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Thursday, 28 May 2009

RAO/CIS Offshore Conference and Exhibition, Russia, St Petersburg

The 9th RAO/CIS Offshore International Conference and Exhibition devoted to Oil and Gas Resources Development of the Russian Arctic and CIS continental Shelf will be held on September 15 - 18, 2009 in St. Petersburg.

The RAO/CIS Offshore Conference and Exhibition is held every two years and obtains strong position among the world offshore oil and gas exhibitions and conferences. Along with the largest relevant events in Aberdeen, Stavanger, Houston and Baku, RAO/CIS Offshore is considered to be the industry central event of the Russian and international scale. Plenary sessions, round table discussions, the Exhibition and Business Communication Center will be organised within the framework of RAO/CIS Offshore event.

RAO/CIS Offshore will be opened by the Plenary Session at the Congress Hall of Smolniy Cathedral on September 15th. Representatives of the largest oil and gas companies from Russia and abroad, government authorities and well-known scientists will make a speech at the session.

For the four-day RAO/CIS Offshore Business program that will take place at the Grand Hotel Europe will feature round table discussions on the following topics: exploitation and development of North, South and Far East Offshore Fields, Shtokman Gas Condensate Field Development opportunities. The issues of industrial and ecological safety, economy and legal base aspects, opportunities of international and interregional cooperation will be also given consideration.

The Business program will run concurrently with the Exhibition of Offshore Resources Development Projects: drilling equipment, floating and underwater facilities, technologies for offshore oil and gas facilities construction, ice-machines, shipbuilding, ecology safety means organised at Mikhailovskiy Manege.

The RAO/CIS Offshore 2009 event is planned to be participated by over 100 largest offshore oil and gas companies from Russia, Finland, Norway, the UK, France, Germany, China, Japan and other countries.

Producing and service companies, research centers and engineering departments as well as suppliers of equipment for offshore field development have already applied for participation in the Exhibition and Conference: StatoilHydro ASA, ExxonMobil, Total SA, Itochu, Shell, Gazprom, Lukoil, Rosneft, Sevmorneftegas, United Shipbuilding Corporation, State-owned Oil Company of Azerbaijan and others.

The event will be held with the support of Federation Council Committee for Natural Resources and Environmental Protection and the Government of St. Petersburg. The RAO / CIS Offshore Organisers are Ministry for the Natural Resources and ecology of the Russian Federation, Federal Subsoil Resources Management Agency, Gazprom, StatoilHydro ASA, Lukoil, Rosneft, Sevmorneftegas, Research Institute of Natural Gases and Gas Technologies (VNIIGAZ) and RESTEC Exhibition Company.

RAO/CIS Offshore Organizing Committee
Tel./fax: +7 (812) 320 8091, 320 9660
E-mail: [email protected], [email protected]

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posted by The Rogtec Team @ 14:43  0 Comments

Tuesday, 19 May 2009

Aboa Mare University Recieves Dynamic Positioning Accreditation

Aboa Mare University of Applied Sciences, located in Turku (Finland), has recently received the accreditation of the Nautical Institute as an official Dynamic Positioning (DP) training center. Dynamic positioning is becoming especially important for sophisticated offshore operations and the need for corresponding training facilities is increasing rapidly.

The new DP bridge simulator in Turku is based on the Navis NavDP 4000 Trainer Simulator, which combines the best qualities of the previous models. The DP training facility comprises the bridge with 3 visual channels and the DP classroom, where the trainees all have their individual DP station.

This new addition means that Aboa Mare now has no less than seven training bridges, turning it to the largest simulation center in Finland continuing its traditions dating back to 1813.

Navis Engineering Oy
Att. Nikolay Ovcharenko
+7 812 567 3763
[email protected]

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posted by The Rogtec Team @ 10:00  0 Comments

Thursday, 14 May 2009

Stochastic Model of iceberg Drift, Including Wave Effect


In Arctic regions, drifting icebergs represent a very dangerous hazard for navigation, and indeed for offshore structures. To ensure safe operation, an iceberg management plan must be developped; covering iceberg detection to iceberg towing or platform evacuation. One important part of the plan is the iceberg drift forecast. Further to a review of existing drifting models, TOTAL have decided to develop and test a new numerical model that includes wave forces and a stochastic approach.

In previous models, wave effect was often taken into account via a slightly over-estimated wind effect, assuming that waves are only driven by local winds (see Smith [1993] for example). Masson [1991] proposed an hydrodynamic approach to the estimation of wave effect, assimilating the iceberg to a cylinder and computing the transfer function of the object. A similar approach will be generalized here. The new iceberg drift model has been written following the classic rules of drifting problems. The principle is to estimate as best as possible the forces that act on the iceberg, and to compute a trajectory during the course of a few hours using oceanic and meteorological forecasts. The uncertainties on the formulation of these forces are taken into account via a stochastic approach; the model computes areas of probability instead of a single trajectory. The model is validated using a series of drift measurements carried out during the months of June 1983 and 1984 in Canadian waters. This data is used to test the accuracy of the model and to estimate the impact of each parameter on the drift.

In the first section we describe briefly the equations solved by the model and the numerical scheme. Sections 2 is devoted to the validation of the model on the available test cases, and in section 3, we present the stochastic approach that is implemented in the code.

Model Formulation


The aim of the model is to predict the drift of an iceberg, knowing an estimation of its shape and mass and using environemental factors.

The drift is a result of:

  • Current drag force (Fc)

  • Wind drag force (Fw)

  • Wave Force (Fwav)

  • Inertia and Coriolis forces (Fm)

The model numerically solves the movement equation (eq. (1)) to compute the location of the iceberg.



dt2 = Fc+ Fw + Fwav + Fm (1)

where m stands for the mass of the iceberg, ma for the added mass, and X for its position. ma is usually taken to be half of m. All the terms in this equation are two-dimensional vectors. We use a fourth-order RungeKutta scheme with adaptative time-step to integrate the equation in time.

Another equation could have been included in the system to compute the yaw of the object. Such a calculation requires having a good knowledge of the shape of the object to be accurate. Furthermore, the formulation of the problem can be very complex, because without using a damping term, we obtain a permanent rotation of the iceberg which is not realistic. And since the choice of the damping coefficient is often arbitrary, it incorporates another source of uncertainty in the model. So we consider that given the lack of details on the precise shape of the iceberg and the number of uncertainties that already exist, it is not significant to include the yaw motion of the iceberg in the calculation at this stage of development.

Drag forces

The classical formulation of drag forces is used: for the wind drag force, in projection on the x and y directions, the expression is simply:

where uw is the wind speed and _w is the wind incidence angle. For the current drag force, the code does not use a single value of current, but vertical profiles. So we have to sum the contribution of each layer to obtain the resulting effort:

where n is the number of layers and uc(k) the current speed at the kth layer. Given the fact that yaw motion is not taken into account in the calculation, the surfaces Sw and Sc must represent a "mean surface" exposed to wind and currents. The drag coeffi

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posted by The Rogtec Team @ 15:55  0 Comments

Thursday, 7 May 2009

The Digitial Oilfield, Continuous Seismic Surveillance and Intelligent Wells

Just around the corner is a new technology which, dependent on who we are listening to, is "The Field of the Future", "The Digital Oil Field", "e-Field" etc. Now one aspect of this vision is that one day in the future we might for example be able to run a field like Samotlor or Rospan from Tyumen, or even Moscow, without exposing workers to Health and Safety risks, and at significantly lower cost. The aspect I want to consider here is the potential avalanche of digital information that can be foreseen and how companies might prepare for it.

Consider a couple of key Digital Oil Field concepts, namely Continuous Seismic Surveillance and Intelligent Wells.

