bluuebunny/crossref_metadata_2025 huggingface dataset:
Technology Focus: Well Construction (May 2013)
Authors: Carpenter Bob
Published: February 2015

Technology Focus

In 2012, the number of unconventional tight gas/shale and high-pressure/high-temperature (HP/HT) papers continued to grow. This year, we had some very interesting developments in these and other areas of well construction.

Paper SPE/IADC 163544 demonstrates that there is still much we do not understand regarding HP/HT cement chemistry. This paper discusses how well-temperature increases and cement designs densified with various weighting materials can negatively affect cement strength stability and permeability. Surprisingly, the subject materials that have been employed have, for decades, generally been considered inert.  We see that the chemistry and even the particle size of these weighting materials can negatively affect cement strength stability and permeability as maximum well temperatures increase. 

Paper SPE/IADC 163534 describes a new hydraulically set, permanent, openhole whipstock that has been field proved on multiple wells to provide a reliable, time-saving, single-trip solution in the Granite Wash formation. The Granite Wash formation in southwestern Oklahoma has been a directional-drilling nightmare. This is a hard, abrasive, multilayered formation generally requiring significant rig time and multiple trips to kick off successfully and build to horizontal. I appreciate the support of John Lofton, senior drilling consultant with Chevron Exploration and Technology Company, in recognizing the value of this paper.

Paper SPE 163842 relates the potential time saving available through the use of multiple sliding sleeves along a horizontal annulus. The sliding sleeves allowed for near-continuous pumping of 15 stimulation treatments in 24 hours rather than the 3-day average required to place similar stimulation treatments in other Eagle Ford wells by use of the plug-and-perforate process. The authors report similar productivity while providing less risk and execution time.

In addition to these selected papers, be sure to check out the papers listed under additional reading.

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

SPE/IADC 163452 HP/HT Well Construction With Closed-Loop Cementing Technology by Don Hannegan, Weatherford, et al.

SPE 159589 New Pressure-Actuated Valve Allows for Interventionless Access to Formation in Cemented Applications by C. Christopher Johnson, Baker Hughes, et al.

SPE/IADC 163459 Dynamic Cementation: A Solution to Well-Integrity Problems by Calvin Holt, Tesco, et al.
Drilling System With Built-In Kickoff Ramp Allows for Dependable Curve Building
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 163534, ’Innovative Drilling System With a Built-In Kickoff Ramp Allows Dependable Curve Building in Granite Wash Formation,’ by G.A. Bruton, SPE, and J. Talkington, Chesapeake, and P. Desai, S. Swadi, SPE, and J. Kelley, Schlumberger, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed.

The Granite Wash formation presents several challenges in drilling the build section from a vertical open hole to form a lateral. The formation is hard and abrasive, and it is difficult to anticipate downhole rock properties. The erratic nature of the formation results in unpredictable performance by the steerable drilling assembly and drill bits. In most cases, the target build rates are not achieved, forcing multiple trips. An innovative drilling system has been developed that provides a dependable kickoff ramp and a firm beginning for initiating the build section without having to rely on the fulcrum point of the drilling bottomhole assembly (BHA) in a single trip downhole.

Challenges

The complex Granite Wash formation (Fig. 1) presents many drilling challenges, particularly beyond 12,000 ft, specifically when building a curve to horizontal at 14°/100 ft.

One of many formation-related challenges was to reduce the number of trips. The conventional sidetracking technique for the open hole has been to run and set a whipstock/anchor assembly at the kickoff point in a separate trip using a different BHA. Once the whipstock was secured, the directional-drilling assembly was run to initiate and finish the curve and reach the landing point. The extra trip, however, needed to be eliminated.

The erratic nature of the formation also makes it difficult for the driller to use the offset to optimize bit selection to drill the highly abrasive formation efficiently. The driller usually selects a proven tricone bit dressed with abrasion-resistant cutters. Despite that, the bit’s cutting structure wears pre-maturely, forcing the operator to make multiple trips downhole with a new polycrystalline-diamond-compact (PDC) bit to finish the curve.

Solution: Innovative Drilling System

The most prevalent sidetracking technique in an openhole application has been to set a cement plug and time drill with controlled rate of penetration (ROP) with a directional-drilling assembly. The cement-plug method generally required 3 to 5 days to get a plug set and dressed off in an oil-based mud. The cement-plug method was replaced by a conventional but reliable whipstock/anchor system, which required a separate trip.
Comments: Mexico's Next Step
Authors: Donnelly John
Published: February 2015

Editor's column

The opening of Mexico’s energy sector to private foreign investment continues to move forward, with more details of the landmark legislation expected soon. The potential impact this will have on Mexico, its state oil company, and the upstream industry in general is hard to overestimate. Mexico, with all its hydrocarbon riches, has essentially been closed to outsiders since 1938, when the country declared that all mineral and oil reserves in Mexico belong only to the nation.

Mexico has watched its neighbor to the north, the United States, reap the benefits of shale development and ultradeepwater production in the Gulf of Mexico with oil prices hovering around USD 100/bbl. The country now would be reversing decades of resource nationalism, allowing foreign oil firms access to potentially world-class fields.

