Recent Press

SAC & KGOC
December 2009


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Training Growth...SCADA Success

2009 saw the successful commencement of SCADA training for employees across many divisions and this training has been see as one of the key successes for the JO Training Center during the year. The course objections have been achieved with the greatest of success in providing effective support to the field automation project. Reviews have been excellent and as we near the end of this training, it is increasingly apparent that the time spent preparing the course work and delivery method has been successful in ensuring cost optimization for JO.

Oil & Gas Journal
March 2008


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Upgrade expands Visund subsea well communications

Upgrading of communications from subsea wells producing to the Visund platform required a threefold solution that involved retrofitting new communication cards in canisters that attach to existing subsea trees, using existing power lines for communication, and integrating the data topside.

The upgrade improves monitoring of subsea wells so that production from the field’s complex reservoirs can be optimized.

See the 03/18/08 issue of Oil & Gas Journal for the remainder of this article.

SPE Production & Operations
Volume 22 Issue 4

or

Download this paper on the SPE Website SPE Papers section
#99949-MS

Real-Time Field Surveillance and Well Services Management in a Large Mature Onshore Field

This paper describes the evolution of an oilfield automation and software system up to an innovative level of surveillance and work planning. The historical automation level was at that of individual wells. (It is estimated that about 10% of the world’s wells are automated to this degree.) Next, this data was brought to field offices allowing remote surveillance. (Most automated wells have some similar type of data consolidation.) The next step was to feed this data automatically into engineering models, which is comparatively rarely done (other than with much human intervention).

It was to build upon this relatively high level of historical automation and surveillance that the decision was taken to go a step further and introduce a highly innovative software system which not only further developed the remote surveillance concept, but also managed the well services activities so that full well histories would be electronically managed. What was particularly novel was the concept that the workflow processes themselves would be defined in, and managed by, the software. There are few instances of this level of business process automation being applied in the upstream operations and engineering sectors, and the lessons learned are valuable.

See the 11/07 issue of the SPE Production & Operations Volume 22 Issue 4 for the remainder of this article.

American Oil & Gas Reporter
August 2007

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Better Software Improves Well Design

For as long as there have been desktop computers, petroleum engineers have used production system analysis software to help them make better decisions. Now a tremendous technology shift has led the demand for enhanced software capabilities that help operators improve front-end well design for better completions and productivity.

Today’s strides in improved nodal analysis are geared toward two trends. The first is demand from engineers for tools that are easy to use and have broader functionality. The second is the need for easy-to-integrate petroleum engineering software solutions that help promote a more connected workplace. Anticipating both trends, service companies are delivering re-energized products that offer a wide range of capabilities and virtually limitless potential.

See the 08/07 issue of American Oil & Gas Reporter for the remainder of this article.

Oil & Gas Journal
March 2007


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Rod-pump automation increases oil rates in Sumatran field

Resizing pumps, installing rod-pump controllers (RPCs), and monitoring and analyzing wells remotely with software specific for that purpose increased operational efficiency in Balam South field on Sumatra Island, Indonesia.

PT Chevron Pacific Indonesia operates the field. The company's optimization program involved phased installation of state of the art technology. The wells highest on the prioritized list were determined to be more likely to provide the most return for the investment in automation

THe results were better than expected with several wells increasing production by about 200 bo/d. The wells also has lower electrical and repair costs.

See the 03/05/07 issue of Oil & Gas Journal for the remainder of this article.

Petroleum
June 2006

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Evaluation, Diagnostics, and Optimization of the Lagomar Exploitation Unit's Gas Collection and Distribution Network

Currently, the Lagomar Exploitation Unit's gas distribution and collection network is facing a series of operational problems due to changes in the normal behavior of both the pressure and the volume handled by the system, mainly as a result of shutdowns of the gas compression plants supplying the lift gas. Deferred production due to well shut-ins during the contingency and liquids buildup in the tubing constitute an important operational problem that requires a solution in the least possible time in order to minimize the impact whenever any of these scenarios may occur.

