ROGTEC Magazine - Russian Oil & Gas Technologies - News, Reviews & Articles

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ROGTEC Magazine - Russian Oil & Gas Technologies - News, Reviews & Articles

Baker Hughes Installs World’s First Ultra-Temperature SAGD Production System

Tuesday, August 31st, 2010

Electrical submersible pumping (ESP) systems designed to operate up to 250°C maximize production from SAGD wells.

HOUSTON, TX – August 31, 2010 – Baker Hughes (NYSE: BHI) has installed the world’s first ultra-temperature electrical submersible pumping (ESP) systems in steam assisted gravity drainage (SAGD) wells in the Canadian oil sands. Nine Centrilift XP™ ESP production systems, which can operate at fluid temperatures up to 250°C (482°F), have been installed since April 15, 2010.

Calgary-based Cenovus Energy, currently field testing the system at its Christina Lake, Alberta, thermal project, is among the first to deploy the new technology. “We expect the more robust system to increase run life and minimize operational expenditures,” says Jason Abbate, a production engineer with Cenovus. “Because the ESP system is operated at higher temperatures than conventional systems, we can also expect higher oil production rates.” SAGD production specialists expect an increase in production with a larger steam chamber and less viscous oil at higher steaming temperatures.

The ultra-temperature ESP system design is the result of several years of intensive research and development in specialized testing facilities at Baker Hughes’ ESP product center in Claremore, Oklahoma, USA. The one-of-a-kind testing facilities allow Baker Hughes’ research and development engineers not only to design and test ESP equipment at temperatures up to 300°C (572°F), but also to simulate the horizontal orientation and temperature cycling characteristics of SAGD wells. The tests conducted in the dedicated high-temperature test loop ensure that the highest levels of reliability are designed into the ultra-temperature ESP systems.

Baker Hughes instituted stringent manufacturing, factory acceptance testing, assembly and field service processes to ensure maximum reliability for these harsh applications. The SAGD ultra-temperature systems also have dedicated application engineering and technical support teams for this emerging market.

“Baker Hughes invested in the industry’s only testing facilities capable of simulating these intense temperatures because we are committed to expanding the technology boundaries for SAGD production systems,” says Mike Davis, president of Baker Hughes operations in Canada. “We anticipate this new robust system design will make a significant difference in infrastructure costs for SAGD wells that require these high temperatures.”



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The ROGTEC Interview: Paul Gielen, Regional Manager, Caspian Sea area, PPG Protective & Marine Coatings

Tuesday, August 31st, 2010

What is your position in the company and how long have you held this position?
My current position is regional manager, Caspian Sea area. As export manager I have been responsible for sales in Turkey, Libya and the Caspian region. Now I will focus fully on the Caspian region and the set up of PPG Protective & Marine Coatings’ regional office in Baku.

How long have you been in business in Russia and the Caspian?
Our company has a heritage of producing paint for 300 years and we have been in business with Russia and the Caspian for a long time. This year we have decided to strengthen our leading global position by setting up a regional office in Baku and expand our strategic stock points throughout Russia, the Caspian region and Turkey.

PPG have recently opened an office in Baku – how is that going? And how does that affect your regional strategies?
PPG Protective & Marine Coatings is a truly global organisation and recognized the need for a regional support organisation. Together with our authorized distributor network in the region, we are dedicated to provide our Caspian client base with a top-class service and tailored technical and supply solutions.

What companies have PPG worked with in the region?
Our international engineering team works together with all major international oil companies and engineering houses, and makes sure that we are approved by both international and national parties, and that our coating systems are in accordance with internationally recognized standards (like Norsok M-501 and ISO-12944). We have an extensive track record in the region, and have supplied projects of Tengizchevroil, Agip KCO, Azerbaijan International Oil Company (AIOC) and many others.

What is your most recent success in the market?
Besides supplying coatings to some of the most important onshore and offshore oil and gas projects, the current opening of our Baku office is a very important milestone for us.