In March, national oil company Pemex submitted to the government its list of fields and acreage that it would like to keep under the new energy reform regime. Fields not on the list are expected to be offered in auctions, with Pemex allowed to bid on those as well. The first licensing round is not expected to be held until 2015 with production-sharing and profit-sharing contracts both under discussion. Acreage would likely include conventional resources, unconventional, and deep water. Pemex may also seek partnerships with foreign firms for acreage under deals that could be signed as soon as this year.

Published reports say that Pemex requested acreage containing 83% of Mexico’s proved and probable hydrocarbons reserves and 31% of its prospective resources. The acreage includes conventional onshore and shallow water fields, in addition to deepwater fields already under development as well as deepwater areas where discoveries have unveiled attractive prospects, such as in the Gulf of Mexico Perdido Fold Belt. Mexico’s energy ministry has a September deadline to decide what acreage Pemex can keep and what will be available for bidding.

International oil companies may be particularly interested in prospective unconventional acreage, such as in the northern part of the country near south Texas, and the unexplored deep water. The state oil company is thought to have neither the finances nor the technology to develop those areas on its own.

Pemex is trying to shore up its declining oil production. Current crude output is averaging slightly more than 2.5 million BOPD this year, the same level of production since 2012, and down significantly from a peak of almost 3.4 million BOPD in 2004. Enhanced oil recovery methods at mature fields and plateauing production at the main offshore Cantarell complex are helping keep output from falling further. Crude oil exports average approximately 1.27 million BOPD. Mexico’s once-prolific Cantarell field is producing about 355,000 BOPD, down from 2 million BOPD a decade ago, and the offshore Ku-Maloob-Zaap complex is expected to start declining soon from its current 860,000 BOPD output. JPT
Technology Focus: Deepwater Projects (May 2014)
Authors: Salies Jacques Braile
Published: February 2015

Technology Focus

In the kingdom of wet completion, Petrobras has just installed its first tension-leg wellhead platform, in the field of Papa Terra in 1190-m-deep water. It is going to be a revolution regarding how to operate such an installation and be able to produce the heavy oil of Papa Terra (14–17°API). For many years, Petrobras engineers have being analyzing the use of a tension-leg platform or a spar as a solution for their field developments, and, finally, it came through. I strongly believe that all the lessons learned from installation (completed by now) to operation will result in much better solutions for the future of dry completion in our industry. In past JPT reviews, I wrote about the effect for field developments of the first floating production, storage, and offloading vessel in the Gulf of Mexico installed by Petrobras in Cascade and Chinook. And I believe that, once again, Petrobras is creating the same impact now in its own backyard.

In February 2014, Petrobras reached a production of 400,000 B/D in the Brazilian presalt 8 years after of the discovery of the first field. In this presalt cluster, the consortium led by Petrobras, including Total, Shell, CNOOC, and CNPC, will be developing the Libra field, one of the biggest discoveries in ultradeep waters in the world. The estimated reserves of 8 billion to 12 billion bbl of recoverable oil will demand a great amount of resources to cope with the challenges of developing this gigantic field. If you are an engineer looking for an opportunity for technological growth and learning experiences, do not miss this chance.

Lately, I have been reading a lot about the shale gas/oil developments in the United States, and I am amazed to see the forecasts showing that this gas/oil production will lead the United States to be self-sufficient by 2020 and a net exporter by 2030. It is a good example of what technology can do for you when combined with entrepreneurship. I have been reading also that unconventional oil and gas has taken money out of deepwater developments and that some majors have deferred their projects because of economics compared with tight oil projects. Equilibrium will come, and I believe both will contribute to our oil/gas supply. JPT

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

SPE 166337 Water-Depth Record for Electric-Line Operations—Retrieving Asphaltenes With Riserless Light Well Intervention by Steven Ashcraft, Anadarko, et al.

OTC 24529 Roncador Module IV: A Successful Case in Heavy-Oil Projects In Ultradeep Water by E. Bordieri, Petrobras, et al.

OTC 24508 Scale Management in Deep and Ultradeepwater Fields by M.C.M. Bezerra, Petrobras, et al.
Complex-Event Processing for the Intelligent Field
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 167817, ’Implementation of Complex-Event Processing for the Intelligent Field,’ by Muhammad Al-Gosayir, Moayad Al-Nammi, Waleed Awadh, Abdullah Al-Bar, and Nasser Nasser, Saudi Aramco, prepared for the 2014 SPE Intelligent Energy Conference and Exhibition, Utrecht, the Netherlands, 1-3 April. The paper has not been peer reviewed.

Every day, reservoir and production engineers are presented with massive streams of real-time data from all kinds of intelligent-field equipment. The existing systems for data cleansing and summary are based on batch processing; hence, engineers find it challenging to make the right decision on time and do not have the capacity to instantly detect interesting patterns as data arrive in streams. This paper addresses the architecture, implementation, and benefits of complex-event processing (CEP) as a solution for the intelligent field.

