Latest Oil and Gas News Russia

he first ice-class floating storage and offloading system (FSO) to be completed at a Caspian Sea shipyard and deployed for service in the Caspian Sea is to be issued ABS classification. The Yuri Korchagin is set to be towed out of Baku for installation, hook-up and commissioning this week. It is destined for the Yuri Korchagin Field in the Russian sector of the Caspian where it will operate for Lukoil.

The FSO hull was constructed in two longitudinal halves by Keppel Singmarine in Singapore and was towed through the Volga-Don River Canal and assembled at Keppel Fels’ Caspian Shipyard Company (CSC) in Baku, Azerbaijan. According to ABS District Manager Simon Jones, the size limitation of the Canal dictated that the unit be constructed in two modules for import into the region. The two hull sections were aligned and joined in drydock at the Caspian shipyard. The helideck and accommodation quarters, as well as other equipment, were loaded alongside the hull sections and also assembled at CSC.

ABS was involved in the project from the outset, continuing through initial construction to assembly and final delivery, working closely with the Russian Maritime Register of Shipping (RS).

The unit has been built to the ABS class notation +A1, Floating Storage and Offloading System, Ice Class C0, +AMCCU, FL(20). The unit is 132.8m in length, 32m in width has a depth of 15.7m. It has a fatigue life of 20 years and is dual classed with RS. The FSO can withstand ice conditions of minus 20 degrees Celsius and ice thickness of 0.6 meters.
Russia’s Lukoil is targeting December to start commercial oil production. When in operation it will be the largest FSO in the Caspian Sea. ABS Senior Surveyor Donald Dunlop, the project surveyor from Azerbaijan, reports ABS will be in attendance during the installation of the unit and will also class the mooring system once completed.
ABS has helped other operators meet the challenges of Caspian operating requirements, most notably Maersk’s first semi-submersible rig, DSS-20-CAS-M and the ABS-classed Parker Rig 257, the world's first arctic-class drill barge, operating in the shallow waters of the Northern third of the Caspian.

ABS has a robust ice program within its Corporate Research and Product Development Department. The aim of the program is to develop state-of-the-art methodologies and tools for assessment of ships and offshore structures operating in ice.
Founded in 1862, ABS is a leading international classification society devoted to promoting the security of life, property and the marine environment through the development and verification of standards for the design, construction and operational maintenance of marine-related facilities

Labels: ABS, Lukoil, oil gas russia, Yuri Korchagin

posted by The Rogtec Team @ 12:15  0 Comments

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: rao@restec.ru, offshore@restec.ru
www.rao-offshore.ru

Labels: CIS Offshore, Conference, Exhibition, Gazprom, Lukoil, oil gas, oil gas russia, RAO, Rosneft, St Petersburg

posted by The Rogtec Team @ 14:43  0 Comments

Introduction

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

Principle

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.

(m+ma)

d2x

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

Labels: iceberg Drift, oil gas russia, rogtec

posted by The Rogtec Team @ 15:55  0 Comments

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."

Labels: oil gas russia, rogtec, Well Construction

posted by The Rogtec Team @ 09:15  0 Comments

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
Completion
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.

Labels: artificial lift, oil gas russia, rogtec, Siberia, Well Construction, Western Siberia

posted by The Rogtec Team @ 17:41  0 Comments

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.

References
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.

7. Sheikh-Ali D.M., Galeeva R.K.,Levanov Yu.B. Prediction of changes in properties of in-place oil during oil field development // Development of oil and oil -gas fields: current state, problems and coping strategy (Proceedings of a meeting. Almetyevsk, September 1995).Moscow: VNIIOENG,1996, pp. 518-532.

8. Sheikh-Ali D.M., Galeeva R.K.,Levanov Yu.B. Change in gas-oil ratio and the content of nitrogen and methane in gas during development of Tuymazinskoye oil field. // In digest: "Modern instrumental physico-chemical and hydrodynamic methods of investigation of formation fluids, rocks and productive strata".-Ufa, 1999, issue 97, pp.104-107.

9. Khamidullin F.F., Dyashev R.N., Amerkhanov I.I. Investigation of changes in the physico-chemical properties of recovered oils during development of Romashkinskoye oil field. Moscow: Neftyanoye khozyastvo, 7, 2000, pp.31-33.

10. Sorokin A.V., Sorokin V.D., Sorokina M.R. The basis of procedure for predicting the variability of oil properties during field development. // In digest: "Simulation of technological processes of oil production". Tyumen, TyumGNGU, 2003, issue 4, pp.249-259.