Have you any recent product launches for the region?
We offer a range of innovative solutions for the oil and gas industry, which have already proved their value. Our solvent-free epoxies from the SigmaShield range are widely valued, as are our high-performance tank linings from the Novaguard range. The most recent and dramatic innovations have taken place in the field of passive fire protection. PPG Protective & Marine Coatings is one of the main players in this area and is introducing its world-leading flexible epoxy intumescent coating from the PITT-CHAR XP range for the Caspian oil and gas industry.

Having re-located to Azerbaijan, what do you like best about Baku?
Although I have been in Baku for a short time I am very impressed by the hospitality, and helpfulness of the people here. I have already made some good friends, so I feel it will not be a hard job to feel at home in Baku.

Where in the world would you most like to visit and why?
South Africa is on the top of my list. I am fascinated by its natural beauty. Besides that, I cannot wait to visit the old cities along the Silk Road and the phenomenal Caucasus mountains.

What is your favourite sport, and what team do you support?
I am a football fanatic and hardly miss any game. The team from my hometown Tilburg (Willem II) is still closest to my heart, but having lived in Amsterdam for several years I will definitely support Ajax Amsterdam this season in the Champions League.

Finally, what are your thoughts on the region’s oil and gas market through to the end of this year and beyond?
Our firm commitment, with establishing our regional office in Baku along with our Moscow and Istanbul operations, already confirms our high expectations from Russia and also the Caspian Region’s growing oil and gas output. We believe the region will become increasingly more important for the energy demands in both the East and West.



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Increasing Recovery Through New Reservoir Management Concepts

Tuesday, August 31st, 2010

Olwijn Leeuwenburgh, Lies Peters, Frank Wilschut, Remus Hanea,
Oscar Abbink and Peter van Hooff, TNO

Increasing recovery by just one percent could add about 80 billion barrels of oil to global reserves. Oil companies have realized this potential and in response have expressed the goal to raise the recovery factor for their fields to as high as 70%. New developments in drilling and completion technology, as well as novel IOR techniques, will play an important part in realizing this goal. An equally important contribution will be delivered by the introduction of improved reservoir management concepts.

The typical current industry practice is that decisions on future field development are based on simulating future development scenarios on a single reservoir model, which has been matched to production data by time-consuming manual adjustment of a very limited number of reservoir parameters. In recent years, the realization has grown that future production scenarios should be tested on many geological realizations of the reservoir model in order to account for the inherent uncertainty in our knowledge of the reservoir properties on scales smaller than the inter-well spacing. Accordingly, many software providers have started to offer (parallel) simulation functionality that enables the reservoir engineer to simulate multiple geological scenarios. However, what has been lacking to a large extent is the possibility to adjust not just a select few, but all parameters and properties of the reservoir model, and to incorporate all available types of measurements in a more-or-less automated and consistent manner. For example, it is generally not possible to incorporate data from repeated seismic surveys by manual processess in a (geo-)statistically correct way. The development of new measurement techniques which generate very large numbers of data, including smart-well completions equipped with down-hole sensors, will pose serious challenges to existing company workflows for model history matching. Similarly, proper optimization of future production and development strategies requires approaches which are both robust to uncertainty and which can handle hundreds to thousands of controls (e.g. Leeuwenburgh et al., 2010). This will especially be important for so-called ‘smart’ or ‘intelligent’ fields, which enable much improved monitoring and provide many more control options than conventionally developed fields.

Closed-loop reservoir management
Research institution TNO, Delft University of Technology, and Shell International Exploration and Production in 2005 took the initiative, with the start of the ISAPP (Systems Approach to Petroleum Production) research program, to develop improved algorithms that will enable new reservoir management workflow concepts. Many methods for incorporating measured data with simulation models were explored and tested, and new concepts for integrating different elements of the complete workflow were pioneered, resulting in what has been called ‘closed-loop reservoir management’ (Jansen et al., 2009, see Fig.1). This concept introduces intelligence and integration to the standard company workflow, enabling the optimization process to be run at the ‘right time’, and with higher frequency.