Continuous Seismic Surveillance extends 4D methodology (see below). Offshore, permanent sensors (with up to 4components: X, Y, Z + pressure) are installed in the sea-bed above any oil or gas field in a one-time installation before production starts (ideally at the same time sub-sea production equipment is installed). Then a relatively inexpensive seismic source vessel can sail above these sensors "whenever required" and generate a "repeat 3D". In theory, this could happen as often as once a week at a repeat cost of as little as $100k, giving real-time data for analysis of reservoir dynamics throughout a field's life. Onshore, a similar approach can be envisaged although permanently installed down-hole sensors are perhaps more likely.

Intelligent Wells implies wells that are equipped at completion with down-hole controls and sensors. There can then be a continuous flow of data from these wells regarding pressure performance, inflow distribution, the flowing phase, reservoir saturation and from down-hole geophysical measurements (e.g. seismic and electro-magnetic) and proactive remediation of fluid inflow into the well-bore via remote controlled down-hole zonal control valves and the ability to implement reservoir management without intervention.

What is clear is that the Majors, in partnership with the bigger contractors, have been working on ideas such as these for several years, believing that the leaders will find competitive advantage in their ability to, for example:

  • shape production profiles, with individual wells starting-up faster, and field-wide optimisation
  • identify unexploited reserves, improving recovery factors
  • cut costs, both Capex (less wells) and operating
  • remove staff from unsafe environments

For a nice summary of the concepts, the progress that has been made, and a couple of Field case studies, I recommend a paper by Judson Jacobs which can be found on the IHS web-site at under the April 2007, London Symposium heading. It's clear that sensible digital solutions are being invented, tested and implemented. However, to my mind, the most profound point made in this paper is that whilst many individual Digital Oil Field technologies have seen widespread adoption ranging from "Intelligent Completions to 4D Seismic to Real-time Drilling" optimized, collaborative, integrated Operations remain at the proof of concept stage or have only just been shown to be technically and economically feasible.

Apart from the obvious possibility that the number of digits of data that can now be acquired is running way ahead of our ability to assimilate and integrate them, what else might underpin the apparent difficulty in progressing collaboration and integration? At the risk of opening a Grand Canyon divide between some of the petrotechnical disciplines, I'd offer the following thoughts:

By and large, the subsurface disciplines "geologists, geophysicists, petrophysicists, reservoir engineers" have already confronted the digital revolution, and are comfortable with it, not least because of the aforementioned problems set and opportunities offered by the tidal wave of data resulting from 3D and 4D seismic surveys (see below).

In contrast, by and large, the petroleum and production engineering disciplines (and commercial folk too) live in a world of Excel spreadsheets, PowerPoint and SCADA data flows, and those who tend the key (upward) information flows within many organizations seem to regard MicroSoft Office as the leading edge of the digital revolution.

The critical point seems to be that organizations - and related processes, workflows, standards and procurement practices - need re-shaping to support integration and "digital oil field" projects. Acting locally in this way seems to be far more significant than the global pursuit of initiatives such as POSC or PPDM. For a good summary of these ideas, I'd recommend my colleague Alan Smith's paper "How to succeed with your KIDS!" which can be found here:

Actually data overload is not new and there are plenty of examples of our ability to collect sub-surface and engineering information running way ahead of our ability to analyse and interpret this data or put differently, we have struggled in the past to turn the massive amounts of data we have into information and thence into knowledge.

A couple of related fragments of geophysical history will help illustrate what I mean.

First of all, let those of us who can cast our minds back to the mid 1980's when, to give them due credit - led by Shell, 3D seismic began to appear on the scene. During this time, I began to be involved in North Sea operations and I can remember walking into 'team rooms' and being confronted with mounds of paper from the very latest technology, a field's new 3D survey. There was so much paper and so little means of dealing with it that to achieve speed of delivery (i.e. to obtain some insight before the field in question came off plateau!), interpretations were commonly based on "every 10th line" - somewhat defeating the objective. This was obviously commonplace around the industry and various semi-exotic analogue interpretation systems appeared. However, the digital seismic interpretation system became the obvious target and to begin with the bigger oil companies attempted to build their own: Standard Oil (Sohio; eventually acquired by BP in 1987) had their SEIS system for example, BP continued with SIIS and Chevron had their own system and so on. Meanwhile some digital entrepreneurs were starting off a couple of companies called Geoquest and Landmark and eventually most, eventually all, of the Majors had the sense to buy rather than build.

The upshot of all this was that by the early 1990's, digital interpretations using all the 3D seismic data were the norm and reasonably accurate static 3D reservoir descriptions could be made available to reservoir engineers for use in their reservoir simulators.

The next episode that's worth some reflection is the move to exploration 3D in the early 1990's. Investment in new vessels, again - to give due credit - led by PGS, allowed seismic contractors to tow many more cables in a much wider pattern, allowing 3D data to be acquired much more quickly and cheaply. However, a major bottleneck now appeared in the processing stage where the massive amounts of data being acquired "several thousand sq kms in some cases" implied a year or more's processing time, threatening the possibility that the first commitment wells on the acreage might be drilled before the 3D was available, again somewhat defeating the objective. The first response to this was for seismic contractors to invest in onboard processing so that a reasonable amount of processing could be undertaken more or less concurrently with acquisition so that a preliminary, interpretable, 3D volume could be made available within a few months of the last shot being fired. Nowadays of course, satellite data transmission, massive computing power and so on means, that a more final data volume becomes available in the same time frame.

The upshot of all this is that an offshore area such as Deep Water Angola enjoys a better than 90% exploration success ratio in Blocks 15, 17, 18, 31 and 32.

Another significant development of the last 10 years has been the growth of repeat or "time-lapse" 3D surveys - usually referred to as 4D - as a component of effective field management (which requires the active monitoring of reservoir properties such as pressure, saturation etc.). The use of 4D increased rapidly in the 1990's. Confronted with this new and extensive type of data, for a while the most significant analytical technique was to process two time-separated 3D data sets in parallel, and then to look at differences at the target reservoir level: interpretation then consisted (more or less!) of looking at the major differences and saying "Hmm, this is probably related to that water injector or that gas injector" or something similar and equally unprofound.

Nowadays, reservoirs are monitored using repeated surface seismic data (4D) together with the acquisition of surface and subsurface well data, and the integrated analysis and interpretation of both to reach a good understanding of how fluids in the reservoir are behaving. Multiple data sets covering many fields are being used in many different ways, varying between simplistic qualitative comparisons to sophisticated models. Such surveys may be used to:

  • Identify compartments
  • Locate possible infill targets
  • Design effective well interventions
  • Improve reservoir understanding
  • Reduce uncertainty in production forecasting
  • Improve estimates of field reserves

The use of 4D is now capable of identifying the pressure changes due to production and injection as well as changes in saturation and solution gas breakout.

My point is obvious, I guess. In each of these episodes, geoscientists were confronted with the (Information Management) problem of an overwhelming rush of data and an operational need to make timely sense of it, similar - in the memorable words of an ex-US colleague - to "a thirsty man holding a tea-cup under the Niagara Falls and expecting to get enough to drink!". Yet, solving the problem led to competitive advantage for the leaders.

And, putting my geoscientist blinkers on just one more time, I'd assert that many sub-surface teams are now organized, and undertake their work, so that the static and dynamic three-dimensional earth model sits at the core of the team's thinking.

Now as somebody who is made slightly dizzy by the notion that my iPod can hold not only every sixties tune that I would wish to listen to but also a significant proportion of those actually written in the sixties, I find this hard to take in and I'm glad that I'm not responsible for delivering the brave new world of the Digital Oil Field.