11. Sorokin A.V., Sorokin V.D. The specifics of change in the physico-chemical properties and volumetric data of oil at "Lukoil - Western Siberia" oil fields. // In digest: "Problems of the oil-gas complex in Western Siberia and the ways of improving its efficiency". Kogalym, 2001. Book 1.- pp. 231-236.

12. Sorokin A.V., Sorokin V.D. Changes in the fractional analysis of mobile oil due to the impact of production-induced processes. // Bulletin of the subsoil user of the Khanty- Mansiisk autonomous district . 15, 2005, pp. 54-58.

13. Sorokin A.V., Sorokin V.D., Sorokina M.R. The effect of variability in oil properties on the procedure and outcome of calculation of hydrocarbon reserves. // Izvestiya vuzov. Oil and
gas. Tyumen,2005, 5, pp.45-50.

14. Sorokina M.R. Calculation of the values of the physico-chemical properties of mobile oil for simulation of oil displacement processes.// In digest: "Algorithmization and modeling of processes of oil-gas field development". Tyumen: Vector- Book,2005, pp.114-116.

15. Voronovsky V.R., Maksimov M.M. System of data processing during oil field development. Moscow: Nedra, 1975, p.230.

16. OST 39-195-86. Industry standard. Oil. The method to determine the coefficient of oil displacement by water in laboratory conditions. Moscow, 1986.

17. Markhasin I.L. Physico-chemical mechanics of the petroleum reservoir. Moscow: Nedra,1977, p.214.

Labels: Fractional analysis models, oil gas russia, Omega K, reservoir analysis, Tyumen

posted by The Rogtec Team @ 17:20  0 Comments

Petrov N.A., Korenyako A.V., Davydova I.N., Komleva S.F

When drilling pilot-operational well 1557/22 in the Sugmutskoye field, polymer-clay replenished mud was used as a basis in a horizontal section of the well in the same way as conventional directional wells in Noyabrsk region.

Chemical treatment of the mud included the following materials and chemicals:

Bentonite powder PBMA
CMC, Saipan
Polikem-D
LUB-167.

The mud was modified via additional treatments with polymers and lubricants (LUB-167 and graphite) and a comprehensive drilling mud surfactant - SNPH-PKD-515. The latter contributed to inhibition (hydration of clay) and surfactant properties. Carbonate heaver was added to increase the mud weight, with Pipe-lax additive in reserve in case of any sticking problems. Following that, a filter (perforated sub) was installed, FSG-146, in a horizontal section. Before sealing the space above the sub with a PDM-146 packer, the drilling fluid, contained in the horizontal section, was displaced with low-concentrated HCl with some cationic surfactant - 0,5-1,5% wetting agent IVV-1.

Oil reservoirs have been developed successfully for quite a while through directional drilling where the horizontal section of a wellbore targets the pay zone. Horizontal wells allow increased oil recovery from a formation due to the following factors:

• Increased oil rates as compared to conventional directional wells.
• Decreased probability of emerging water and gas cones.
• Recovery of oil from zones which cannot be reached with conventional drilling techniques (underneath communities, industrial facilities, agricultural lands in conservation areas and water conservation zones etc).
• Profitability of oil recovery from low-payable reservoirs.

Drilling and production of horizontal wells began in the Noyabrsk region, particularly in Sugmutskoye field in the early 1990's. This field is in an area of prioritized use of natural resources. Oil deposits were tapped within the field in formation BS 9-2 which represents a complex sand-shale reservoir with West Siberia' generic interlaying of hygrophilous sandstones and mudstones. The roof of the payable formation in the center of the deposit is between 2708 - 2714 m. Waters of BS 9-2 and AC 7 are of the calcium chloride type, with the salinity ranging from 12,10 - 17,03 gr/l. The average formation temperature at the water-oil contact of the formation BS 9-2 is 88C, with a formation pressure of 28.1MPa.

The Senoman deposits of the Sugmutskoye field are not productive. From experience of drilling directional production wells, there is a chance to impair well bore stability, which may result in pipe sticking at intervals above 2700 m. Drilling the interval below the surface casing shoe usually requires utilization of salt-resistant fluids of a polymer-clay nature.