Figure 1: The ISAPP closed-loop

Figure 2: The Brugge 2-phase benchmark model for closed-loop water-flooding optimization.


Figure 3: Results from the Brugge workshop on closed-loop reservoir management: improved history match quality (low error) tends to enable improved field development strategies and a considerable increase in realized asset value (high NPV). The red points are based on a history match over a longer time period than the blue points. The best results were all obtained with the Ensemble Kalman Filter (circles), while standard methods (squares) were found to deliver significantly poorer results.

These ideas were tested in an SPE workshop on Closed-loop Reservoir Management, held in 2008, for which the benchmark Brugge reservoir model was developed (Fig.2). The workshop results, documented in Peters et al. (2010), as well as subsequent studies, have validated the ideas behind the closed-loop concept, indicating that such an approach will result in more value, as measured for example by NPV or total recovery (Fig.3). Several clear conclusions could be drawn:

1.    The use of advanced computer-assisted history matching approaches provides improved consistency with both geological reservoir knowledge prior to history matching and with dynamic data.
2.    The incorporation of additional types of measurements, such as time-lapse seismic, in the history match improves the reservoir model.
3.    An improved set of reservoir models enables a more reliable (robust to uncertainty) forecast of reservoir value.
4.    The use of advances techniques for optimization of production strategy (scheduling) leads to higher value.
5.    An increased frequency of runs through the closed-loop (i.e. history matching and future production strategy or development optimization) provides higher value.

It has become clear than any serious effort to increase ultimate recovery will have to involve a change in reservoir management thinking along these lines.

An important element of the closed loop is generating a set of model realizations which are consistent with all available measured data, and which properly reflects the remaining uncertainty in the reservoir parameters. Companies tend to build ever larger and more complex models, accompanied by similarly increasing computing facilities. These models are becoming impossible to manage manually by a single reservoir engineer.

The incorporation into such models of large numbers of data, such as produced by seismic surveys or by wells equipped with down-hole sensors, will only be possible using computer-assisted methods. This will require both trained personnel as well as user-friendly software tools, enabling the reservoir engineer to spend his time instead on making better decisions.

Research has suggested that only certain scales, regions or aspects of the model may be relevant in matching the model to data, or in controlling the output of simulations of future development scenarios. This offers the potential to use clever up-scaling or model-reduction methods, which could significantly reduce computing time and therefore cost, and enable increasing the frequency of the loop, resulting in better results.

Finally, the subsurface characterization may be improved by incorporating data which is traditionally not typically used in the same way as production data are used. Within ISAPP new developments in this area have been in the use of time-lapse seismic, subsidence, gravity and bore-hole radar measurements. Challenges also exist in the design of surface and subsurface sensor networks for such soft-sensing data types, and in extracting the relevant information from the resulting data sets.

New reservoir management tools
Implementation has started of some of the new concepts and methods coming out of the ISAPP program into tools that can be integrated in the workflows of oil companies. An example is the history matching tool which has been integrated with the JewelSuite® modeling package. The tool consists of an Ensemble Kalman Filter which has been integrated with JewelSuite® property modeling functionality, to simulate multiple geological realizations. It enables the reservoir engineer to adjust all grid block properties and parameters of the reservoir model in a semi-automated fashion in order to achieve a history matched set of model realizations consistent with all production data. This tool is the first of its kind and operates with a host of commercially available reservoir simulators. It represents the first step towards a full implementation of all elements of the closed reservoir management loop in a single modeling package. It demonstrates both the feasibility and potential of a major new development in reservoir management outside of academia and research groups. Results obtained for the model depicted in Fig. 4 are shown in Fig. 5. Figure 6 demonstrates the value of a computer–assisted history match approach relative to a manual approach on predictions for a new well.