This research's objective is to evaluate the behavior of the gas collection and distribution network of flow stations 15-1, 16-1, 1-2, 1-12, 2-12, belonging to the Block I, II and XIII of the Lagomar Exploitation Unit in the Maracaibo District of PDVSA using the commercial application ReO-DGO in order to optimize the gas injected to the gas manifolds of each station and use the remaining gas for export to third parties, and at the same time avoid over-injection on the wells thus achieving hydrocarbons production gains. Likewise, it is expected to detect bottlenecks reducing the gas transfer capacity on the network due to the presence of liquids on the system's lines. The possibility to count on an integrated platform able to dynamically simulate the different scenarios that may show up in the system networks allows us to minimize deferred production in case of contingencies and, in normal conditions, diagnose and optimize lift gas injection to increase wells production and maximize natural gas usage.

See the 06/06 issue of Petroleum for the remainder of this article.

The Manufacturer
April 2006

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It's in the hole

The blunt reality of the oil and gas production business is its cyclical nature, and it takes a certain amount of patience, skill, and capital for a supplier to the industry to get through the rough spots. Of course, the rewards come at the upswing, and then the challenge is to keep up with demand. Offering different services helps too, and Kingwood, TX–based eProduction Solutions (eP) provides optimization products, field services, and consulting services. Its parent company, Weatherford International, is a large global provider of comprehensive artificial-lift, drilling, and completion products and services for the drilling and production sectors of the oil and gas industry. It operates in more than 730 locations in about 100 countries, employing more than 25,000 people.

See the 04/06 issue of The Manufacturer for the remainder of this article.

Harts E&P
April 2005

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2005 Meritorious Awards for Engineering Innovation

Weatherford/eProduction Solutions’ (eP) 2G water-cut meter is installed in a well’s flowline as a part of the Red Eye three-phase metering system. It uses infrared-beam technology to accurately and continually measure the oil/water fraction in produced fluid, providing the operator with valuable real-time readouts.

According to Weatherford/eP, the Red Eye meter is the only system that uses a narrow bandwidth infrared beam to provide a highly accurate water fraction in an oil and water mix. It is based on the principle that oil in a multiphase flow regime attenuates a light beam at a different level than does water. The light is absorbed by the oil, whereas gas and water appear transparent. The 2G system is differentiated in that it is the only system that simultaneously measures multiple infrared wavelengths to monitor water- and oil absorbent peaks in addition to nullifying scattering effects. The 2G meter ignores salinity changes and is insensitive to free gas.

See the 04/05 issue of Harts E&P for the remainder of this article.

World Oil
May 2005

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What's New In Artificial Lift

Part 2 - Fourteen new downhole/surface system developments from 10 companies for electrical submersible pumping and other artificial lift operations.

This concluding article introduces 14 new developments from 10 companies. Eight of the presentations include new downhole and surface equipment for ESP systems. The remaining six items cover miscellaneous contributions for new downhole pumps, operations monitoring/control and soap stick launching.

See the 04/05 issue of World Oil for the remainder of this article.

World Oil
April 2005

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What's New In Artificial Lift

Part 1 - Fifteen new systems for beam, progressing-cavity pumping and plunger lift.

Described here are 15 recent developments in three categories of artificial lift technology, including: beam pumping (seven items); progressing-cavity pumping (PCP) (four); and plunger lift (four). Part 2, coming in the May issue, will present electrical submersible pumping (ESP) and other, miscellaneous, artificial lift-related innovations.

See the 04/05 issue of World Oil for the remainder of this article.

Harts E&P
March 2005

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Pumps Pay Off

Using intelligent pumping systems with innovative design and operating and analysis software, operators are achieving near production optimization from their pumping well fields.

Electrical submersible pumps (ESPs) have been around for decades. For the most part, they quietly do their jobs until they are pulled for routine maintenance, or fail, whichever happens first. Failure can be costly, with repair and replacement costs coupled with workover costs and the cost of lost production during the shutdown period. Even more costly is the ESP that produces sub-optimally for years, decreasing the well’s potential one barrel at a time.

See the 03/05 issue of Harts E&P for the remainder of this article.

NOVA
December 2004

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eProduction Solutions We Create Solutions for the Oil Industry

Thony Brito, eProduction Solutions' Latin America Comptroller, explains in this interview how the company offers better optimization for reservoirs and oil equipment, as well as a total commitment toward client's satisfaction.

The objectives of eProduction Solutions (eP) are to optimize oil reservoir production, protect the equipment, and make the client's business more profitable. eP, a Weatherford company and has a presence in the North America, Latin America, the North Sea, and the Middle East.

See the 12/04 issue of the local Venezuelan magazine NOVA for the remainder of this article.

