bluuebunny/crossref_metadata_2025_split huggingface dataset:
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 (&gt;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.
Foam-EOR Pilot: Mature Volatile-Oil Reservoir Under Miscible-Gas Injection
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 16984, ’Successful Foam-EOR Pilot in a Mature Volatile-Oil Reservoir Under Miscible-Gas Injection,’ by A. Ocampo, A. Restrepo, SPE, H. Cifuentes, SPE, J. Hester, N. Orozco, C. Gil, and E. Castro, Equion Energia, and S. Lopera and C. Gonzalez, Universidad Nacional de Colombia, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
A successful field trial in which foam was used as a gas- injection conformance enhancer was implemented in the Cusiana field in Colombia. An extensive front-end loading (FEL), including chemical-product screening, studying foam stability at reservoir conditions, coreflood experiments, reservoir modeling, and careful selection of well candidates, was executed for this pilot. The treatment was performed in a gas-injection well in the northern part of the field that had already attained a high recovery factor (RF) with high levels of gas recycling. The operation was performed by use of a surfactant-alternating-gas (SAG) method.
Introduction
The Cusiana field is in the foothills of the Eastern Mountain chain in Colombia, and initial production was in 1994. The field comprises three stacked reservoirs (Mirador, Barco, and Guadalupe) and two fluid systems (both volatile oils) with a rich-gas cap at near-critical conditions (pressures and temperatures greater than 5,000 psia and 250°F, respectively). The initial in-place volumes were 1.5 billion STB of oil and more than 3 Tcf of gas, with the Mirador formation containing approximately 60% of the total fluid. Development strategies have included natural depletion, gas recycling, water injection, and gas-injection redistribution. Gas recycling and redistribution provided the best recoveries.
The Mirador reservoir is a low- porosity quartzarenite with significant heterogeneities in permeability, both vertically and areally. The reservoir was developed with extensive gas reinjection, beginning in the early days of production with the gas-injection wells updip on the structure. This strategy proved beneficial from the very early stages of gas injection with regard to efficient first-contact miscibility and the favorable location of the injectors. The result has been RFs greater than 50% for most of the Mirador units. After approximately 10 years of gas reinjection, high levels of recycling were observed as a result of reservoir heterogeneities and a less-efficient gas-enrichment process because of the decrease in reservoir pressure below the minimum miscibility pressure. Those conditions led to unrecovered oil in areas that are difficult to access, such as the oil rim between the producers and the aquifer, poor-quality rock layers, and bypassed areas between the producers and injectors.
Implementation Challenges: DTS Injection Profiles in the Belridge Field, California
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163694, ’The Challenges of Full-Field Implementation of Fiber-Optic DTS for Monitoring Injection Profiles in Belridge Field, California,’ by Mahmood Rahman, SPE, Daniel A. Reed, and Malcolm E. Allan, SPE, Aera Energy, prepared for the 2013 SPE Digital Energy Conference and Exhibition, The Woodlands, Texas, 5-7 March. The paper has not been peer reviewed.
The Diatomite reservoir in the Belridge field, California, has been under pressure-maintenance water injection to mitigate reservoir compaction and improve oil recovery. Accurate placement of the injection water across this 1,500-ft-thick reservoir is essential to balance voidage and reduce in-situ compaction. However, scale buildup and casing deformation have made monitoring the injection profile by use of conventional radioactive-tracer (RAT) technology a challenge because of the inability to access wellbores for logging. Field tests with fiber-optic (FO) distributed-temperature-sensing (DTS) systems confirmed that the technology had potential to replace the RAT surveys for continuous monitoring of the injection profile. However, moving from a successful pilot to full-field implementation presented many challenges, both technical and economic.
Introduction
Belridge, one of the largest oil fields in California, is approximately 150 miles north of Los Angeles (Fig. 1). There are two major producing horizons: The shallower Tulare sands produce heavy oil (13 to 15°API) by steamdrive, and the deeper Diatomite formation produces light oil (29 to 31°API). In 2012, the Tulare produced an average of 21,000 BOPD and the reservoir produced 41,000 BOPD.
The Diatomite reservoir has very high porosity (50 to 70%), high compressibility (100 to 300×10−6 psi−1), and very low matrix permeability (0.1 to 3.0 md). The upper portion of the Diatomite formation in Belridge has a gross thickness of more than 1,500 ft (Fig. 2), with 21 major depositional cycles grouped into nine conformance units.
Initially, the reservoir was produced on primary recovery by solution-gas drive. Because of the high rock compressibility, pressure-maintenance water injection was started in the late 1980s to combat reservoir compaction. The operator has been investigating methods to evaluate injector effectiveness. One solution was extensive use of openhole wireline formation tests (WFTs) that are run in replacement wells and provide a good indication of vertical-conformance effectiveness. However, WFT pressure profiles indicate only the effectiveness of past injection; they cannot show the current state of injection conformance.
E&P Notes (June 2014)
Authors: Jacobs Trent , Rassenfoss Stephen 
Published: February 2015

E&P Notes
’DuPont Touts MEOR Technology’
DuPont is ramping up the commercial-scale implementation of its microbial enhanced oil recovery (MEOR) method after nearly a decade of development and testing of what it says is a low-risk way to improve production from mature fields. Using its bioanalysis technology, DuPont has isolated microbes able to promote flow conformance through the production of a biofilm that restricts flow by reducing permeability. The company has also identified and isolated microbes that have oil-releasing (or wettability-changing) qualities to reduce residual oil adhering to the rock. Based on successful results both in the lab and in the field, the company says that its MEOR solution can increase production rates by as much as 25% at a cost of USD 10 per incremental barrel. DuPont presented the details of its laboratory tests and discussed the results of field trials at the SPE Improved Oil Recovery Symposium in Tulsa in April.
’Wintershall Sees EOR Promise in New Biopolymer’
After a year of field testing, a new type of biopolymer developed by Wintershall, Germany’s largest oil and gas producer, is showing promise as an effective enhanced oil recovery (EOR) tool in one of the country’s longest producing oil fields. The company presented the first-year results of its pilot project using the biopolymer in a pair of technical papers in April at the recent SPE Improved Oil Recovery Symposium in Tulsa. The biopolymer, Schizophyllan, is named after one of the most widespread fungi found in the forests of Germany. What is novel about Wintershall’s biopolymer is that it can survive inside high-salinity reservoirs with temperatures as high as 275°F. The triple-helix configuration of the molecular structure provides durability and high viscosity. According to the company, these tolerances are unmatched by all other commercially available polymers and will enable polymer flooding in reservoirs previously considered too harsh for such a treatment.
’Two Big Equipment Makers Working on Tougher Fracture Pumping Systems’
Pumping fracturing jobs is an equipment killer. To begin with, the job requires running enormous quantities of water and sand through a pump, which is an abrasive mix that damages pumps in ways that cannot be fixed. Adding to the pressure is the trend toward clustering wells on pad sites to allow larger, non-stop, multi-well jobs that extend run time.