Figure 4: The new 3-phase channelized benchmark model for history matching and optimization developed by TNO. Porosity is shown. The first results were presented at the SPE Applied Technology Workshop, held July 2010 in Miri, Malaysia.

Figure 5: Results obtained with the integrated history matching workflow for the 3-phase channelized benchmark model. Shown is the product of permeability (K) and thickness (h) a) True Kxh. b) Initial Kxh before history matching, c) Estimated Kxh after history matching with the Ensemble Kalman Filter

Figure 6: Comparison between predictions of oil production and the realized production (truth) for a new well.

The workflow described above will be extended with functionality for computer-assisted development planning. The experience gained in the ISAPP program has led to the development of a robust ensemble-based optimization tool that can be used for automated optimization of both production scheduling and well placement.  An example for well placement optimization is shown in Fig. 7.

Figure 7: Optimization of well placement in a simple rectangular reservoir containing an L-shaped oil-trapping fault. a) Oil sweep resulting from water injection and production from initially proposed well locations. b) Oil sweep resulting from production of the field using optimized well locations. Super positioned are the displacement vectors of the wells with respect to their original positions. The improved sweep efficiency represents 10% increased oil recovery.

Future developments
TNO and Delft University of Technology are continuing the ISAPP knowledge centre and are currently inviting oil companies to participate. The main aim of the ISAPP-2 program will be to transfer the new concepts developed in the first ISAPP program to the world of real operations. To this end the program is looking for partners who are interested in bringing in actual assets in order to demonstrate the added value of these concepts and to incorporate the required tools within their workflows.

Many challenges still remain. Therefore, the ISAPP-2 program will additionally continue the fundamental and exploratory research on closed-loop concepts and computer-assisted methods. Partners will be able to participate in this research by close cooperation with staff members of the involved institutions. The ultimate aim is to enable 10% or more increase in recovery by introducing improved methods and concepts into the reservoir management workflow of companies. We believe that this goal can be achieved best by close cooperation between those involved in R&D and the engineers who will use the results in daily operations.

References
ISAPP-2 website: http://www.isapp2.com/

Peters, E. et al. 2010: Results of the Brugge benchmark study for flooding optimization and history matching, SPE Reservoir Evaluation and Engineering, p.391–405, SPE 119094.

Jansen, J. D., S. D. Douma, D. R. Brouwer, P. M. J. van den Hof, O. H. Bosgra, and A. W. Heemink, 2009: Closed-loop reservoir management, SPE 119089.

Leeuwenburgh, O., P. J. P. Egberts, and O. A. Abbink, 2010: Ensemble methods for reservoir life-cycle optimization and well placement, SPE 136916.



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Friction Reduction in Tight Gas Stimulation

Tuesday, August 31st, 2010

Mike Hurd – Technical Applications Manager, Kemira Oil & Mining

Global natural gas use is increasing as an efficient environmental alternative to oil and other liquid fuels. Production of tight shale gas formations is also growing to meet that demand and the related stimulation technology and chemistry required is developing quickly too. Heavy stimulation of these wells is needed and a significant part of that process is the chemistry used specifically for friction reduction. The efficiency of a hydraulic fracturing (frac) or acid job is directly related to the performance of the friction reducer (FR) on location and a surprising number of elements can affect that performance. The following article will review the major chemically related contributors to FR performance principally in ‘slick water’ type frac work where limited sand transport capacity is required. It concerns performance at the wellhead both during the treatment and where lasting effects can be seen.

Viscosity and Reynolds
Viscosity is actually the driving force behind friction reduction and molecular weight is the principle factor in the generation of viscosity. While there are some other factors involved, in general, whatever affects molecular weight effects friction reduction in the same way. Reynolds Number is one measure of this phenomenon since turbulent flow generates the highest friction in a flowing system. In a simplified Reynolds Number formula, R = DρV/μ, viscosity in the denominator has a great effect on the resulting degree of turbulence and therefore on the friction seen in the pipe. That said, calculations at the desk are one thing, but there are so many great, new products coming out that could become the components for a new frac fluid that some lab testing should be done. Viscosity data is good as interactions will show up there. Flow loop data through a fixed system though is the best, as it measures more closely the actual field events. There is debate on which setup is better, but there is no debate that loop data is better than anything else.