PipeLine
July 2004

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Benefits of Detailed Compressor Modeling in Optimizing Production from Gas-Lifted Fields

Gas-lift is one of the major artificial lift methods employed for oil production. In implementations where there is no external source of high pressure lift-gas (eg, a gas field nearby), compressors are used to provide the lift-gas supply by recycling the low pressure associated gas produced with the oil. Figure1. shows a schematic of a typical gas-lifted production system. Lift-gas leaving the discharge side of the compressors travels through a distribution network to the individual wells, and returns to the production separators along with the fluids (oil, gas and water) produced from the reservoir. The gas is separated from the liquids, and passes to the compressors and from there back to the wells.

See the 07/04 issue of Pipeline Magazine for the remainder of this article.

PipeLine
December 2003

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Revolutionary water cut meter optimizes transmission

US-headquartered eProduction Solutions (eP) Provides and inexpensive water cut meter that actually increases its accuracy as the water cut approaches per cent. The Red Eye Water Cut Meter uses technology involving infrared light to determine the precise percentage of water to oil, especially at extremely high water cut levels.

See the 07/04 issue of Pipeline Magazine for the remainder of this article.

World Oil
August 2003

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Integrated rod-pump controller cuts operating costs

Phoenix Hydrocarbons Operating Co. agreed co beta-test the new iBEAM rod pump controller (RPC) on one of its low-productivity wells in Esperson Dome field near Dayton, Texas. The field has 120 rod-pumped wells that lift fluids from depths of 2,000 to 4,000 ft. Sixty of these wells operate on timers, and one is controlled by an iBEAM RPC, Fig. 1. This well produces 6 bopd with 50% water cut. The 2-in. by 1.5-in. by 10-ft THD pump produces 22°API gravity oil from a depth of 2,300 ft.

See the 08/03 issue of World Oil for the remainder of this article.

Oil & Gas Journal
August 2003

Rod pump controller features self-contained design

This new self contained rod pump controller uses advanced load and position technology. Because of it's wireless design, the controller is able to eliminate maintenance cost associated with cables to the load cell and position sensor, the company points out.

Radio technology tat is imbedded is used to control the well and relay operational data to a host-based software system for remote monitoring and detailed analysis. The radio also provides data to a hand held device for operators to use while visiting the well site.

See the 08/03 issue of Oil & Gas Journal for the remainder of this article.

World Energy Source
May 2003

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World Energy Source

eP's President, Dharmesh Mehta took part in World Energy Source's series of exclusive interviews with industry leaders at the OTC Conference 2003 in Houston, TX. The interview lasts approximately six minutes and discusses the important topics relating to the industry today and how eProduction Solutions is reacting to these issues.

See the World Energy Source web site for the interview.

Harts E&P
May 2003

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Well Optimization Extends Life of Reservoir

XTO Energy is a domestic producer with a history of acquiring properties where technology can be used to increase profitability and consequently extend the life of the reservoir. XTO optimizes assets through drilling, workovers, and cost reductions. This article focuses on reducing operating costs using well optimization technology.

Since operating costs are a contributing factor to the cost per barrel of production, minimizing operating costs reduces the production cost per barrel. Production cost per barrel is defined as field overhead expense coupled with costs associated with the operation of the producing wells, including workovers, utilities, repairs, maintenance, chemical treatments, and labor.

See the 05/03 issue of Harts E&P for the remainder of this article.

Offshore
May 2003

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Managing Production from First Oil to Abandonment

Automation of oil and gas offshore facilities can conjure many opinions, from regulatory requirements to requirements for occasionally manned facilities, or from simple pneumatic controls to full electronic distributed control systems interfaced to many subsystems.

Seldom does the selection of the technology phase include looking at the complete business environment on a platform. Many aspects of operating an offshore platform require different systems. Because capital expenditure for a platform can be so high, the driver is only for completing the platform construction at the lowest cost. Many operators do not consider the life cycle of what is required during the front-end engineering design (FEED) stage to manage the asset from first oil to abandonment. This results in dissimilar systems being added over the life of a field.

At a minimum, three basic layers – process control, emergency shutdown systems, and fire and gas protection – are required to provide automation. The management of the reserves in place can be better achieved through advanced automation of the process control system.

See the 05/03 issue of Offshore for the remainder of this article.