But the future "winners" in the oil & gas patch will deliver it to their advantage.

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posted by The Rogtec Team @ 16:18  0 Comments

Wednesday, 6 May 2009

Caledus Improves Well Construction Offerings

Vision becomes reality as Caledus announces JV and new product

Caledus, the Aberdeen headquartered well construction technology oil and gas service sector business, is reaping benefits with the launch of a joint venture company, entry into new markets and an innovative technology.

Earlier this year the company unveiled plans for significant global expansion with forecasts of 250 employees worldwide and turnover of £50 million in 2012.

As part of the strategy, Caledus is forming a joint venture with Malaysian oil and gas service sector company Deleum Berhad. Headquartered in Kuala Lumpur the joint venture will see Caledus significantly enhance its existing profile in Malaysia, Miri, Indonesia and Brunei and expand into Thailand, Vietnam and Myanmar. Up to 20 jobs will be created in the initial phase of the joint venture with a large majority being drawn from the local market. Deleum has over 20 years of oil and gas experience in Malaysia and the surrounding region and is headed up by Chandran Aloysius Rajadurai, Group Managing Director. Chandran, GMD said “We have worked closely with Caledus for the past three years acting as their agent, both companies now feel is it appropriate to enhance that relationship and a JV is the vehicle that we have chosen together.

Also in line with the vision, Caledus has announced its entry into the drilling with casing and liner market with the establishment of a new product line – the DragonBITE* Drill Shoe. DragonBITE* will complement the company’s existing well construction technologies, TD SOLUTIONS™ and SlimWELL®. TD SOLUTIONS™ is a range of individual down hole products and services to reduce non productive time. SlimWELL® slims down the well profile while maintaining well integrity and intervention ability without reducing the final hole size. SlimWELL® has the potential to reduce well construction costs by up to 50 per cent, enhances safety and reduces environmental impact.

The new technology is also seen as having an important role to play in proposals by Caledus to create a Slender Well Alliance – a grouping of like-minded companies, products and services that are focused on the development of lean profile, slender wells. Plans for the Slender Well Alliance are well advanced and it is anticipated that more details will be revealed later this year.

Paul Howlett, CEO and co founder of Caledus said: "Our vision stated that we would look to enhance organic business growth with strategic alliances and acquisitions, and a joint venture with Deleum is proof of that commitment. The Asian market has held up relatively well in terms of the global oil and gas industry and we see tremendous potential for our products in this arena.

"The establishment of DragonBITE* and our entry into drilling with casing and liner market was a logical progression in our suite of well construction technology, and again ties in with our strategic commitment to incorporate new product lines where appropriate to enhance the business. There is a significant demand for this technology particularly, in Asia and offshore and onshore North America.

"Casing and liner drilling, enhanced by the services offered by TD SOLUTIONS™ and SlimWELL®, will form an integral part of our proposed Slender Well Alliance. We are extremely excited about this concept which will bring together a range of products and services to create a slender well solution for the operating community."

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posted by The Rogtec Team @ 09:15  0 Comments

Tuesday, 5 May 2009

GIS & GPS in the Oil & Gas Industry for Russia

By V.Yu. Andrianov, DATA+ LTD

Any competitive business today just cannot do without computerized systems that have learnt to store and process information on business targets and procedures much better than humans. If accurately configured, an information system may be none the less valuable for a company than its basic production infrastructure assets.

Geoinformational systems (GIS) are one of information technology domains intended to handle spatially referenced information. Even though the technology is more than a dozen years old, it is in the most recent years that a burst-like integration of GIS into a range of industries has occurred. Contributing to the phenomenon are qualitative growth of computer processing power and progressively lower data storage cost, which is critical for handling spatial information, along with emergence of popular mapping internet services, such as Google Maps, personal navigational systems, let alone the simplicity of taking coordinates by means of global satellite systems of GPS type.

Oil and gas industry has long started using GIS as a primary instrument essential for geologists and ecologists. Thus, USGS has nowadays developed into a major consumer of commercial GIS software. A kind of stereotype has even formed with regard to geoinformational systems as of "something to deal with geology".

Yet, spatial information is not entirely confined to mineral resource deposits and geographic maps. In fact, a substantial portion (if not all) information describing oil and gas companies' assets and business prospects is spatially referenced, from core-taking in a specific well to filling stations, from license areas to marketing strategy differentiation. Today, the leading developers of database management systems (DBMS), such as Oracle, IBM, Informix and others realize that spatial data is an important information type that needs to be supported by corporate level systems, which is exactly what their latest products can do.

One should not confuse geoinformational systems with computer-aided mapping systems. GIS is not just a map on a PC display, but a means of cartographic imaging a variety of data, as well as a method to analyze data using spatial distribution of objects and processes. Invention of centralized facilities to store spatial data and multi-user access enabled the leading GIS software developers to bring the technology to corporate level offering the opportunity of integrating, based on spatial location of objects accounted and controlled, practically any data and business processes handled by services and subdivisions of major vertically integrated companies.

GIS has a wide spectrum of applications in oil and gas industry. Here are several of its major segments:
- geology, prospecting and management of fields' life cycle
- cadastre, evaluation and management of licenses, land allocations, environmental payments
- monitoring and spatial analysis of production profile to maximize oil recovery
- logistics, freight scheduling and vehicle fleet operations management
- marketing, sales area competitive analysis and distribution system optimization
- evaluation of holding company internal competition, development planning
- integration of aerospace surveys GPS-measurements into corporate business processes
- emergencies: on-line response and environmental damage assessment

One cannot help wondering as to "how in the world can this versatile technology work so well in those multiple applications?". The answer is: just as easily as standard database management systems do. The "geo-" prefix simply indicates that from now on these DBMS will store spatial component of the data, granting to users new opportunities previously out of reach. It should be noted at once that it is more than plain quantitative capacity growth, but a qualitative leap, almost comparable to recovery of eyesight (the dramatic effect is normally dampened as changes are introduced gradually, in a step-by-step manner, and yet exclamations like "Wow! We never imagined such things were possible!" - are not uncommon).

Now let us take a quick look at how geoinformational systems are typically applied in oil and gas industry. Geologists and surveyors have used GIS since long ago, because they have to deal with maps anyway. However, in contrast to conventional maps that may take many days to plot and print out, GIS can instantly produce maps of any kind and nature. More importantly, the maps thus produced can contain not only static topographical data, but also the results of spatial analysis just carried out in the same media where the maps are being created. Armed with digital maps carrying topographical and geological information, aerial shots, geographically reference, seismic profiles etc., and a full-featured GIS, a specialist can make a full-scale analysis of a vast acreage to spot oil and gas occurrence, estimate the reserves and prepare a report constituting a basis for decision-taking. It means that GIS is a facility to generate new information out of the existing database capable of presenting the output data in the form of maps so that it takes several times quicker to search for and evaluate prospects.

Developing a field is not a cheap undertaking, so the operator may substantially profit optimizing the whole business. Geoinformational systems can find the best well locations and compose access road network, calculate the construction cost of such roads and damage compensations payable to the government for land use and landscape development. Noteworthy, GIS can help you not just calculate those variables, but also minimize them taking into account plenty of factors: forested area locations, specially protected preserves, other valuable vegetation, soil types and wetlands, potential vicinity to inhabited areas and the existing service lines, etc. This is the way geoinformational systems help find the best planning solutions for field development and, owing to quick assessment of multiple factors, to promptly update plans if any changes are required.

