Extreme Wellbore Environment in Schoonebeek Heavy-Oil Field,’ by Andrew Foster, Auke Pollema, Ian Petitt, SPE, and James Heathman, SPE, Shell, and Carl Johnson, SPE, and Rudy Schlepers, Schlumberger, prepared for the 2011 SPE Heavy Oil Conference and Exhibition, Kuwait City, Kuwait, 12-14 December. The paper has not been peer reviewed.

The Schoonebeek heavy-oil field was first developed by Nederlandse Aardolie Maatschappij B.V. in the late 1940s. Because of economics, it was abandoned in 1996. In 2008, the Schoonebeek Redevelopment Project, using a gravity-assisted-steamflood (GASF) design concept, was initiated with 73 wells (44 producers, 25 injectors, and four observation wells). A key design requirement was long-term integrity of the cement sheath over an expected 25- to 30-year field life span. Complicating this requirement was the need for systems to place lightweight cement because lost-circulation issues were expected in both hole sections, particularly in the mechanically weak Bentheim sandstone.

Introduction

The Schoonebeek field was discovered in 1943 and was on production until 1996. During this period, 597 vertical and deviated wells were drilled. In 1995, two horizontal wells were drilled to test borehole stability while drilling horizontals and test sand production during the production phase. Core data in numerous vertical wells show that the reservoir is coarsening upward. The lower part of the reservoir has a lower permeability than the upper part of the reservoir. One-fourth of the original oil volume was produced over the approximately 50-year period (more than 250 million bbl). Approximately 120 million bbl is expected to be produced by use of the GASF technique. Planned plateau production is 3000 m3/d, with a steam-injection plateau of 8000 to 10 000 m3/d.

Cementing thermal wells, particularly cyclic-steam-injection wells, is one of the most crucial and challenging cementing operations. Maintaining well integrity and zonal isolation over time is critical to the economic success of a steam project. The fundamental purpose of primary-cementing operations is the provision of effective zonal isolation during the life of the well. As wells become more challenging, more demands are placed on the cement-slurry design, operational practices, and in-situ properties of the well annular sealant. Uniform competent cement sheaths can minimize buckling, collapse, parting, or elongation caused by thermal stress.
Innovation: Funding SPE Programs and Services
Authors: Imomoh Egbert
Published: February 2015

President's column

In the next two months, I am going to deviate from the theme of my previous columns on innovation. As indicated above, this month I will share with you how SPE funds its programs and services and next month I will write about the work on strategy that your board has been working on.

I am happy to report that our membership continues to grow. Total SPE membership (professional and student) exceeded 110,000 at the end of 2012. These members continually look to SPE for good programs and services, and our mission to disseminate technical information to all of them and to do so quickly, affordably, and in new ways, is increasingly challenged. SPE accomplishes this primarily through meetings, lectures, training courses, and publications. So, how does SPE fund all of these things?

All of SPE’s major business segments (meetings, publications, membership, re-tail sales, SPE.org) contribute to the overall success of SPE, but as Fig. 1 illustrates, meetings are SPE’s largest source of revenue. Although SPE now conducts around 140 events worldwide each year, most of the revenues from meetings come from the financial success of a small number of conferences with large exhibitions, like the Offshore Technology Conference and Offshore Europe. Most other events are budgeted to break even or generate a small surplus.

Your board recently considered and approved SPE’s budget for Fiscal Year 2014 (1 April 2013 through 31 March 2014). It has total operating revenues of USD 92.4 mil-lion and expenses of USD 84.4 million, resulting in a net income of USD 8 million. Here is the important thing to remember when you are considering these numbers. Unlike commercial organizations, our income goes back into benefits for our members. This helps us keep dues, meetings registrations, and publications prices reasonable, and helps us support programs that produce little or no revenue on their own, like scholarships, the very popular Distinguished Lecturer visits, and our peer-reviewed journals.
Downhole Gauges Meet Challenges of Operating Beside ESPs in HT Reservoir
Authors: Kettle Bob , Scott Michael
Published: February 2015

Technology Update

Talisman Energy needed to enhance its continuous downhole monitoring capability at the Gyda field offshore Norway with a system that could perform in high-temperature (HT) conditions and operate beside electric submersible pumps (ESPs) in two oil production wells.

Situated in the southern Norwegian Sea 270 km from Stavanger, Gyda is a mature field in which production peaked in 1995. To address the increasing water production and decreasing reservoir pressure, the company installed ESPs in the completion of new wells A-19A and A-26 in 2011. Estimated field production for 2011 was 8,000 BOPD, according to the Norwegian Petroleum Directorate. The field’s production license was recently extended to 2028.

Challenges for New Monitoring System

The Gyda field has an extensive permanent downhole monitoring network that tracks information on individual well conditions, such as temperature and pressure. Through sensors, gauges, and other downhole operating equipment, Talisman can monitor and, if necessary, maintain pressure; control each well; and optimize field production. However, adding monitoring systems to the A-19A and A-26 wells presented special challenges.