World Oil
April 2003

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What's New In Artificial Lift

Part 1 - Fourteen new systems for beam, progressing-cavity, plunger-lift pumping and gas lift.

Described here are 14 recent developments in four categories of artificial lift technology, including: beam pumping (7 items); plunger lift (3); gas-lift (2); and progressing-cavity pumping (PCP) (2). Part 2, coming in the May issue, will present electrical submersible pumping (ESP) and other, miscellaneous, artificial-lift-related innovations.

See the 04/03 issue of World Oil for the remainder of this article.

American Oil & Gas Reporter
August 2002

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Intelligent ESPs Doing More With Less

Throughout each downturn in the oil business, companies have learned to do more with less. Many fields are operating today with fewer employees than they had 10 years ago, even though they now have more wells. The layoffs that occurred during each downturn were not reciprocated by expanded hiring during more profitable times. Consequently, fields are now being operated by a less than optimal numbers of staff.

Many companies have turned to automation systems to overcome the shortcomings of staff, and found that the benefits go beyond replacing personnel. Automation systems for wells on electric submersible pumps have provided many advantages for field operators.

See the 08/02 issue of American Oil & Gas Reporter for the remainder of this article.

World Oil
June 2002 Supplement

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Rod-pump controllers profitable in East Texas operations

Bottom line. Stetson Petroleum Corp. purchased and installed rod-pump controllers, replacing time clocks, in 15 wells in its East Linden (Cotton Valley) field in East Texas. Wells there are about 10,000-ft deep, producing 42 to 46°-API gravity oil, with a 5 to 50% water cut. With contract pumpers, timers and a trial-and-error process for setting timers, Stetson saw upside potential from using rod-pump controllers (RPCs). Based on two years' experience, it found that the controllers reduced rod and tubing failures by 31% and electric costs by 40%, equating to about $50,000 per year savings. RPC equipment costs paid out in less than a year, on average.

See the 06/02 supplement of World Oil for the remainder of this article.

World Oil
May 2002

What's New In Artificial Lift - Part 2

This article introduces 15 new developments from nine companies. Eight of the presentations include new downhole and surface ESP systems. The seven" miscellaneous" items cover contributions for various artificial lift and production operation categories, such as: motor controllers and monitors; automation systems; enhanced oil recovery control; and tubing insulation.

See the 05/02 issue of World Oil for the remainder of this article.

World Oil
April 2002

What's New In Artificial Lift - Part 1

Described here are 14 recent developments in four categories of artificial lift technology, including: beam pumping (8 items); progressing-cavity pumping (PCP) (3); plunger lift (2); and one gas-lift related item. Part 2, coming in the May issue, will present electrical submersible pumping (ESP) and other, miscellaneous, artificial-lift-related innovations.

See the 04/02 issue of World Oil for the remainder of this article.

PetroMin
March 2002

Intelligent equipment and software provide the right answers

eProduction Solutions (eP) offers unique solutions for producing oil and gas fields and offshore platforms. The solutions provide automation and optimization systems for wells,facilities and the field as a whole. By providing intelligent hardware at the well site and intelligent software at the desktop,eP provides production operators, managers, and well analysts the most advanced solutions for monitoring, controlling, analyzing, and designing artificial lift systems as well as monitoring and controlling well test and production facilities.

See the 03/02 issue of PetroMin for the remainder of this article.

PTTC Network News
Vol. 8, No.1
1st Quarter 2002

Rod Pump Controllers Can Now Be Leased

Most independents are aware of the potential benefits from using rod pump controllers, but need affordable options to implement them in mature properties. eProduction Solutions Inc. (eP) recently launched a "Service Plan" in the U.S. that provides rod pump controllers on a lease basis. Leasing avoids initial capital issues, and the plan can provide rod pump controllers for as low as $1.99 per well per day. Price varies according to options and configurations. eP will install and support the controllers. The controllers use state-of-the-art load and position technology like that being used in over 20,000 wells around the world by eP customers.

Journal of Petroleum Technology
December 2001

Technology Applications: Artificial-Lift Drive System

Artificial-lift drives from eProduction Solutions Inc. provide precision control for oil field pumping applications. Digital technology is used to control motor voltage, current, speed, and torque, making the drive responsive to continuously changing downhole conditions. The drive can be configured in the field to operate any type of artificial-lift system.

See the 12/01 issue of JPT for the remainder of this article.