Practically all commercially available GIS packages today include 3D facilities. The most advanced ones are capable of not just seeing a perspective view of the surface, but can also create a 3D image featuring both surface and subsurface objects. Coupled with wellhead GPS coordinates, deviation survey data can be processed to make a spatial well path image in an ensemble with a map, photo shots and other objects. One can actually see boreholes of many wells running deep underground, crossing specific formations, tapping on oil-bearing horizons etc. Logging data can be used to present a 3D picture of deposits, thus enormously facilitating field development planning and monitoring. When used in combination with geological and other special applications, multipurpose GIS packages can "work wonders" on usual PC's, which is far less expensive than VR-rooms that up till recently used to be the only method of "diving" into the subsoil.

In addition to pure visualization, geoinformational systems include measurement-based analysis facilities capable of designing spatial images though inversion, while the newly invented animation techniques can show a phenomenon as a moving picture. Such techniques are effectively applied to monitor spatially distributed dynamic processes. A good example is water injection typically practiced in oilfields to maintain formation pressure.

To keep producing wells from premature production of pure water, water flooding front movement must be continuously monitored so that timely steps can be taken to adjust water injection points and rates. It is critical that the on-going process is tracked down, which can be best achieved through animation. A spatial image of water flooding is obtained based on well test data and mixed production content readings constantly monitored through interpolation is made in GIS, while animation shows the modifications occurring to that image with time. This is how specialists can have a visual perception of the flooding in progress meaning they can act with utmost accuracy and efficiency. This results in the highest ORF's with minimum oil recovery enhancement costs.

Industrial infrastructure and facilities are generally operated using special information systems (EAM, ERP). As major companies often operate sites scattered around vast areas (including those located abroad), the accounting functions of the above systems in combination with GIS geographic location data give the managers a chance to have a better grasp of both the entire stock of production resources, and its separate pieces. The leading world's software suppliers support their systems' communication modules with the most advanced assents and production management systems (for instance, SAP R/3 and ArcView GIS). Russia's home IT products developed by oil companies are fairly common, too. They integrate access to such systems in client user applications. Access from GIS environment to accounting data makes it possible for specialists to see and assess interrelated effects of industrial (internal) and natural (external) factors. Thus, operations in the North of Russia must monitor permafrost melting caused by industrial activities. Inland plains run a risk of pipelines being flooded because of construction disrupted land runoff. Geoinformational systems can detect problem areas and identify risk-prone objects through use of aerospace shots and information contributed by accounting systems. Known as very productive is a combination with field survey data referenced to the main database by means of coordinates provided by GPS receivers. Thanks to the above opportunities contributed by site GIS site management solutions of better timing and quality become available, with reduced risks of emergencies or accidents.

Sales planning is the activity type for GIS to clearly demonstrate high investment efficiency. Retail sale locations and distribution oil tank farms layout must be based on spatial distribution analysis with regard to current and potential consumers account taken of competitor sale terminals. It is only at random that "Manual" methods can produce the best solution here, for there is a need to analyze several irregularly located factors in parallel. For example, in order to correctly deploy a filling station, one should mind population density, traffic level, taxation regime, land price, remoteness from supplier tank farms and other variables. Each variable will form an individual cost surface, while a weighted combination thereof will constitute a common priority surface, with "hill" peaks indicating locations most suited for new sales points, i.e. locations combining high demand level and low construction and/or operation costs.

Another illustrative example is optimizing tank farm supply zones and petroleum product delivery routes. For example, our company's experience has shown that demand fluctuations are typical of the way many oil tank farms have to operate often leaving them "underloaded". Redistribution of consumers serviced is a method to smooth out the load and reduce the number of oil tank farms required. If combined with optimized delivery routes, it can bring 20-30% savings with the same or even shorter average hauling time. As consumer environment tends to change (new consumers and competitors emerge, road network is upgraded etc.), periodic GIS-aided sales network optimization analysis allows to make timely adjustments to maintain the highest profitability possible.

There is one more interesting challenge resolvable through combined use of GIS and GSP technologies: tracking cargoes and traffic on-line with the purpose of dispatching them. It has been actively used in sea and railroad transportation, by forwarding agencies, in carrying hazardous and valuable loads. In addition to meeting the natural requirement of locating all freights, tracking is typically accompanied with a noticeable economic effect owing to psychological aspect as the drivers prefer to stick to their preset routes and become generally more disciplined. Recording motion paths allows for simulating actual situations in the future, which may be of use for traffic accident or emergency investigations, as well as to analyze and optimize traffic routes and schedules. To implement dispatcher center tracking function, a company has to install on-board computers on their fleet, to include a GPS receiver and coordinate transmitter, plus other optional navigational parameters. Messages can be relayed via cellular, satellite, transponder or other radio communication links to be finally received at the dispatcher center message server. This server receives messages from all carriers, processes them, sorts out and presents them in the form of trajectory and traffic schedule files. By interfacing the message server, GIS application can show transport vehicle movement either on-line or as a record, the image (if necessary) being superimposed onto any map in combination with any other user applied information. Trajectories and traffic parameters themselves may be used analogously with any other data: for spatial analysis, reporting documentation etc.

GIS multi-factor analysis facilities are not limited with search of optimum locations for prospective sites - they can also identify optimum trajectories connecting any two spots. This function is widely applied in road and pipeline design. It can account for any spatial distribution factors, such as ground profile, vegetation, soil types, water entities, inhabited areas, roads etc. The system is able to automatically find the best path to bypass restricted areas and/or bring the route through mandatory specified points. Having analyzed all factors, the system will propose one or more options of the best routes plus the corridor where cost fluctuations should remain within acceptable limits.

To conclude this introductory overview of GIS and GPS applied in oil and gas industry, it would be proper to make a mention of Internet and intranet map publication facilities, along with the novel server architecture of geoinformational systems. This technology accommodates GIS applications on the server so that users can interface them with a standard web browser. The advantage of this approach is that no GIS software has to be installed on user PC's (an operating system and a browser are sufficient), while the access is possible from the Internet (intranet) workstation. Information security of such distributed system is achieved through standard access limitation and data coding utilities. As means to configure such systems became available from the leading GIS providers, many oil companies (and not only Russian ones, for that matter) proceeded to actively introduce the technology for their in-house needs. The benefits it offers are evident: system administration as such is considerably simplified (all updates are effected on the server saving the administrators the trouble of visiting departments, branches etc.), a range of users widens up (mainly on account of managers and other employees who are not professional GIS users), a company's management is granted a handy visual cartographic aid to check current work status and the company's business results right on their PC's.

In summary, it should be noted that due to the capacity to integrate a variety of data and specialist systems enhanced by advanced analysis and imaging geoinformational technology carries a good promise to increase the efficiency of business run by oil and gas companies. The reduced time required to prepare informed decisions optimized through multi-factor analysis shortens payback period and, on many occasions, cuts total business owing costs. Similar to any other information technology, GIS is not a panacea: it can be productive enough only in the hands of qualified specialists subject to a comprehensive approach.

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posted by The Rogtec Team @ 17:54  0 Comments

Russian Production Capacity and the Development of Western Siberia

Russia s oil production growth has slowed in recent years, from double digits in 2003 to just 2% last year. The ‘boom’ came mainly from reinvigorating the West Siberia area, first discovered and developed in the Soviet era. Application of more advanced technology allowed production profiles to be increased but West Siberian growth is now slowing.

If Russian production levels are to be maintained, of course one option for Russia is to open, explore and develop new areas, for example by extending West Siberian success to both the north and the south (Yamal and Uvat) or building on early successes in East Siberia.

However, an additional option for West Siberian fields is to recognize the distinction between the recent application of those technologies which have successfully transformed production rate, and the use of "Know How" which could still lead to an increase in reserves and hence, at least potentially, to a transformation in production capacity.