Introduction

CEP is an innovative, rising technology designed to handle large amounts of data with minimal latency in real time. This technology can aid in the detection of trends and anomalies in the data stream such as unusual buildup or drawdown in well pressure in real time. Furthermore, CEP is an event-driven solution, meaning that it is triggered by events such as changes in downhole pressure in order to perform computational logic to calculate average reservoir pressure. This process will in turn provide reservoir and production engineers with clean real- time data and notifications of prominent events.

Overview of Intelligent-Field Structure. For the implementation of the intelligent field, Saudi Aramco has adopted a four-layered architecture. These layers are surveillance, integration, optimization, and innovation, as shown in Fig. 1. The surveillance layer is responsible for continuous monitoring of real-time production data and makes use of data-management tools to ensure the validity of the data. The integration layer processes real-time data to detect trends and anomalies. These anomalies are referred to reservoir engineers for analysis and resolution. The optimization layer streamlines field-optimization capabilities and management recommendations. The innovation layer stores event knowledge and triggers optimization processes and actions throughout the field’s life cycle. This final layer captures “intelligence” and injects it into the system.

Real-time data traverse multiple zones of instrumentation, networks, and data servers before they reach the corporate database and the engineer’s desktop (Fig. 2). A typical piece of data captured by a sensor will be transmitted automatically from the sensor and will pass through multiple data servers connected through wired/wireless networks. The data eventually reside in the corporate database.
Technology Focus: Well Construction (May 2014)
Authors: Carpenter Bob
Published: February 2015

Technology Focus

Many good well-construction-technology papers came out last year, as well as a couple on older technologies that either had not been published earlier or had been released and were underappreciated. Two papers on cement technologies offer improved, relatively easy cementing success. The paper on the new, larger-diameter, high-pressure/ high-temperature (HP/HT) casing valve offers new capabilities for reducing risk in some managed-pressure-drilling applications.

Stinger or Tailpipe Placement of Cement Plugs. Everyone knows how to balance a cement plug, right? Well, if you are using the same approach to balance plugs with a stinger as that used without a stinger, this paper does an excellent job of demonstrating why you are performing your stinger applications incorrectly. While this technology has been available in a couple of forms for several years, I think it is still underused. This paper does a very good job of illustrating and explaining in simple terms how we may be contaminating 40% or so of our cement plug from unintended overdisplacement.

Newtonian Fluids in Cementing Operations in Deepwater Wells. The first field applications of this technology were as early as 2000, but this is its first publication. This technology is simple and relatively easy to apply and is most beneficial in wells where one is trying to gain increased cement coverage farther up the annulus when fighting a narrow pore-/fracture-pressure window. Improved mud-displacement efficiency can be an ancillary benefit. The authors have done a good job of detailing some of the more recent deepwater Gulf of Mexico case histories.

New Casing Valve in a Deep-Well Sour Environment. In HP/HT managed-pressure drilling, many bottomhole-assembly (BHA) components are too large to be tripped through the rotating head. Opening the rotating head to pull large BHA components requires a delicate fluid balance between losing and gaining while completely out of the hole, a high-risk operation. The equipment and techniques described in this detailed case history could add a significant safety barrier for similar HP/HT managed-pressure operations.

Thanks to John Lofton, Chevron senior drilling advisor, for his help with selection of these papers. JPT

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

SPE/IADC 168056 Experimental Assessment of Casing Expansion as a Solution to Microannular Gas Migration by Darko Kupresan, Louisiana State University, et al.

SPE/IADC 167956 Constructing Difficult Colony Wash Lateral With Innovative Rolling-Cutter Technology Improves Drilling Performance by Greg Bruton, Chesapeake Energy, et al.
Technology Focus: Well Stimulation (June 2010)
Authors: Coulter Gerald
Published: February 2015

Technology Focus

Reviewing the numerous papers for this feature showed that the primary theme worldwide, throughout the last approximately 18 months, has been acidizing carbonate formations. Fine tuning this information, it is further seen that the primary interest was zone isolation or diversion. Fracture acidizing seems to be on everyone’s mind as well. Certainly, acidizing sandstones is an important area, but only approximately 15% of the papers were related to sandstone acidizing; thus, with limited space, the emphasis here is on carbonates.

Too often, when multiple zones are to be acidized, mechanical isolation is not feasible and chemicals and/or particulate materials are used for diversion. Post-treatment production logging and results often indicate inadequate stimulation of the target zones. When matrix acidizing carbonates, there are many treatment options from which to choose. Choices relate to amount and type of acid per unit of zone, injection rates, heating the acid (cool dolomites), fluid-loss-control materials, diverting materials, as well as the many other additives including friction reducers, corrosion inhibitors, surfactants, iron control, and on and on. Many of the additives are necessary, but of utmost importance is getting the proper amount of acid into each zone.