Polymers
The two chemistries normally used as friction reducers are guar (usually hydroxypropyl guar – HPG) and polyacrylamide (PAM) polymers. Variations and grades exist for both of these products that will modify performance somewhat, but improvement usually comes with a price. Since typical dosages range between 250-750 ppm (or 0.25-0.75 gpt) with thousands of cubic meters of fluid being pumped, more expensive options add cost to the treatments very quickly. Each of these polymers also has a couple physical forms that are often dependent on the freight from the manufacturing point or warehouse to the treatment location. Lower solids liquid or emulsion product is much easier to handle and use on location, especially if the footprint of the location allows for the inventory. Dry products are less costly in freight to location and may be the only option for platform inventory, but command additional equipment to put them in solution for use in the frac fluids.

Hot, Cold, and Salty
Similar products are already used in other areas of the oilfield and some of these characteristics may already be familiar there. Water salinity and well temperature are commonly cited as the biggest culprit to performance from typical polymers used elsewhere in the oilfields.  There are two big temperature concerns here with hot AND cold water. Cold make-up or surface water causes a delay in putting the polymers in solution. ‘Time to solution’ can be a critical factor since water at a temperature <5°C can require twice the time to put emulsions, dispersions, slurries, or powders into a pumpable solution, than they would at 25°. Liquids can invert or dilute relatively quickly, but cold water delays that reaction and hydration, often by several minutes for each step. Yet both of these must occur for the polymers to reach full viscosity in very cold water. If it only takes 20 minutes for the pumped fluid to reach bottom then every minute delayed in the hole reduces the benefit of the polymer as a friction reducer. Since warmer water or a method to produce it isn’t always available, emulsion or liquid polymers specifically designed for cold water inversion can offset any additional product cost by reducing the need for additional equipment on location to compensate for the loss in performance. Such as higher horsepower, or to work around the delay for hydration in the form of additional blenders and storage.

Dry polymers have the same hydration problem as emulsions in cold weather since hydration is also delayed here, but the consequences can be more dire. The timeline for hydration is considerably longer for dries than for liquids and emulsions, especially in salty waters. Un-hydrated particles of a dry polymer can lodge in the wellbore and plug off injection during the treatment, remaining even after flowback as formation damage. Various grades of polymer can have different particle sizes and that can also impact the hydration timeline. The larger the particle, the longer it takes to go into solution. Cheaper grades of polymers may also have higher insolubles in them which never go into solution regardless of temperature or salinity, but act the same as an un-hydrated particle of polymer in terms of formation damage. Finer grinds of higher quality dry products and better hydration techniques on location may be additional costs, but they are essential to treatment performance should the decision be made to use dry products.

We need to go back and pick up the discussion of hot conditions, too. High bottom-hole temperatures can also cause significant problems and need to be addressed. There are realistic limits on both guar and PAM’s. Guar can handle up to 100-125°C in fresh water while PAM’s can perform well in the same range. The additional conditions of the fluids also matter. Salinity, hardness, and pH all become more critical as temperature goes up. Here is where some of the modified polymers work well and the added expense may well be worth the cost. AMP’s copolymers of PAM’s are resistant to both higher temperature and salinity effects while additives and crosslinkers in guar can also boost their performance under these conditions. There is continued debate on the significance of bottom-hole temperatures and most models suggest that the high rate of surface water injection will serve to cool the reservoir several degrees and protect the fluids being pumped to some extent. If the bottom-hole temperature (BHT) is within 25 degrees of the perceived limits of the polymer the injection rate, particularly with colder surface water in winter, will save you the cost of higher temperature products. If the BHT is beyond 50 degrees over the product limits you’ll definitely need to have a high temperature package and plan.