By and large, the application of technology, in the form of for example:

Well Construction, especially Directional and/or Underbalanced Drilling
Coiled Tubing Operations
Mechanical Operations
Stimulation, Fracturing, Chemicals etc
Artificial Lift

leads simply to existing reserves being produced earlier than otherwise would be the case. Indeed, over-vigorous “pulling” on existing reserves can ultimately lead to damage to a field, for example to premature water breakthrough, and hence to a reduction in field reserves. Saudi Arabian examples illustrate these points (Simmons, Twilight in the Desert, 2005).

In contrast, reviewing studies where increases in reserves are demonstrated, the application of "Know How" seems to be key. I illustrate this with 3 SPE papers:

Back in 1993, BP and Arco (Szabo & Meyers, SPE Western Region Meeting, 1993) described the "Development History and Future Potential" of the Prudhoe Bay Field, the largest producing field in North America, then expected to yield at least 25% more reserves than estimated at start up. Their paper briefly described the history of the field and some of the key developments that had taken place which had contributed to improved recovery efficiency. These incremental developments resulted from a process of continuous surveillance, interpretation of field performance, management of multiple reservoir mechanisms, efficient utilization of the gas resource, and exploitation of the existing field infrastructure.

Four dominant recovery processes were at work in Prudhoe Bay: Gas Cap Expansion/Gravity Drainage, Waterflood, Miscible Flood, and Gas Cycling. Continuous management of these processes and analysis of field performance had led to identification of attractive targets for further development.

Even in 1993, Prudhoe Bay was seen by many as a mature oil field on an inevitable and irreversible decline. However, the major Owners (who included Exxon) in Prudhoe Bay had continued to pursue incremental developments to mitigate decline and supplement proved reserves. Unit technical studies were (and are) typically done in multi-company, multi-disciplinary work teams. The pooling of resources, experience and knowledge in this manner enabled efficiency gains and promoted the sharing of ideas and best practices.

In 2004, ExxonMobil (Wilkinson and others, SPE International Conference, 2004) described "Lessons Learned from Mature Carbonates…." based on three long-life fields in the USA (the Jay, Salt Creek and Means Fields), exemplifying the benefits achieved by a continuous process of data collection, studies, and systematic application of available technologies. The example fields "will achieve a range of incremental increases in the recovery factor of between 8 and 20% OOIP…….." A systematic and integrated approach to reservoir management has been employed to understand the basic rock and fluid physics of each reservoir and the key parameters that impact reservoir performance.
……..ExxonMobil has established a large knowledge base of secondary and tertiary project experience at the laboratory, pilot-test and field implementation stages."

In 2005, several SPE authors (Moulds and others, Offshore Europe, 2005) described reservoir management issues associated with the North Sea Magnus Field. Magnus is a high productivity field from which oil was first produced in 1983 and for which the production plateau of 150mstbod ended in 1995. Post-plateau, a variety of reservoir management techniques has been used to arrest decline and by 2005, through exploitation of a gas injection EOR opportunity, the oil rate was again rising and looking ahead, additional drilling to access more reservoir was anticipated to maintain significant oil production ‘beyond the next decade’. In this opportunity-rich field, prioritisation of drilling targets was seen as key, with EOR wells vying with infill waterflood targets and extended reach wells to the (untapped) field periphery. The particular challenge described (and met) by the authors is that, due to non-uniqueness, a conventional full field reservoir simulator history model cannot sufficiently reduce uncertainty on drilling locations and facilities decision: in fact, future reservoir processes and performance may be sensitive to aspects of reservoir description that have little influence on the history match.

So “Know How” is about integrated, multi-disciplinary teams, building knowledge, dealing with great uncertainties, learning from their mistakes: it is acquired by having explored for, developed, managed and produced hydrocarbons around the globe and thus is the preserve of IOCs.

It is not generally available from oilfield service contractors who may well own some technologies but do not know how as defined above. In addition, contractors do not participate independent from their technology – indeed being paid premium prices for its deployment is part of the business model which induces them to invest in technology development in the first place.

Provinces such as Alaska (for BP and Arco), USA Gulf Coast (for Exxon) and California (for Shell and Exxon), North Sea (for Shell and BP) have honed company and individuals’ skills. Another way of saying this is that the oil & gas industry is knowledge-based, that is, dependent on people and not simply on technology. And all the signs are that in the short to medium term there will be a shortage of appropriately educated and trained or trainable staff. As I’ve discussed elsewhere, I believe that a “scramble” for this resource is under way.

This argument does not of course dismiss the important impact of technology.

In simple terms, IOCs apply technology to developments and producing fields to:

a) Image what’s there
b) Reach what’s there
c) Extract what’s there.

The last ten years have seen dramatic developments in the use of seismic technology, specifically "time-lapse" 3D, otherwise know as 4D, to Image fluids within reservoirs.
This technology – involving conventional surface-towed sources and streamers – has transformed reservoir management from its previous situation where the main approach to understanding reservoir dynamics was to build a 2D or preferably 3D simulation model based on relatively long-term production history (oftentimes an epic labour of love somewhat akin to the building of the Grand Mosque* in Cordoba!).

The North Sea has been greatly impacted by 4D technology but perhaps an even greater impact will come in deep-water fields where wells are very expensive and thus any increase in certainty as to fluid movement is exceptionally valuable.

This said, it would be facile to assume that what is done today represents the limit of what is achievable with geophysical technology, whether in acquisition, processing or analysis. Indeed, it is widely envisaged that The Instrumented Oil Field lies in the (near) future with down-hole
sensors recording seismic and electro-magnetic waves, and perhaps potential fields (gravity and magnetic), and seismic and electro-magnetic sources complementing conventional surface (and sea-bed) sources and sensors.

Globally, the most significant problems associated with this vision are:

Developing sensors and sources that are reliable down-hole,
Delivering said equipment to the reservoir, without interrupting production, and
Analysing the data to deliver a usable Image.

However, the issue in Russia is this:

By an accident of history, Russian geophysical contractors are focused onshore, somewhat regional, have relatively weak technical quality assurance and HSE standards, no experience of 4D, and little understanding of working as an integrated part of a multi-disciplinary (reservoir management) team.

Western geophysical contractors have global onshore and offshore experience, good technical quality assurance and HSE standards, significant 4D experience, and are used to working with multi-disciplinary teams. However, with the exception of WesternGeco via its relationship with PetroAlliance, they have shown little appetite for, or commitment to, working in Russia.

There seems therefore to be both a pressing need and a clear opportunity for a multi-national service company to bring new geophysical ideas to the development and production of Russia’s onshore and offshore resources. A merger between a Russian contractor and a Western one seems to be called for.

*The Grand Mosque in Cordoba:

Cordoba fell to the Moors in 711AD:
Late 8th C AD, the original Mosque was built
833-852 AD, first extension
961-966 AD, second extension
987 AD, final extension.

Following the re-conquest of Cordoba in 1236 AD:
1254 AD, Chapel of San Clemente added
1258 AD, Capilla Real added
Late 15th C AD, Chapel of Villaviciosa added.

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posted by The Rogtec Team @ 17:41  0 Comments

TNK BP - Fast tracking Orenburg discoveries

From Exploration to Production in 12 Months

Often, when exploration is mentioned, it conjures up wells drilled in far-flung and remote parts of Russia, such as Southern Tyumen (Uvat) or regions in the far north (Bolshekhetsky). These Greenfield areas are critical to the Company's mid to long term growth, with limited potential for short term production; meanwhile, around half of TNK-BP's exploration activity occurs in Brownfield areas. These areas are typically within mature oil basins or close to existing fields (within 50 km)

The enabling technologies of cheap, modern, high-quality 3D seismic, its integrated and rapid interpretation and improved sedimentary understanding have allowed smaller oil traps to be identified, at the same time lowering their risk. Once discovered, these fields can be economically developed because they are close to existing fields, reducing tie-in costs and allowing use of existing infrastructure (i.e., roads and power) and facilities (i.e., oil processing and water injection), while the spare export capacity allows easy transport to market for the hydrocarbons.