A primary issue with fracture acidizing is obtaining conductivity and length, with the decision being which is more important, conductivity or length. In most cases, it is not possible to have both (i.e., long conductive length), particularly in high-temperature situations. In a low-permeability situation, length becomes more important than conductivity, and the requirements may be met more easily with an inert fluid and proppant. In a high-permeability situation, conductivity becomes more important than length, more easily met with acid. Production-increase predictions can help sort out the required balance between length and conductivity.

The following summaries provide insight into acidizing carbonates.

Well Stimulation additional reading available at OnePetro: www.onepetro.org

IPTC 13203 • “Case Study of Successful Matrix Stimulation of High-Water-Cut Wells in Dubai Offshore Fields” by F. Shnaib, SPE, Dubai Petroleum, et al.

SPE 128043 • “Stimulation of Multilayered High-Carbonate-Content Sandstone Formations in West Africa Using Chelant-Based Fluids and Mechanical Diversion” by M. Parkinson, SPE, Chevron, et al.

SPE 127768 • “Acid/Scale-Inhibitor Stimulation Treatment for High-Temperature Cased-Hole Frac-Pack Subsea Wells: Fluid Qualification and Formation-Damage Assessment” by M. Marquez, Chevron, et al.
Successful Implementation of a Gas-Injection Trial in a Low-Permeability Carbonate Reservoir Offshore Qatar
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 13327, ’Successful Implementation of a Gas-Injection Trial in a Low-Permeability Carbonate Reservoir Offshore Qatar,’ by Kristian Mogensen, SPE, and Soren Frank, SPE, Maersk Oil Qatar, and Rashed Noman, SPE, Qatar Petroleum, prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December.

The planning and implementation of a lean-gas-injection trial conducted in the low-permeability Kharaib B carbon-ate reservoir of the Al Shaheen field, offshore Qatar, is described. The main objectives of the trial were to determine whether premature gas breakthrough would occur in the neighboring production wells and whether water injectivity after the gasflood would be reduced as a result of the presence of high gas saturation around the injection well.  

Introduction

The Al Shaheen field began production in 1992 from two thin separate Cretaceous carbonate formations and an overlying sandstone formation. Field development used horizontal wells, some placed in radial patterns and others in parallel line-drive patterns of alternating water injectors and oil producers.

These carbonate reservoirs are relatively thin oil columns with a large areal extent (25×45 km) with permeabilities in the 1- to 10-md range. The reservoir-fluid properties exhibit large lateral variations, with oil gravities ranging from 16 to 38°API within the same reservoir. The field contains several gas caps and shows large variations in solution gas/oil ratio (GOR) and in saturation pressures.

Development studies focus on expanding of the current waterflood and on enhanced oil recovery (EOR). A promising EOR process is water-alternating-gas (WAG) injection that uses either CO2 or hydrocarbon gas as the injectant. A coordinated effort was initiated in 2006 to evaluate the scope for incremental field oil recovery.

An important part of the EOR evaluation was to conduct an early gas-injection trial for a period of 6 months in the Kharaib B reservoir. The purposes of the trial were to investigate whether unexpected large-scale permeability heterogeneities exist in the reservoir, to gather gas- and water-injectivity data, and to gain experience for planning potential WAG-injection applications for the whole field.

Planning Phase

The most important part of the preparatory phase was to select the correct injection well for the trial to ensure that the trial objectives could be met. Once selected, the required modifications to the surface facilities then could be scheduled and a data-gathering program set up.
R&D on Campus: Evolving Operations Drive New Technologies
Authors: Braswell Gentry
Published: February 2015

Editor’s note: JPT surveyed major universities around the world regarding their key upstream research and development projects and activities. The second installment of this series will be published in the July issue.

The signposts ahead show that applied, improved technologies such as enhanced oil recovery (EOR), nanotechnology and state-of-the-art reservoir treatment, monitoring and modeling, and unconventional extraction will define the future of the oil and gas industry. As the demand and need for these techniques and technologies increase, research is under way at numerous universities on how to improve recovery factors to meet future world consumption.

Institute of Petroleum Engineering, Heriot-Watt University, UK

Petroleum engineering at Heriot-Watt University comprises eight general areas of expertise: geomechanics and rock physics, hydrates, hydrocarbon recovery mechanisms, production chemistry, reservoir description, reservoir fluids, reservoir geophysics, and uncertainty quantification.

Patrick Corbett, Total professor of petroleum geoengineering, said the reservoir description group is a coming together of joint industry projects at the university. Furthermore, this kind of collaborative, interdisciplinary model is evolving into research networks among multiple universities working on the same project, he said.

Industry collaborators with the institute include Shell, ExxonMobil, BG Group, Weatherford, Wintershall, PetroChina, Schlumberger, BP, Chevron, Conoco Phillips, Hess, Landmark, Maersk Oil, Marathon Oil, Petrobras, Statoil, Total, Anadarko, Saudi Aramco, and Eni.

The reservoir description group specializes in the integration of geology and engineering for improved quantitative reservoir performance characterization. The reservoir geophysics group’s seismic history matching project uses Schlumberger’s Eclipse, Frontsim and Petrel reservoir data software, Roxar RMS process management software, and Malcolm Sambridge’s NA Algorithm, approaching the subject with geological modeling. The group’s Edinburgh Time-Lapse Project develops reservoir analysis tools for quantitative seismic data interpretation.