As suggested above, salinity, defined by Total Dissolved Solids (TDS), plays an important role in the development of the polymer’s viscosity.  Different elements that make up the term ‘salinity’ have a different impact on the polymers themselves. Calcium limits the potential of both types of polymer to fully hydrate and build viscosity.

In careful lab observations of fresh water systems the effect can be seen on viscosity in as little as 50 ppm Ca. But performance effects in the field with all the other additives in the system aren’t typically seen until 100-400 ppm Ca is reached. Soda ash can complex the Ca and reduce the effect if it doesn’t interfere with other additives. In higher TDS systems (above seawater) chlorides tend to overtake the calcium as the problem forcing the basic PAM molecule to collapse on itself rather than hydrate fully. Some PAM polymers are being developed that can withstand a higher degree of salt, but guar tends to be less effected by monovalent salinity overall.

Biology
An additional concern that is growing in importance is biological activity and its relationship to these polymers in friction reduction. On the front end of these jobs there is a concern about ‘bugs’ in the surface water. Guar is particularly susceptible to a poorly designed biocide program with many species considering it a nutrient. Without a biocide program in place guar can lose viscosity within a matter of minutes depending on the bug population in the surface waters. PAM polymers aren’t as susceptible to the bugs even in highly populated fluids, but degradation does eventually occur.  So a good surface program is important regardless of the polymer you choose.

Hold that thought for a minute. In either case the downhole effects of the biocide added to protect your polymer in the surface can be equally remarkable or devastating on the success of the treatment long-term. Most of the bugs on the surface are aerobic (oxygen loving) in nature and a good biocide program will kill them quickly and easily. But guar and PAM still get pumped down the hole and introduced as a nutrient to an anaerobic (no need for oxygen) population in the reservoir. While the aerobic population would likely die in the anaerobic reducing environment of the reservoir anyway, the starved anaerobic population will now thrive with the thousands of cubic meters of nutrients that have been introduced. Consider that the downhole population usually consists of Sulfate Reducing Bacteria (SRBs), Acid Producing Bacteria (APBs), Iron Reducing Bacteria (IRBs), and others. That’s enough of a list when you consider that the SRBs generate hydrogen sulfide (H2S) which corrodes pipe and the other two corrode pipe directly. Biocides added at the surface have to also protect long-term. Gluteraldehyde and THPS are the typical biocides used in frac jobs and they kill quickly at the surface, but degrade as quickly with little or no lasting effect. Other biocides like DBNPA and quats offer quick kill and a little longer lasting effects, but may have some environmental issues associated with them in certain areas. TDTT offers good long-term kill, but is not particularly good at quick kill on the surface. Fortunately, some of these, like DBNPA or quats and TDTT can be dual injected to achieve both quick kill on the surface and long-term preservation down-hole.

Let’s go back to the surface treatment for a minute and look at the biocide effect directly on the polymer. While we are most concerned with whether biocides kill the bugs and protect the polymers there are also component reactions to consider within the fluid. It can get complicated here as new components, biocides, polymers, and fluid characteristics like pH are being introduced all the time. Gluteraldehyde and THPS, for example, are the most used biocides for surface water treatment, but addition of these products has an adverse effect on both guar and PAM polymer viscosity. Not a huge amount of degradation of course, in comparison to

having no biocide treatment at all, but DBNPA and quats offer quick kill along with TDTT for long-term kill without the degradation to the polymers provided pH and other components like clay stabilizers are also compatible. Since dual addition was mentioned be aware that even certain biocide interactions take place. For example BIT is incompatible with any aldehyde and TDTT particularly in water. At this point it is probably easier to say – make sure your chemistry suppliers are checking compatibility with the full set of chemistries you are trying to use on a well and have a logical alternative plan through the test work that gives you realistic set alternatives if you find serious interactions.