This means that developments will cost much less than in new Greenfield areas, and their development and subsequent production can be achieved far more rapidly. The combination of advanced technology and available infrastructure allows smaller discoveries to come promptly on line where five years ago this would not have been possible.

In Orenburg, discoveries made over the last four years have been brought into production within 18 months and now contribute around 3 percent of Orenburg's production. This is set to grow significantly in the future.

TNK-BP's key Brownfield exploration areas are Orenburg / Samara and West Siberia (around Kamennoye (West KhMAO) and Samotlor (East KhMAO) respectively) (Fig. 1).

Application of Appropriate New Technology in Brownfield Areas

The use of new technologies and techniques to unlock the remaining potential of the Brownfield regions is key to their success, as overspending or slow turnaround easily erodes the value of these small projects.

Affordable, high-quality 3D seismic is only now being used within Brownfield areas of Russia for exploration. The quality allows smaller structures to be defined structurally, with significantly improved certainty and correspondingly lower risk. The seismic can be acquired quickly and processing in TNK-BP's Dedicated Processing Center (DPC) ensures clearest focus, quickest turn-around time and highest quality. In addition, it allows a direct link between the client (interpretation team) and the processors. In priority projects, fast-track processing can produce good-quality seismic cubes within three months of data delivery.

3D seismic is not just used to create an exploration well location but can produce 3D geological models even prior to drilling; this helps speed up appraisal and development planning post discovery. Modern interpretation packages (for example, Petrel*) are capable of running on a laptop computer and can be used to rapidly interpret the new seismic. Framework horizons can be produced in an afternoon when five years ago it would have taken a week to produce the same results. This allows the interpreters to easily refine maps and also frees them up to focus on the details around prospects. In addition, the software allows the entire exploration team to work on the data from maps based on seismic and geological studies to build reservoir models. This level of integration allows numerous data sources to be integrated into a single project, shared across the team, and results are modified rapidly.

Multi-disciplinary teams, sharing the same goals and sitting together, allow each team member to interact on the problem, giving their perspective and allowing the free flow of ideas. All this speeds up interpretation work and improves prospect generation and risk. The use of Visual Modeling Center (VMC) style forums to share information and results with regionally based teams in real time has improved communication and built trust.

The need for geological understanding of the entire petroleum system from regional to prospect through Gross Depositional Environment mapping (GDE) has led to refocusing of exploration analysis to include reservoir distribution along with previously overemphasized structural controls. The understanding of why oil is or is not present in certain areas allows better predictions of the sweet spots for exploration and appraisal (E&A) activity and license acquisitions.

Exploration Success in Orenburg

Orenburg region can be taken as an excellent example of Brownfield E&A where exploration discoveries have been fast-tracked into responsible production within about 12 months. Orenburg is an oil-rich region and part of the enormous Volga-Urals basin which has been in production since the 1930s and, prior to the discovery of West Siberia in the early 1960s, was the main oil and gas production area of Russia.

The assumption is that this is a very mature basin with little exploration potential. Nonetheless, since the formation of TNK-BP in 2003, exploration in Orenburg / Samara has added 22 mln t of new recoverable oil reserves (classified as C1+C2). In addition, we currently have 9 exploration license areas, five of which have been purchased since 2004, and we have acquired 4,000 sq. km of 3D seismic. The regional GDE and composite common risk segment (CCRS) descriptions, typical modern exploration tools, were completed in 2006.

TNK-BP's 2007 plan is to drill 11 exploration and appraisal (E&A) wells and acquire 1,200 sq. km seismic. Many more license acquisitions and wells are planned. A simple statistical technique can be used to estimate the number of undiscovered fields. It suggests there could be more than 500 individual traps of between 6 mln t and 60 mln t OOIP (original oil in place) left to find within the Volga-Urals basin, giving a total OOIP of close to 6 bln t (risked).

Within Orenburg, there are a number of exploration discoveries that have either already been fast-tracked to production or are in the early stages of this process. These include the three successful discoveries around the Sorochinsko-Nikolsky license area which are all on their way to production, and the Buzuluk license area which is still in the exploration stage.

Sorochinsko-Nikolskaya Group of Fields

The license block of Sorochinsko-Nikolsky is located in central Orenburg. The fields have been in production for 40 years or more and are a series of domes, discovered without the aid of seismic tools. A modern seismic survey was acquired and, based on its interpretation, three major new prospects (domes) were identified (Fig.2).

Map of the existing and new domes within the group of fields

The first Borodinovsky dome was drilled in 2004-2005 by well 900, which was put on test production during the first half of 2006, producing 20,000 t of oil. Follow-up appraisal is planned and, once completed, the wells will then be turned to production. Subsequently, Verkhne-Nikolsky dome was drilled by well 901 in 2006, and Novo-Lvovsky by well 910 in 2007, and both plan to be in production this year. Follow-up appraisal is budgeted for 2007-2008 with approved pilot development plans. These discoveries have a total potential of about 10 mln t to 20 mln t of reserves between them.

Buzuluk License Area

This license project is still in the exploration stage; but a 1,100-square-kilometer, 3D seismic survey was completed in 2006 and is still undergoing processing. Numerous new prospects have been identified and wells are planned for late 2007, continuing on for five years, combining both new-play exploration and little "e" exploration and appraisal.

The planned development tie-up time is three to six months following discovery, with full appraisal within two years.

Specialists believe that this rapid turnaround time, coupled with existing capacity within the oil facilities, will allow significant value to be obtained from relatively small reserves. Thus, exploration activity does not deliver just long-term renewal projects, but within specific areas it can deliver near-term production as part of a framework of responsible field developments. Activity in Brownfield areas can deliver high-commercial-value projects that compete very favorably with their larger cousins in the Greenfield areas and help TNK-BP grow short-term production while retaining excellent capital returns.

TNK-BP: Bringing Cutting-Edge Seismic Technology to Russia

Forecasts show that in 2007 almost one-third of all 3D seismic surveys in Russia will be performed on the Company's order. In a five-year outlook, we plan to do at least 5,000 sq. km of 3D surveys per year. This work is expected to cost about $120 mln per year. Such major investments result from the fact that upstream development groups have come to realize the value of 3D seismic data and have committed to cover all major fields of TNK-BP with 3D surveys.

Marketing research annually performed by Seismic Technology Dept. of TNK-BP shows that over the last three years, the Company has been one of the largest customers of 3D seismic survey services in Russia. Modern seismic surveys are the most effective exploration method in the oil and gas industry; they also provide a key tool for optimizing development of current main upstream assets. The priority task for seismic is to reduce risks associated with drilling and add to the Company's reserves.

Among the main tasks currently faced is delivery of an integrated seismic program, which consists of exploration and development surveys. Another priority is collection of high-quality, world-class seismic data at minimal cost. In addition, TNK-BP pays a lot of attention to HSE compliance and introducing latest seismic technology.

To date, 3D surveys have covered about 35 percent of the total area of the Company's major fields. Since 2004, the company have systematically performed 3D seismic surveys on all major producing assets of TNK-BP, Samotlor, Vostochno-Urengoyskoye, Talinskoye, and Kamennoye fields. Last year, we started to actively implement 3D seismic in exploration for the first time. Prior to this, in most cases we used 2D survey methods that failed to properly delineate reservoirs and provide a good understanding of the relationship between the adjacent field and prospective structures.