The main consortium of the production chemistry group is a flow assurance and scale team joint industry project that develops software used to design field scale inhibitor treatments.

The reservoir fluids group collaborates with carbon dioxide injection research in partnership with the European Carbon Dioxide Thematic Network, the European Network of Excellence on Geological Storage of Carbon Dioxide, the UK Carbon Capture and Storage Edinburgh Consortium, and the Scottish Centre for Carbon Storage. The uncertainty quantification group is in its third phase, addressing problems of uncertainty and error modeling in production. The geomechanics and rock physics group developed the true triaxial Smart Cell for measurement of stress-sensitive petrophysical and rock property data, and created the spinout company PetroMagnetics.
Technology Focus: Coiled Tubing Applications (June 2011)
Authors: Misselbrook John
Published: February 2015

Technology Focus

The overwhelming focus on “shale plays” in North America has spurred many innovative developments in well design and in completion techniques. The increasing drive toward ever greater reservoir contact in these tight formations has changed the landscape, not only for drilling contractors and fracturing companies but also for the coiled-tubing (CT) industry because today, to achieve increased lateral reach and as a direct result of North American activity, more than 50% of all CT supplied globally has a diameter of 2 in.

The drive toward large CT and correspondingly larger and heavier CT units and reels has totally eclipsed the smaller 11/4- and 11/2-in. units, of which a significant number are sitting underused in various companies’ operating districts across North America.

There remains, however, a moderately healthy demand in many other locations for smaller, more-economical CT packages. Therefore, two of the papers I have selected for this feature describe innovative intervention solutions that use “smaller” CT, from two geographically diverse locations.

The third paper introduces a new material development, which, while originally aimed at ultradeep applications and larger sizes of CT, might actually have the potential to enable improved opportunities for the smaller CT packages. CT practitioners generally are an innovative group and I will be interested to see how they exploit whatever opportunities arise from this development.

Coiled Tubing Applications additional reading available at OnePetro: www.onepetro.org

SPE 143261 • “Unconventional P&A Intervention With Coiled Tubing Below a School Building: Comodoro Rivadavia, South Argentina, Case History” by H. Graterol, SPE, YPF, et al.

SPE 142769 • “New Hybrid System Brings the Flexibility of Coiled Tubing to Long, Extended-Reach Wells” by F. McNeil, SPE, Halliburton, et al.

SPE 143371 • “Spoolable Coiled-Tubing Spears: Recovering Subsea Wells After Emergency Shutdowns” by C. Guidry, SPE, Baker Hughes, et al.
Technology Focus: Well Stimulation (June 2011)
Authors: Coulter Gerald
Published: February 2015

Technology Focus

Reviewing technical papers from recent SPE meetings around the world, it is apparent that many innovative and creative approaches are being employed to enhance production or injection. Many previously hydraulically fractured formations—carbonates, sands, and shales—are candidates for refracturing, as discussed in the first highlighted paper. Refracturing can be applicable with all reservoir-access methods (i.e., vertical, horizontal, multilateral, and deviated wells). Of utmost importance is the initial completion. Too often, wells are completed initially for expediency, cost reduction, and related factors without planning for “life-of-the-well” scenarios. Experience shows refracturing to be very economical if the correct candidate is chosen and the existing completion allows for proper restimulation. History shows that those wells responding favorably to the first hydraulic-fracturing treatment have the best chance for a successful refracturing treatment.

It is common to think of nonproppant well stimulation as some application of acid. However, we know that there are many well production or injection problems for which acids are not the answer. Near-wellbore nonacid techniques used to overcome these problems seem to have become more popular recently. Examples include gas generators/propellants, acoustics, and other methods to provide energy waves that disrupt and/or remove near-wellbore restrictions. Additionally, improved perforating techniques and nanotechnology are examples of nonacid approaches to assist with near-wellbore issues. Many of these nonacid approaches may be beneficial when paraffin, asphaltenes, inorganic scales, water blocks, and other problems restrict production. This is not to imply that acids cannot be successful in overcoming near-wellbore issues; but when acids are used, they should be used for an identified, specific, near-wellbore problem.

Well Stimulation additional reading available at OnePetro: www.onepetro.org

SPE 138726 • “Successful Well-Stimulation Projects Boost Production From Iraq’s South Oil Fields” by Loayd Al-Hashmi, SPE, Weatherford, et al.

SPE 138357 • “Acid-Stimulation Results of Arab Carbonate Reservoirs in Offshore Field, UAE: 10 Years of Review; How To Prepare for the Future Challenges Linked to Stimulation” by Ahmed F. Shokry, Abu Dhabi Marine Operating Company, et al.