Efficient transportation of cuttings and good carrying capacity of mud are critical factors when drilling wells with a horizontal bottom-hole. Effective transportation of solid particles can be achieved via imparting adequate energy. This provides a turbulent flow with a high velocity. If there is a higher concentration of cuttings in the mud due to a high drill rate, it may exceed the sand-lifting ability of the mud. Therefore, mud velocity in the annulus is regarded as one of the main parameters of bore cleaning. At a very high velocity of turbulent flow, most cuttings may be carried away with the flow. At low velocity, of the stream cuttings may accumulate on the low side of the wellbore wall resulting, eventually, in a cuttings pad on the bottom.

The task of defining what velocity is required to create a turbulent flow in the annulus is difficult. Moreover, turbulent flow should not be created when erosion-sensitive formations are the case, or if the pump is at limited capacity. Rotation of the drilling tool initiates a spiral flow, which in turn assists in cuttings removal and prevents the formation of new layers and sand drifts.

Acceptable levels of well cleaning (with mud) can also be achieved at moderate velocities. For example, at the laminar flow when mud flow characteristics are accurately defined.

Mud flow characteristics (rheology) in a turbulent flow are not linear. Here, there may be concurrently low viscosity and have appropriate carrying capabilities.

High carrying and the thixotropic properties of fluids precludes from the inner sedimentation of solids. At the same time such fluids should contribute to a minimal hydraulic resistance during the course of drilling. This favorably influences the performance of a drill bit.

Cleansing quality at the laminar flow is more sensitive to high viscosity at low gel strength (GS), which should be proportional to the yield point (YP). There is a certain dependency between these values and the quality of cleaning. Experience shows that the YP should be in the region of 30-40dPa, plastic viscosity should stay within 15-20 MPa*s, with relatively low gel strength (gel strength (1) not higher than 10dPa or gel strength (10) not higher than 40dPa). Favorably, funnel viscosity should be kept within 20-30sec.

Adjustment of mud flow characteristics can be done by altering the concentration of the colloidal clay components of mud solids and high-molecular polymer compound.

Stability of bore walls is achieved through adequate mud weight as well as the selection of inhibiting (water repellant) and filtering properties. In particular, fluid loss of polymer-clay mud should be ultimately low, ca. 3-5 cm3/30 min using the BM-6 meter.

The inhibition properties of the filtrate influence the size and properties of the cuttings particles. It is practically good precedure to have a 4-stage mud cleaning programme; in order to enhance performance of the cleaning equipment (mainly a shaker, centrifuge and settling tank) one should use coagulants and flocculants.

The optimal content of solids within the drilling fluid fed into a well bore is 20-22%, including a colloid clay component percentage of 1.6-1.8%. There should be virtually no sand (or it should not exceed 0.5%).

Drilling horizontal sections requires the usage of lubricants that minimize the friction factor between the filter cake and the drill pipe. Drilling fluids successfully used in conventional directional wells serve as a basis that certainly requires modification before drilling a horizontal section.

Polymer-clay types of mud are widely spread in drilling operations in the Noyabrsk region. The chemical composition of drilling mud is mainly the following:

• Powder-like low molecular polymers that are derivatives of cellulose.
• high-molecular polyacrylamides.
• surfactants of comprehensive effect.
• acid-soluble heavers (e.g. carbonaceous).

Therefore, the chemical treatment of drilling mud when drilling out from surface casing to 2700 m is performed in accordance with operations procedures applicable for directional drilling. Chemical treatment has a number of features within the highly deviated drilling sections below the intermediate casing shoe (when the building angle is as high as 90%), as well as when drilling a horizontal well in productive formation. In particular, it does the following:

• Prevents pipe sticking
• Enhance bore cleaning from cuttings
• Preserve quality of well bore
• Improve tapping of payable horizon

For engineering support of the pilot operational well No. 1557/22 at the Sugmutskoye field (1997) the following procedures of drilling mud preparation and conditioning were planned:

The ejector unit prepares the clay slurry by mixing high quality clay powder, with a density of 1020-1030 kg/m3. The clay-based mud is then mixed with chemicals KMTs-700 or CMC (USA) using 200-250 kg of dry chemical per 100 m3 of drilling fluid. The drilling mud is treated with the chemical CMC, whether in a dry condition or dissolved in water. If it is necessary to replenish the volume of circulation liquid then a water based solution is used, consisting of the chemical CMC and Saipan (Japan) in a ratio of 2:1. The mixture is diluted in a clay mixer on the basis of 2-3 kg CMC, 1,0-1,5 kg Saipan and 1 cubic m of water. Following that, a chemical called Polikem D (Kem-tron, USA) is added to this water composition on the basis of 0.5kg to 1 cubic meter of water.