The systems, which would need to monitor well zone conditions and the ESPs to ensure their function at the optimum points of their pump curves, would face reservoir temperatures as high as 160°C (and pressures as high as 300 bar). The HT environment can put enormous stress on instrumentation and impair its ability to generate reliable data. The standard gauges designed for the ESPs were not qualified to operate at the higher temperature levels found in the Gyda reservoir, thus further justifying the need for enhanced permanent monitoring.

Another challenge was that the new downhole monitoring systems would have to operate effectively next to the ESPs. These pumps require large amounts of power, which is transferred downhole on a three-phase cable. This cable runs alongside the ESP cable and is susceptible to noise disturbance from the pumps’ motors and variable speed drive (VSDs).

The VSDs—at 12 and 24 pulse, for example—can cause total harmonic distortion. This can be induced onto the downhole gauge control lines and interfere with downhole communication and gauge electronics, particularly during an ESP startup when the drive current can be six to eight times the normal operating current.
Decade of Stimulation Experience in the Deepwater Gulf of Mexico
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 159660, ’A Decade of Deepwater Gulf of Mexico Stimulation Experience,’ by Lee N. Morgenthaler, SPE, and Leigh A. Fry, Shell E&P, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed.

The deepwater Gulf of Mexico is a technically and economically challenging production environment. High rates and ultimate recoveries are required per well to offset high development costs. Stimulation treatments maintain wells at peak production rates and accelerate reserves recovery. In these complex layered reservoirs, stimulation is necessary to ensure recovery volume. The primary objective of stimulation is to restore impaired well/reservoir connectivity. Successfully identifying the cause and location of impairment is required. Looking back over a decade of experience in this challenging environment yields useful insights as the industry moves into new deepwater provinces.

Introduction

Shell’s deepwater development began in 1991 with the Tahoe subsea prospect tied back to the Main Pass 252 platform. Development continued with the Auger, Mars, Ram Powell, Ursa, and Brutus tension-leg platforms (TLPs) and many subsea fields that tie back to them (Fig.  1). Most of the reservoirs producing to these structures are geologically young turbidite sands that require sand control. Initially, all of the fields were geopressured significantly above hydrostatic and were significantly undersaturated. The soft compacting sands and aquifer support often provide sufficient energy to achieve adequate recovery by depletion.

The hydraulic fractures created in the frac-pack process provided lower skin values with minimal use of acid. The horizontal openhole gravel packs used acid-soluble bridging agents to stabilize the wellbore during gravel packing. The bridging agents were then removed with acid washing. Because most of these sand-control completions were cased-hole gravel packs or cased-hole frac packs, most of this paper refers primarily to the experience with those completion types.

As the fields matured, there were more subsea-tieback developments. Stimulation campaigns generally focused on the direct-vertical-access (DVA), or dry-tree, wells of the TLPs. However, stimulation of subsea wells has been highly profitable, and technology has been developed to reduce the subsea-intervention costs to make these interventions more attractive. The complex operations on TLPs introduce challenges when planning and conducting stimulation operations. Logistics coordination and proper management of returning wells to production are critical to realize production gains and to meet environmental-discharge regulations and goals.
Who Dat Project - Deepwater Subsea Production of Light and Heavy Oil
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 23378, ’Subsea Who Dat Project—Producing Light and Heavy Oil in a Deepwater Subsea Development,’ by Gerard J. Simms, SPE, Bruce Cooley, SPE, and Rick Fowler, SPE, LLOG Exploration; Kosta J. Leontaritis, SPE, AsphWax; and Kana Krishnathasan, SPE, Intecsea, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.

Plans were developed to produce multiple deepwater reservoirs with vastly different fluid properties from a subsea development in 3,100 ft of water in the Gulf of Mexico. Diagnostic and flow-assurance (FA) testing of the different-density oils addressed viscosity including non-Newtonian, wax, asphaltene, and hydrate behavior; downhole and flowline commingling; and fluid-compatibility tests. Provisions for pigging and a chemical-treatment program were added for extra assurance. A larger-sized oil-export line was selected to allow sufficient capacity for blended or heavy oils after restart.

Introduction

The Who Dat field is in the Mississippi Canyon protraction area of the Gulf of Mexico and is being developed with the Opti-Ex semisubmersible floating production system (FPS), which has a capacity of 60,000 BOPD and 150 MMcf/D of gas. The field primarily contains oil and consists of ten stacked amplitude- supported reservoirs in a salt-withdrawal minibasin. Three wells had been drilled at the time this paper was written, penetrating more than 700 ft of net pay in nine distinct reservoirs ranging in depth from 12,000- to 17,000-ft true vertical depth. Both gas and oil reservoirs were found, with varying fluid properties. Significant fluid data were acquired in the openhole program, with more than 60 downhole fluid samples. Twelve full pressure/volume/temperature (PVT) studies and eight diagnostic FA studies were performed to gain an early understanding of the fluid. Later, flowback oil samples were acquired, rechecked, and evaluated further.