SPE 131551 • “A Successful Application of Near-Wellbore Stimulation Using Fluidic-Oscillation Technique in North Africa Oil Field” by Kritsana Kritsanaphak, SPE, Halliburton, et al.
A Tricky Tradeoff - Can Adding a Little Solvent Yield a Lot More Heavy Crude?
Authors: Rassenfoss Stephen
Published: February 2015

Years of small-scale testing have shown that adding a small amount of a light hydrocarbon to steam can yield large gains in heavy-oil output and reduce emissions; but, no one has proven it can be done on the large scale common in the Canadian oil sands.

That could change soon. Two innovative Canadian operators—Imperial Oil and Cenovus Energy—are working on commercial steam-injection installations.

They have spent more than a decade developing and testing ways to add solvents such as butane to steam to increase production and ultimate recoveries. If it works on a large scale, it will allow heavy-oil producers to use significantly less steam per barrel to coax out thick crude.

Lowering the steam/oil ratio (SOR)—which represents the barrels of water used to produce an added barrel of oil—could offer a profitable path to reduced emissions.

“If you can improve the thermal efficiency—the steam/oil ratio—emissions go down. Also, costs go down,” said Ian Gates, an associate professor at the University of Calgary, whose research includes solvents. “It all goes in the same direction. You make more money with lower greenhouse emissions.”

Based on laboratory work and field tests, the combination of heat and solvents can increase production—30% or more is often cited—though some have done better and some worse.

Cenovus’ pilot program, which was run at two locations, showed it could reduce its steam/oil ratio by 25%, said Subodh Gupta, chief of technology development for the company spun off by Encana. He also said the greater efficiency could allow wide well spacing.

Imperial said it sees a significant increase in the amount of oil it will ultimately be able to produce. The operator, which improved its estimated recoveries from 20% to 40% at its Cold Lake field by improved reservoir analysis, steam injection, and drilling techniques, said that solvent use plus continued improvements in those three areas “have the potential to increase recovery to more than 60%.”

Despite the potential, many working on the technology express concerns about the cost of the solvent required. “There is no doubt it works, but solvent is quite expensive,” said Neil Edmunds, vice president for enhanced oil recovery at Laricina Energy, who has long been involved in solvent research and simulation work. For companies considering the idea, he said, the cost of the solvent can be “sobering.”
Deja vu All Over Again?
Authors: Hill A. Daniel , Holditch Stephen A.
Published: February 2015

Guest editorial

For many years, professor Lloyd Heinze of the Texas Tech University Petroleum Engineering Department has been collecting US petroleum engineering enrollment data from all of the department heads in the country. These data have always been enlightening, but the current trends are more than enlightening, they are cause for concern. Fueled by the strong demand for petroleum engineering graduates at all degree levels for the past several years, petroleum engineering enrollment in the US, particularly at the undergraduate level, is increasing in a manner similar to the period between 1976 and 1982.

The enrollment data in Fig. 1 is alarming, and each university needs to understand the industry situation to determine its proper course of action. In our opinion, engineering departments cannot continue increasing enrollment at the current rate or they most likely will experience a sudden decline, as they did in the mid-1980s. At some point in the near future, enrollment needs to level off and grow at a much lower rate, if at all.

Those of us who have been in the business since the 1970s remember the enrollment “mountain” shown in Fig. 1 that peaked in 1984. For those of us in academia, the most significant part of this mountain was the incredibly fast rate at which enrollment declined, causing considerable stress in all departments and the closures of some departments. For petroleum engineering students graduating in those years, the implications were dire, for there were no jobs in the industry for a large number of them.

A closer examination of the past few years helps to understand where the growth is occurring. Fig. 2 shows bachelor of science degree enrollments in petroleum engineering departments in the US. Of particular interest is the change that has occurred in just the past year.
Use of TEG-MeOH To Control Wellbore Hydrate Formation
Authors: Sheeran Kenneth , Murray Michael V.
Published: February 2015

Technology Update

The Southwest Kinsale (SWK) reservoir is part of the Kinsale Head reservoir in the Celtic Sea offshore Ireland. SWK was completed with three subsea wells tied back to the Kinsale Head platforms in 1999 (Well 3) and 2001 (Well 4 and Well 5). After initial depletion, SWK was con-verted to gas storage in 2001–02 and has been operated by PSE Kinsale Energy each year since. The storage is seasonal with injection in May to September and withdrawal principally from December to March. The nominal capacity is 8 Bcf with a maximum flow rate of approximately 95 MMscf/D.

Background of the Problem

The operation has experienced gas hydrate formation during the latter part of each withdrawal season since 2006. In 2011, the company decided to expand its storage business. Hydrate formation was identified as the key technical risk to that expansion. While the company has an excellent record of meeting withdrawal nominations, isolated incidences of hydrate formation have proved challenging. In March 2011, the company set up a structured program to understand and resolve the problem.

The majority of the withdrawal uses “free flow,” i.e., reservoir pressure, to generate gas flow over the 7-km distance to the Bravo platform, which has a choke and flowmeter, and thereafter, the 5-km distance to the Alpha platform, where the withdrawn gas is processed by separation and triethylene glycol (TEG) dehydration. From there, the gas travels another 50 km to the shore terminal. The flow can be boosted during peak demand in the latter part of withdrawal by a boost compressor upstream of the TEG dehydration. Production gas from other reservoirs commingles upstream of the TEG process.