KMTs-700 chemical is used for lowering fluid loss and adjusting the flow rheology of the mud. Saipan, an Acryl polymer, also reduces fluid loss value and, in addition to this, facilitates well bore stability thanks to its encapsulating (inhibition) effect. The high viscosity of - Polikem D allows a regulated flow rheology of the mud, showing flocculating and inhibiting properties.

In order to achieve both inhibiting, hydrophobic and surfactant properties, the chemical SNPH-PKD-515 was used, which is a composition of non- ionogenic and cation-active surfactants. Complex surfactant blends well with almost all chemicals currently used in the region. The water solution SNPH-PKD -515 is then used to condition drilling mud in a water-agent ratio of 3:1, and is thinly jetted at the pump suction point. Mud conditioning should be started from the interval below the surface casing.

Conditioning with LUB-167, a lubricant from Kem-Тron in the USA, should also start when drilling out from the surface casing and to ensure the concentration of thechemical is maintained in the mud.

Lubricant LUB-167 allows for the efficient reduction of torque, and resistance to the motion of the drilling pipe (drag). Since LUB-167 is a chemical that blends well with almost every chemical used in the region, it can be used in any water-based drilling mud.

For better lubricating mud, it is recommended to additionally use 2-3% graphite for the volume of mud in circulation. Moreover, for well engineering support it is important to have a 200kg reserve of Pipe-lax, an anti-sticking additive made by Kem-tron.

To achieve a higher density of drilling mud to meet procedural parameters, a carbonate heaver should be applied. In order to neutralize Ca2+ions when adjusting pH, 1.5kgs of sodium carbonate per 1 cubic meter of mud can be used.

As the length of the horizontal bore increases, and prior to drilling completion, drilling mud is treated with combined water solution KMTs-700 and Polikem D in a ration of 6:1. The water solution is added evenly throughout circulation cycle.

The operational parameters of drilling mud at intervals between 2700 - 2900 and 2900 - 3100m vertically are presented in the below table.

The sequence of conditioning drilling mud at the above intervals is as follows:
Between 2700 - 2800 meters: drilling mud is treated with the following:

up to 1 ton of KMTs-700 chemical
500 kg of Saipan
100 kg of Polikem D.

5-7 tonnes of preliminary hydrated bentonite powder, type PBMA, then needs to be added for every 100 cubic meters of mud.

During mud circulation 2tonnes of LUB-167 lubricant need to be added, 600 kg of SNPH-PKD-515 surfactant and 20 tonnes of carbonic heaver.

Between 2900 - 3000 meters: At this depth, drilling mud will need to be additionally treated with the following:
400 kg Saipan
400-800 kg of KMTs-700 chemical
up to 50 kg of Police D
up to 700 kg of LUB-167
and up to 600 kg of SNPH-PKD-515.

When drilling a horizontal bore, drilling mud must conditioned with:

2 tonnes of KMTs-700
Up to 700 kg of polymer Saipan
up to 100-150 kg of Polikem D in combination with up to 2 tonnes LUB-167, Up to 1 tonne of graphite
up to 600 kg of SNPH-PKD-515



It is quite logical that during the construction of the first horizontal wells at each field, as a rule, the number of unreliable sections not covered with casing is reduced to minimum.

Thus, for example, before drilling the horizontal section of a well bore an intermediate casing is run into the hole in order to cover the unreliable well bore lengths. Accumulating experience in the construction of sloped and horizontal wells and increasing the quality of drilling mud will ultimately lead to drilling without intermediate casing, which allows for significant savings in capital expenditure.

Indeed, construction of a well with a horizontal offset bears certain risks associated with the potential loss of well bore stability from the moment of drilling-in, untill casing running and cementing. The probability of stability loss of rock is most likely at high inclination angles.

However, rock properties across the geological profile of Sugmutskoye field at high inclination angles has not been studied sufficiently enough. Therefore, at key well No. 1557/22, the plan was to run in an intermediate casing at a maximum vertical depth of 2680m in order to achieve a minimum or zero probability of stability loss in the open hole interval when drilling horizontal section of a well bore.

Since running intermediate casing with a diameter of 245 mm results in a considerable cost increase for horizontal well construction, new data obtained during key-well drilling has enabled operators to optimize the design of other horizontal wells at the Sugmutskoye field.