The previous paragraph makes it sound like there are no alternatives; picking the best of the worst to pump downhole. Compatibility testing can also find you some real synergistic improvements in the frac fluids of choice. For example, TDTT works well with certain emulsion PAM packages, offering 5-10% faster viscosity generation (remember ‘time to solution’) and 5-10% higher friction reduction from higher solution viscosity. The ultimate result can be a lower dosage of polymer that still gives higher performance in the end. TDTT also appears to extend oxygen scavenger performance driving ORP lower into the reduction values than other biocides which lower oxidation potential and reduces short-term corrosion and long-term deterioration of tubulars. Again, nothing replaces data run with the actual set of components in the frac fluid compared to a few alternatives.

Conclusions
This is not an exhaustive list as you well know if you’ve done this work already. There are reservoir engineering and mechanical factors to also consider as well as the economics of both the gas being produced and the service being performed. This was only intended as a check list to remind us of some additional considerations in designing and developing frac jobs. One last reminder – nothing can replace data and the continued search for a new way of doing what needs to be done to produce tight gas. The growth of the market itself in the last 10 years is proof of that!



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ROGTEC Technology Roundtable – Fracturing

Tuesday, August 31st, 2010

Michael Tulissi: International Technical Director for Fracturing Services with Trican Well Service

Andrey Smarovozov: Director, Pressure Pumping, Russia & Caspian (Marketing and BD), Baker Hughes

Kevin Mullen: Senior Production Stimulation Engineer for Schlumberger-Russia

Igor Kuvshinov: Senior Technical Leader, Halliburton Company

What are the most important aspects to consider when designing and implementing a frac job?

Michael Tulissi: It is most important to consider the desired fracture geometry and conductivity, as well as the optimum economic yield. The design will be dependent on accurate data concerning formation permeability and pressure, a clear understanding of rock mechanical properties that affect the created geometry, and current well conditions such as damaged and undamaged reservoir parameters.

The design must strive to eliminate failures and include an understanding of the fracture cleanup process, as well as the relationship between propped fracture length and the effective producing fracture length that are, in practice, very different. To this end, experienced operators, comprehensive Quality Control and reliable equipment are essential.

Andrey Smarovozov: When designing, the most critical  aspects for accurate Frac design would be well readiness (ie casing and cement condition), formation data, including rock properties, formation and fluids parameters. Having the reliable data would significantly increase the accuracy of the design, thus optimizing the individual treatment for the specific well. While executing a frac job, the most critical areas would be QA/QC control and the flexibility within the chemical additive system with each parameter being closely controlled. Saying that, I mean, that what’s stated from the prospective of the desirable result must be executed the way it was planned. The equipment should be flexible to allow varying each of the individual components to keep the fluid system optimal and at minimal cost.

Kevin Mullen: A frac treatment design should be as individual as one person is to another. The most crucial element of designing a job is to take all well characteristics into consideration while determining the optimal geometry for that specific well to optimize production. This includes determination of where the fracture should be placed, to what extents the frac can grow, and how much proppant is required for adequate conductivity. A simple example is designing a frac that is large enough (by mass and width) to produce effectively, but small enough (by shape and volume) to avoid stimulation of nearby water layers.

Igor Kuvshinov: Having a sufficient amount of basic knowledge of the rock and reservoir properties allows you to solve the fracture geometry, general speaking.  Some Operators readily accept this and do not want to go beyond this basic level. However only a detailed analysis of the data regarding the rock mechanics, reservoir fluid and PVT data allows you to solve the question whether the selected fractured completion will have sufficient long-term conductivity to produce the reservoir to the targeted degree. The wisest option for the Operator is to select the full analysis approach because of the increased return in the mid to long term.

Formation damage is one of the greatest dangers during a frac. How can you minimize the risk of formation damage during the job?