There is neither downhole pressure nor temperature indication in the wells, nor is there a downhole chemical dosing point. On each Christmas tree between the master and wing valves, there is a chemical injection point (fed by two umbilical cores), a pressure sensor, and a temperature sensor. The hydrate inhibitor historically used was methanol (MeOH). No corrosion inhibitor is injected. The wells are in 90 m of water and completed at approximately 900 m total vertical depth below mean sea level. The reservoir temperature is approximately 27°C. Wells 4 and 5 are deviated while Well 3 is vertical.
Treatment Enables High-TDS Water Use as Base Fluid for Hydraulic Fracturing
Authors: Lord Paul D. , LeBas Renee
Published: February 2015

Technology Update

The beneficial use of produced water is receiving great attention in the oil and gas industry. As oil and gas are produced, large quantities of water containing high amounts of total dissolved solids (TDS) are produced in the process. Most of the high-saline produced water is reinjected into disposal wells. Reclaiming produced water as the base fluid for hydraulic fracturing not only helps to alleviate the industry’s dependence on fresh water, but also lowers the overall cost of the fracturing treatment.

Contents of Produced Water

Produced water usually comprises the formation water and the injected fluids from previous treatments. It can contain hydrocarbons, high levels of TDS, suspended solids, and residual production chemicals. The use of produced water for hydraulic fracturing has many advantages, such as reduction in disposal of produced water, reduction of freshwater consumption during completion and production operations, and realization of economic benefits by the operator. If produced water is gathered at or near the production site and a minimal treatment is applied in hydraulic fracturing fluids, recycling and reuse programs may become economically and environmentally beneficial.

As hydraulic fracturing in shale plays continues to require large amounts of fresh water for oilfield operations (i.e., 4 to 6 million gallons per well in some cases), reusing produced water reduces freshwater consumption. With increased restrictions on water availability from subsurface or surface sources, fresh water is becoming more difficult to obtain.

In some basins, the use of produced water in oil and gas drilling and slick-water-based fracturing treatments has been explored. Typically, these applications use water with low TDS levels. Little work has been done on the use of produced water with high TDS levels (>200,000  ppm) in fracturing fluids designed with linear or crosslinked gel bases.

Treating High-TDS Water

To reuse high-TDS produced water effectively in crosslinked gel-based hydraulic fracturing fluids, the water must first be treated. The treatment need not generate potable or fresh water, as some oil and gas industry water treatments do. The goal of the treatment is to remove only minerals that hinder the development of the crosslinked fluid or that cause scale buildup in the well. One effective form of produced water treatment is electrocoagulation (EC).
Huge Saudi Field Begins Production Ahead of Schedule
Authors: Henni Abdelghani
Published: February 2015

Manifa

Saudi Aramco started production in April at its Manifa field, the fifth-largest oil field in the world, 3 months ahead of schedule. The field’s output reached 500,000 BOPD of crude from a network of wells drilled through manmade islands.

By the time it is fully operational in December 2014, the offshore field is forecast to produce 900,000 BOPD of Arabian Heavy crude oil, 90 MMscf/D of sour gas, and 65,000 B/D of hydrocarbon condensate. 

Manifa is one of the largest engineering projects in the world, involving 41 km of causeways, 3 km of bridges, 27 drilling islands, 13 offshore platforms, 15 onshore drillsites, water supply wells, injection facilities, multiple pipelines, and a 420 MW heat and electricity plant, not to mention the relocation of an entire coral reef.

After the Khurais project, the USD 9.28 billion Manifa field development is the second-largest project being developed by Saudi Aramco, as part of its effort to boost its production capacity to 12.5 million BOPD by 2015.

Discovered in 1957, Manifa is located in the shallow waters southeast of the Safaniyah field, about 200 km north-west of Dhahran, with estimated proven reserves of 10 billion bbl. The field has six oil-bearing reservoirs: Upper Ratawi, Lower Ratawi, Manifa, Arab A, Arab B, and Arab C/D. The reservoirs for incremental development are the two most prolific: the Lower Ratawi and Manifa reservoirs. Production from the field dates back to 1964 following the drilling of eight development wells. However, the facilities were mothballed in 1985 because of the heaviness of the crude.

Early Start

Planning for the Manifa project began in 2006 when global oil demand was soaring, and the front-end engineering and design (FEED) was completed in the third quarter of 2007. The FEED and project management services contract was awarded to Foster Wheeler in November 2006. Foster Wheeler’s remit was the FEED for the central processing facility, detail design, ordering of long lead equipment, coordination of the FEED development across the project including the offshore sections and development of the bid package for the engineering, procurement, and construction stage.