During the drilling of this well, a new completion program was in effect. The program provided for setting a 146-mm non-cemented casing in a horizontal section with pre-fabricated and installed perforated subs (FSG-146). When running the casing, subs play a role of casing, ensuring the hole circulation through a shoe; and later on, when the well is producing, the subs provide hydrodynamic communications between the productive formation and the well. Before sealing the casing annulus above the horizontal section with packer FSG-146, clay mud in the horizontal bore section is displaced with acid.

The composition of acid solution includes 4-6% of concentrated HCl, with the addition of 0.5-1.5% of water-soluble surfactant cathion (wetting agent NBB-1). Particles of carbonic heaver dissolve under the influence of the acid solution, which in turn restores reservoir permeability. At the same time, the cathion-active additive inhibits the corrosion process on the casing during acid solution injection, inhibits deacidification and hidrophobize pore space at the bottom-hole formation zone, which facilitates cleaning of the bottom-hole formation zone from "impurities" during well flow stimulation.

Because a horizontal well bore section has a non-cemented perforated sub, the quality of tailing-in is, in fact, entirely dependent upon the quality of drilling mud.

In conclusion, when drilling wells with a horizontal offset, special care should be taken when selecting the type of circulation fluid and its composition, as well as when setting an ongoing monitoring process over the parameters of enriched drilling mud. It should also be possible to easily adjust its properties should the need arise.

Labels: Drilling Mud, horizontal wells, oil gas russia, optimisation, production

posted by The Rogtec Team @ 15:43  0 Comments

With the EAGE St.Petersburg taking place in April - what are you looking to achieve through this event?

We hope, as in 2006, that this will be a very successful meeting for all involved. With the current buzz surrounding the regions geo market we hope more people will be find the solutions they seek for their businesses. Basically, we are looking to put the latest technologies from the region and around the world in front of the end users.

What technologies do you think will steal the headlines at this year show?

Well that's a tough question . . . I think that simultaneous pre-stack migration, Q-technologies and sparse surveys are found to be the most important in geophysics - these will be among the technologies to look out for at the show.

With more and more international players looking to enter the regions geophysical sector, how do you see them integrating with local Russian competitors?

There are different methods to get integrated in the Russian geophysical sector and different companies chose different strategies. It looks likely that partnership with Russian companies may be a good option and we see more and more international companies taking this route.

What major investments are planned for exploration in 2008? And are there any state incentives for growth in this area?

Investments into exploration are numerous with most majors planning some sort of exploration spend. It also seems that the State is going to accelerate exploration in East Siberia to make sure that sufficient amount of oil is available the East Siberia - Pacific Ocean pipeline. It is a tremendously ambitious project which needs a lot of investments, hard work and luck in exploration and related activities

What regions do you see as being a hotbed of exploration activity in the coming couple of years?

Aside from East Siberia mentioned in the previous answer, a number of areas will prove to be exploration "hotbeds" in the coming years including Timan-Pechora, offshore Far East and Caspian - I think these areas are likely to of key interest in terms of exploration.

With the Russian artic being touted as the final frontier for hydrocarbon exploration, will the harsh and remote environment hold back exploration studies?

On the contrary, as I know almost all major oil companies are involved in studies of exploration potential of the Russian Arctic.

Of course explorers are going to face the most difficult, sensitive and challenging environment ever found, let's not forget the difficulties of working in such conditions. But despite these issues, interest in the hydrocarbon potential of this area will grow massively, providing new and exiting opportunities for regional majors and providing a huge market to the local and international geo-industry.

Even with such interest and potential, it will take no less than a decade to evaluate the full potential of this area.

Is there a demand for geophysical technologies on current brown field sites?

Demand for geophysical technologies in brown field developments will be on the rise for years to come. This is due mainly to the current state of affairs in brown field site and of course the strong oil price.

How will the marketplace have changed before EAGE St.Petersburg 2010 takes place?

I think it is clear that exploration developments are on the rise and that the oil business will be supporting many of us by EAGE 2010 and well beyond.

The Russian oil industry will become more consolidated and quality G&G services will be in greater demand with many new and exiting projects underway. Additionally the development of Russia's harsh and sensitive regions, a lot more emphasis will be placed on correct geo technology development.

Labels: EAGE, KONSTANTIN SOBORNOV, oil gas russia, rogtec, St Petersburg

posted by The Rogtec Team @ 15:23  0 Comments