Field development includes 12 subsea wells (i.e., wet trees) flowing into three four-slot subsea manifolds. Drill Center A has one manifold, and Drill Center E has two manifolds. Each manifold is connected to the FPS with dual 6-in.-nominal-diameter wet-insulated flowlines and flexible risers having the capacity of roundtrip pigging. These infield flowlines are approximately 3 miles long, and the seafloor geometry results in a downsloping flowpath. The project includes a 10-in. gas-export line and a 14-in. oil-export line, also with flexible risers. Fig. 1 shows the subsea layout.

The key inputs for the FA process are uncontaminated fluid samples and detailed laboratory analysis. In the case of system selection for the Who Dat field, fluid samples were available from three wells and multiple formations. There were uncertainties about key formation-fluid properties resulting from drilling-fluid contamination, including viscosity, foaming, and wax content.
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.
Drilling Rigs Evolve Seeking Productivity Gains
Authors: Rassenfoss Stephen
Published: February 2015

The vision of fully automated drilling rigs driven by big data gathered in real time looks so far off but there are people working on a road map to help the oil and gas industry find its way there some day.

Drilling rigs working onshore are evolving, driven by the need to manage the high cost of mass producing thousands of wells needed for unconventional development. The rate of penetration (ROP) is the most commonly used measure of efficiency, but the location and the quality of the hole can be significant variables.

The number of wells drilled per year is up as the rig count goes down with many older rigs finally being retired. The rig market overall looks soft, but demand remains strong for late-model rigs wired to handle computer controls (AC drive). While they command higher day rates than older rigs, by drilling wells in fewer days they can help oil companies lower the cost per foot drilled.

At a panel discussion at the recent IADC/SPE Drilling Conference and Exhibition in Fort Worth, Texas, Michael Power, manager of unconventional resources for global drilling and completions at Chevron, said the company is seeking to reduce the average cost of drilling onshore wells in unconventional formations by 15% or more a year.

The goal has been regularly reached with a combination of incremental improvements. In addition to the rate of penetration, gains can be made in other ways, such as reducing nonproductive time, or the time and trucks needed to haul a rig to a new site. “A level of automation speeds drilling and movement of rigs,” Power said.

One indication of the pace of change is the growing market share of Helmerich & Payne (H&P), whose rigs now represent 15% of the onshore market in the United States—about twice its share in 2001—and the company is adding at least two rigs a month to its fleet.

Its rise dates back to its decision to be the first in the industry to design and build a new generation of drilling rig called FlexRigs. A critical difference is those rigs were wired to accommodate systems from the company automating certain functions, increasing a driller’s productivity. It has built five generations of the rigs and is working on the next.

Significant drilling time reductions have been a trend in unconventional exploration. H&P has drilled 10,000 ft of hole in 10.5 days from the start of work on a horizontal well to when the rig is released, said Jeff Flaherty, senior vice president of land rig operations at the company.

But gains in the rate of penetration are getting harder to find. “We are moving to the short end of the bell curve on the time to drill,” he said

Ever faster drilling takes its toll. “Unconventional drilling is hard on equipment and hard on people,” said Flaherty, who said the cost is going down per foot drilled, but the wear and tear is squeezing the company’s profit margins.
International HSE Conference Discusses Crisis Leadership
Authors: Wilson Adam
Published: February 2015

Conference review

More than 1,000 people gathered in Long Beach, California, in March for SPE’s 2014 International Conference on Health, Safety, and Environment (HSE). In addition to the opening and closing sessions, the conference consisted of three plenary sessions, 13 panel sessions, and 44 technical sessions that presented more than 200 papers.

Opening Session

The grand ballroom at the Long Beach Convention and Entertainment Center was nearly full for the opening session on 17 March. Roland Moreau, Conference Committee chairperson, and Kathy Kanocz, Executive Committee chairperson, introduced Jeff Spath, 2014 SPE President, who, in turn, introduced Leonard Marcus and Eric McNulty of the Harvard University National Preparedness Leadership Initiative.

Marcus and McNulty presented the idea of what they call “meta-leadership,” based on their research into the responses to the Boston Marathon bombings of 2013, Hurricane Katrina, and the Macondo oil spill disaster in 2010. Meta-leadership, Marcus said, involves leadership that reaches “beyond the confines of your particular role or position.”

Marcus and McNulty said that, during times of crisis, people’s brains respond by “going to the basement.” This refers to the instinctual responses of freeze, flight, or fight. During those moments, McNulty said, “all your brain is focused on survival. You can’t do any complex problem solving. You’re not very productive in terms of figuring out what’s actually going on.” The key to successful crisis management, he said, is to get out of the basement as quickly as possible in order to make sound decisions.

“You, as a crisis leader, have to be smarter than your brain,” Marcus said. This return to rational decision-making can be made by sending a second signal to the brain. This second signal can be as simple as taking a deep breath or counting to 10. With practice, one can build a second neural pathway to speed one’s return to productive thinking.