The first construction contract was signed in late 2007 and construction was scheduled to begin in the first quarter of 2008. The project, however, was consistently delayed with construction beginning in the first quarter of 2010.
Extending North Sea Asset Operating Life With Large-Diameter Velocity Strings
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163905, ’Extending the Operating Life of Mature North Sea Assets With Big-Scale Offshore Installation of Large-Diameter Chrome-Coiled-Tubing Velocity Strings,’ by R.M. de Jonge, SPE, D. Ambergen, and U.A. Tousis, SPE, Baker Hughes, and K. Veeken, SPE, L. Hoekstra, and S. Gesterkamp, NAM, prepared for the 2013 SPE/ICoTA Coiled Tubing & Well Intervention Conference & Exhibition, The Woodlands, Texas, 26-27 March. The paper has not been peer reviewed.

In the southern North Sea, many fields Suffer from declining gas production because of reservoir-pressure depletion and associated liquid loading. At some time during the operating life of offshore production facilities, the ability for these facilities to operate economically with further decline in gas production will need to be evaluated. To avoid early abandonment of these offshore assets, well-dewatering or liquid-unloading techniques, such as velocity-string (VS) installations, are considered for extending the operating life of these mature fields.

Introduction

As more fields in the southern North Sea begin to mature, it becomes important to keep the wells producing economically for as long as possible. In the case of depleting gas wells, this life extension involves preventing liquid loading in the wellbore.

In most gas reservoirs, the reservoir pressure will become insufficient to lift the water or condensate to the surface. As a result, the liquids accumulate in the wellbore and first will choke production then, later, will kill the well. This gas-well liquid loading occurs when the velocity of the gas up the wellbore becomes insufficient to drag the associated liquids to surface. Although many methods of liquid removal are available, only intermittent production, continuous injection of foam, and permanent installation of velocity strings are currently considered suitable for large-scale offshore application.

Because many of these wells produce from small production platforms or normally unmanned installations (NUIs), a self-propelled jackup vessel was used to accommodate the coiled tubing (CT) and associated equipment. The jackup vessel has its own crane, which is large enough to lift the heavy weights, including large-diameter CT reels, onto the deck.

Large-diameter (2⅜- and 2⅞-in.) chrome CT strings are being installed in deep gas wells in the southern North Sea as part of a large-scale installation project, including 20 wells over a 2-year period. The self-propelled jackup work vessel is used to house all the CT, well test, and associated equipment needed to enable well interventions on the small production platforms and NUIs. Critical to success of the project was the cross- discipline approach to preparing, selecting, and testing appropriate CT hardware and tools; performing hazard analyses; and implementing logistical coordination.
Technology Focus: Well Stimulation (June 2013)
Authors: Coulter Gerald R.
Published: February 2015

Technology Focus

This past spring, I had the opportunity to review more than 100 SPE paper abstracts as well as numerous full papers from those abstracts. To SPE’s credit, these abstracts all represent high-quality papers, making it difficult to select those to be highlighted for this feature. The papers chosen for highlighting are those that represent some of the challenges our industry faces and solutions shown to help overcome these challenges. The nonproppant well-stimulation trend continues to be acidizing of the carbonates. What really stands out is the industry emphasis on the continued move to marginal reservoir targets (i.e., poor-quality carbonates as well as sands and shales). For this move to be successful, long-reach horizontal wells are being used. Along with the long reach comes reservoir heterogeneity and the commensurate need for zonal isolation. Or, said another way, the need is to ensure that the entire interval gets the required treatment in these low-quality reservoirs.      

Last year, after a similar review, it was apparent that horizontal wells and proper acid placement were priorities. The subject that seemed to prevail was distributed-temperature-sensing and distributed-acoustic-sensing diagnostics. This year, the published-literature emphasis is on methods and required equipment to achieve better acid placement. The papers chosen to be summarized are excellent resources related to this emphasis.

The first paper, Improved Methods and Workflows for Multizone Stimulation, illustrates tools and workflows that have improved multizone-stimulation effectiveness. The second paper, Optimization of Limited-Entry Matrix Acid Stimulations With Laboratory Testing and Treatment Pressure Matching, is of importance because it discusses the application of acid jetting in long horizontal chalk wells but also addresses pressure drop across perforations. The paper further focuses on the elusive perforation coefficient used by many of us in the design of limited-entry zonal stimulation. And the third paper, A New Strategy To Explore Tight Oil/Gas Reservoirs—Fit-for-Purpose Acid Fracturing, demonstrates the value of a strategy to improve on the success in poor-quality reservoirs. The first additional-reading paper, Successful Application of a Fit-for-Purpose Acid Program in the Tengiz Field, demonstrates application of this approach.

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

SPE 160804 Successful Application of a Fit-for-Purpose Acid Program in the Tengiz Field by K. Ussenbayeva, Chevron, et al.

SPE 162238 Acidizing—Lessons From the Past and New Opportunities by Robert Taylor, Halliburton, et al.

SPE 160762 Successful Application of Foamed-Acid Stimulation of Severely Damaged Perforations in a Horizontal Intelligent Well by W. Ruksanor, Sakhalin Energy Investment Company, et al.

SPE 163384 Unique Process and Tool Provide Better Acid Stimulation and Better Production Results by Mishari Al-Saqabi, Kuwait Oil Company, et al.