Work to Obtain Quality Data

To ensure that the TNK-BP seismic program is successful, the Seismic Technology department has implemented an effective project management process. We have introduced a reporting system that uses the latest Internet based communications. Contractors use the system to report on work progress on a daily basis. Every day, the information on all projects is recorded in a single database for Seismic Technology. This allows us to trace any change and make appropriate balanced and effective decisions.

In addition to managing seismic operations, the Company controls the quality of seismic data to ensure that it complies with our high standards. Over the last three years, we have implemented a number of projects that substantially improved the quality of data:

Only the best contractors have been pre-qualified for seismic projects (Bashneftegeofizika, TNG-Group, Tyumenneftegeofizika, Petroalliance). These contractors have sufficient experience as well as equipment, financial resources and HSE performance.

Since 2003, the density of seismic data collected has tripled and is currently 115,200 traces per sq. km. This parameter quantifies the quality of data. Fig. 3 shows a sample of high-density 3D data.

New 3D seismic map from the top Tournaisian within the Buzuluk license area

Thanks to broad-band Internet connection between the contractor's office and TNK-BP, we were able to set up a continuous quality control of field operations and seismic data processing.
We have established a dedicated Data Processing Center (DPC) managed by global leader WesternGeco. This allowed us to consolidate and implement the best Western and Russian practices in seismic data processing. Good results from the DPC work have led to extension of the contract with WesternGeco for another three years in 2007.

In 2006, the Company implemented a practice of signing long-term contracts for seismic projects. TNK-BP has long realized the advantages provided by long-term contracting but started using this approach only last year. By using this approach, we can attract the best contractors in a very tight seismic services market, keep control over cost inflation, foster development of the seismic services market and manage and mitigate HSE operational risks. Other advantages of long-term contracting include detailed planning of the entire seismic survey cycle a year prior to the beginning of data collection (project feasibility study, scouting, seismic modeling). All this in the end helps to reduce the time between a first seismic shot and the start of drilling and hence reducing seismic cycle time.

Other Initiatives in 3D Seismic

Regardless of achievements, Seismic Technology continues to develop in terms of both project management and introduction of new technology. For more detailed planning of seismic projects, we use modern topographic data such as aerial photography images and LiDAR data (Light-Imaging Detection and Ranging). LiDAR is a technology that can produce extremely accurate 3D elevation models overlapped with aerial photography images in actual coordinated system).

We continuously work with our contractors on improving HSE performance. In 2006, for the first time in Russia, we have tested summer-season collection of 3D seismic data. This technology is no different from the winter method, but there are higher requirements to data acquisition systems and special vehicles are used that minimize the impact on environment. If application of this method proves to be successful, the Company will be able to increase the annual volume collected seismic data and therefore speed up the exploration and development progress.

Nicholas Whiteley, Team Leader, Brownfield E&A, Exploration, Technology
Dmitry Zolotarev, Chief Specialist, Brownfield E&A, Exploration Technology
Maria Konstantinova, Specialist, Brownfield E&A, Exploration Technology
Alexander Fokin, Chief Specialist, Brownfield E&A, Exploration Technology
Artem Zhukov, Chief Specialist, Seismic Technology, Exploration, Technology

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posted by The Rogtec Team @ 17:25  0 Comments

Monday, 4 May 2009


Sorokin A.V., Sorokin V.D. Omega-K, Tyumen

Knowledge of fractional analysis and physico-chemical properties of oil is used in many areas of petroleum science to tackle a dazzling array of practical issues. Again, in many cases, the properties of oil are used as a model. And this always brings up the question of whether the chosen model reflects the real values of the properties of oil.

Models of fractional analysis and physico-chemical properties of in-place oil are used for solving the problems of oil origin, the specificity of processes that occur in oil before it migrates into traps where it currently resides, the degree of change it undergoes during storage, and the study of the impact on its composition and properties of processes that occur during storage of selected oil samples during laboratory investigations, etc.

Among the hands-on tasks that involve the use of values of in-place oil properties, mention should be made in the first place of reserves assessment, calculation of oil recovery factor during lab tests, etc.

Hence, the parameters of the model describing the fractional analysis and physico-chemical properties of in-place oil indirectly affect the assessment of the investment appeal of an oil production scheme at a specific field.

Models of fractional analysis and physico-chemical properties of mobile oil are used in hydrodynamic simulation of oil displacement process, selection of relevant displacement technology, they are also incorporated into technical requirements for equipment for oil production, treatment and transport, and considered when choosing process solutions for oil field processing of petroleum, etc.

Models of fractional analysis and physico-chemical properties of commercial (degassed) oil are utilized in addressing the issues of storage and delivery of oil via trunk pipelines, selection of technologies and equipment for its processing, and affect the process for optimizing the range of obtained products.

From the above-mentioned models, models of fractional analysis and physico-chemical properties of degassed oil are currently the best-fit models that reliably reflect the actual object which is due to physical accessibility of oil in any volume, and the well-developed methods of taking and testing of samples.

Models of the physico-chemical properties of mobile oil are far less adequate to the real object of investigation due to a number of constraints imposed on methods deployed for drawing samples of this oil at various stages of oil field development[1].

There are currently no adequate models of in-place oil by reason of lack of procedures and devices for taking in-place oil samples. To a large extent this is due to the fact that in regulatory documents and technical literature there is no clear-cut distinction yet between the terms : "in-place oil" and "mobile oil".

The meaning of the terms "in-place oil" and "mobile oil" do not coincide because both in the composition and values of the physico-chemical properties of oil-in-place and mobile oil there is a substantial difference as shown in paper[2].

Mobile oil is only one of the components of in-place oil and therefore the values of their properties do not coincide. This example demonstrates the exceptional importance of working out relevant terms and their definitions which then set the scene for further research in many areas of petroleum science and practice.

In-place oil is a natural system and for this reason its fractional analysis and physico-chemical properties cannot be governed by the technology of oil recovery, methods of its study, etc.

Therefore, the process of generating a model of the physico-chemical properties and fractional analysis of in-place oil for a specific production facility should be maximally independent of the technogenic impact on oil in-place.

The notions of oil in-place and mobile oil are not treated as separate entities in applicable regulatory documents. The values of properties of the latter tend to vary during the period of oil field development and are also a function of the technology deployed and parameters of the recovery process.

And thus, in actual practice, while taking and testing mobile oil samples the obtained results are identified with the properties of in-place oil without any appropriate substantiation. And since the physico-chemical properties of mobile oil are known to change their values [3] in the process of field development, then this also proves the fact that there is a disparity in the values of physico-chemical properties of oil in-place and mobile oil.

The information structure of in-place oil is presented in the study[2]. The need for developing such structure is dictated by reasons based on different methods of study and personalized estimate of the fraction of each in-place oil component.

According to the proposed structure, in-place oil is divided into mobile and immobile components. The mobile component is divided, in turn, into recovered mobile and non-recovered mobile oil.

The immobile oil consists of the following components: oil adsorbed by the reservoir surface, oil residing in structured layers and oil located beyond the deposit drainage zone. The composition and physico-chemical properties of mobile recovered component of in-place oil are studied by taking and investigating bottom-hole or recombined oil samples from the products of producing oil well. The composition and physico-chemical properties of non-recovered mobile component of in-place oil have not been studied experimentally, but can be obtained computationally by extrapolating the values of recovered mobile oil properties.

The composition and physico-chemical properties of oil located in adsorption layers on reservoir surface, in structured layers in the near-surface zone of the reservoir are studied by means of laboratory investigation methods. Physical models of the corresponding in-place oil component are also used in the experiments. The composition and properties of oil located outside the drainage zone correspond to those of in-place oil as an immutable object during the life of a field.

In practice, however, when each in-place oil component is investigated by its own technique, acquiring an adequate model of its composition and physico-chemical properties is feasible only through synthesis of information about fractions and the properties of all components.

This method of generating a model of composition and physico-chemical properties of in-place oil is cited in reference [2, 4]. Using volumetric data for in-place oil with parameters of mobile oil when calculating hydrocarbon reserves may bias the results of estimation of geological resources.

With this approach the results of calculating the hydrocarbon reserves indicate a lesser reliability and hence oil reserves are usually understated (for the groups of beds B and Yu of deposits in Western Siberia by 10-20%) while the reserves of oil gas are somewhat overstated.

A model of physico-chemical properties of mobile oil is utilized in geological and hydrodynamic simulation of the process of oil recovery. Today it is an established fact that this model is static. It has been established by numerous investigations including those based on the results of dedicated field experiments conducted in different regions of Russia that the composition and values of physico-chemical properties of mobile oil tend to change in the process of field development and are also contingent on operating parameters of the well.

Information on the results of these investigations can be gleaned from works [2, 3, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14] and elsewhere. From this it follows that parameters of the model describing the composition and properties of mobile oil are non-stationary, are clearly dependent on selected technology of oil production, the degree of impact of oil displacement methods, etc which should be considered during model generation. The sum total of the methods to account for changes in the physico-chemical properties of mobile oil that occur during the period of field development which makes allowance for the impact of main technogenic effects is presented in a list of works cited [2, 3, 12, 13, 14].

A lower quality of geological and hydrodynamic models of the process of oil displacement, especially at the fields under the late stage of development is the upshot of using models of the composition and properties of mobile oil that ignore the dynamics of their change during field development.

In a number of cases, history matching of the geological and hydrodynamic model of the oil displacement process fails to bring the desired result without considering the phenomenon of variability of values of the physico-chemical properties of mobile oil.

According to the conclusions drawn by researchers in the study [15] in order to achieve the required accuracy (10%) of field development indices while computing the hydrodynamic model of the process of oil displacement, the parameters featuring the values of the physico-chemical properties of oil should be defined with the following accuracy: oil density 1%, viscosity 4%, oil formation volume factor 3%. The physico-chemical properties of mobile oil during the process of development at the oil fields in Western Siberia vary in their values over a far greater extent (examples are provided in work [3]). The question of the value of in-place oil volume factor remains undecided due to lack of formation oil model. The first attempts at generating a mathematical model of oil in-place are outlined in a list of works cited [2, 3].

The question of separation of in-place oil in the drainage zone between its mobile and immobile components is a separate issue since their fractions are calculated using the oil recovery factor (ORF) whose calculation is based on an experimentally obtained coefficient of oil displacement by water. To determine the coefficient of oil displacement it is essential that a physical model of in-place oil should be used rather than its mobile component model as is the current practice.

When using the currently effective OST 39-195-86 [16] whose objective is regulation of jobs to determine the coefficient of oil displacement by water, obtaining objective results in defining this coefficient may be impossible for a number of reasons. The clause 1.5 of this OST prescribes using dry crude oil or isoviscous model of formation oil to conduct the studies and use is also allowed of recombined samples of oil in-place.

The first part of this requirement is impossible to implement if only because no one has yet succeeded in taking a sample of in-place oil at the present stage of scientific development. The current potential of available methods and sampling technology allow one to only take a sample of mobile component of in-place oil and even then with varying degree of validity.

The isoviscous model of in-place oil is not devoid of the following drawbacks. Since parameters of oil in-place are unknown, the isoviscous oil parameters are selected to fit those of recovered mobile oil model.

A sample of degassed oil is taken as a basis for the model and organic solvents are added to it to reduce its values of viscosity until they are equal to those of mobile oil. As a result, a disparity in the fraction ratio develops in the isoviscous physical model with regard to oil in-place model: the gas component is totally absent, the portion of heavy fractions is insufficient which are contained in increased amounts in the structured layers of in-place oil. The fractional oil content of structured layers depends on both reservoir properties and the properties of oil and, in the opinion of the study author[17] , may be quite substantial in some specific cases.

Despite the "match" between the viscous characteristics of the two oil models, the surface tension coefficient of the isoviscous model of in-place oil determined by capillary method is 1.5 -2 times higher than that of mobile oil model determined under similar thermobaric conditions. Therefore, the coefficients of displacement of these fluids (the isoviscous model and mobile oil model) by water will have different values.

It is also important to point out here that when using in the experiments the in-place oil model which, as a rule, features much higher values of density and viscosity under reservoir conditions and a lesser relative content of light components in its composition than does mobile oil, the difference in the values of surface tension coefficient between the in-place oil model and that of isoviscous oil should decrease.

Thus, if we consider to define experimentally the coefficient of oil displacement by water there remains an option of selecting an oil model through recombination with mandatory condition that parameters of the recombined oil model should correspond to those of the in-place oil model.

To achieve the highest possible degree of approximation, the selection of parameters of this physical model should be done by combining the individual fractions of mobile oil. It is necessary to develop in advance a mathematical model of the composition and physico-chemical properties of in-place oil according to procedures outlined in works [2, 4].

Usually when drawing up process documentation based on the coefficient of oil displacement by water the value of ORF is set such that it becomes virtually unattainable in the majority of cases with the use of only one technology of oil displacement by water. Therefore, in development practice to achieve the preset value of ORF other technologies are also employed such as hydrofrac, chemical methods of enhanced oil recovery, etc. This provides yet another proof that the value of the coefficient of oil displacement by water obtained in a laboratory experiment is overstated.

It is our opinion that the error in question emerges as a result of using in the experiment an oil model inadequate by its properties to oil in-place. Analysis of the foregoing compels the following conclusions:

  • To further develop the process of investigations of the fractional analysis and physico-chemical properties of oil in-place and mobile oil it is essential to establish and standardize a system of terms and to provide their definitions;
  • Because it was found impossible to take samples of in-place oil its composition and values of physico-chemical properties have not been defined experimentally and in consequence it is necessary to use computational methods to simulate the properties of in-place oil;
  • The composition and values of the physico-chemical properties of mobile oil are prone to change during field operation;
  • Parameters of the physical model used to define the coefficient of oil displacement by water must correspond to parameters of in-place oil model with the presence in it of components and fractions that actually exist in the oil in-place.


1. Sorokin A.V., Sorokin V.D. A system of experimental and theoretical methods of investigation of the physico-chemical properties of in-place oil at oil fields in Western Siberia. Tyumen: Vector-Book,2003, p.223.

2. Sorokin A.V., Sorokin V.D. Accounting for physical and chemical properties of in-place oil components in procedures for calculating the reserves and computing the oil recovery processes// Izvestiya vuzov. Oil and gas.-Tyumen,2005, 6 - pp.34-40.

3. Sorokin A.V., Sorokin V.D. Investigation of the process of variability of the physico-chemical properties of in-place oil during field development in Western Siberia. Tyumen: Vector-Book, 2004,- p.237.

4. Sorokin A.V., Sorokin V.D. Procedure for calculation of the physico-chemical properties of in-place oil for use in computing hydrocarbon reserves //In digest "Simulation of technological processes of oil production". Tyumen: Vector Book, 2005, #5 - pp.93-95.

5. Amerkhanov I.M. Regularities of change in properties of formation fluids during oil field development. // Survey information. Ser. Neftepromyslovoye delo.- Moscow: VNIIOENG,1980, p.48.

6. Sheikh-Ali D.M. Changes in the properties of in-place oil and gas-oil ratio during oil field operation. Ufa: BashNIPIneft, 2001, p.137.

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