Michael Tulissi: Fracture treatments can result in two types of damage: damage to the formation itself and damage to the conductivity of the proppant within the fracture. Formation damage can be mitigated by proper compatibility testing of frac fluid/additives with formation rock and fluids, as well investigating suspected damage from previous treatments. Damage to the proppant conductivity can be minimized by reducing the amount of polymer based gel, using improved breaker technology, better post fracture clean-up procedures and the inclusion of nitrogen in fracturing fluids.

Andrey Smarovozov: There are several ways of minimizing fracturing fluid formation damage factor, (as well as a proper stress proppant application is a must):

1.    Low polymer loading systems (such as BJS’s QuadraFracТМ which allows us to decrease polymer loading down to 18-20 ppg from 30-35ppg system) with similar proppant carrying capacities.

2.    Application of polymer-specific enzyme breakers (this allows to the increase of frac gel break of up to 98% as opposed to an average of 30-40% in a normal guar-borate system with oxidizers as a breaker)

3.    Polymer-free frac fluids, which contain no polymer make “filter cake” fracture damage theoretically impossible. Chemical processes of formations being affected by water should not be left out of consideration either and should be closely controlled.

4.    Foamed fracturing fluids allow you to reduce the total amount of polymer left in the fracture, simultaneously helping the process of well clean-up and kick-off. However, since the volume of guar-borate fluid is reduced in foam (the remaining is nitrogen), maximum effective concentration of proppant in a fracture volume is limited.

Kevin Mullen: Formation damage can be extremely detrimental to well production, but these problems can be easily managed by proper pre-treatment analysis and design of the breaker package to degrade the frac fluid. To avoid any potentially irreversible problems, it is strongly recommended to test in the laboratory the interaction of formation fluids (oil and water), the fracture treatment fluid, and even wellbore fluids (such as work-over brine). If incompatibilities are observed, then the treatment fluid recipe must be adjusted with inhibitors to impede those effects. Testing against formation rock may not be practical, so a clay stabilizer should always be present in the recipe. Finally, an aggressive breaker package must be tested and included in the fluid design to minimize residual damage.

Igor Kuvshinov: The ability to provide best-in-class stimulation treatments comes not only from the total horsepower in delivering proppants downhole, but from an educated knowledge of the overall picture, allowing you anticipate problems and successfully engineer ways around them in order to target long-term fracture conductivity.

The best way to minimize the risk of damage during the job is to design a fracture target conductivity based on all relevant data, while tailoring frac fluid  and ensuring complete frac clean out shortly after the well is in production. Knowledgeable service companies work over every aspect influencing the conductivity of the final fracture, including chemicals, materials, placement techniques, etc. in order to ensure success.

Do you have any new technologies which are being deployed in the Russian oilfield?

Michael Tulissi: Trican is a technical leader in the pressure pumping industry and customers worldwide are benefiting from these innovations. In Russia, these include:
»    Multistage Frac System (Selective fracturing of horizontal wellbores)
»    IsoJet (Selective fracturing using jet perforation through coiled tubing)*
»    DRA-2 (Delayed Release Acid Breaker)
»    WCA-1 (Relative Permeability Modifier for water conformance)
»    SI-3 (Scale inhibitor pumped during fracturing operations to reduce scale build up and pump damage due to deposits)
»    Stratum Frac (Ultra low polymer fracture fluid providing superior shear stability and proppant carrying capacity)*
»    PropLock (Proppant Flowback control)
»    Various fracturing fluids including Nitrogen

These products were developed in Russia to address local requirements.

Andrey Smarovozov: With BJ being part of Baker Hughes now, the following technologies of theirs are planned for use in Russia:
»    QuadraFracТМ low polymer loading system is going through field trial tests.
»    Polymer-specific HPHT enzyme breakers can be widely implemented.
»    Polymer free frac fluid system – AquaStarТМ (surfactants system) was delivered to the country and  is planned for a field trial.

Kevin Mullen: As one of our core values, Schlumberger understands the value and importance of technology. And we are exceedingly proud of the manpower and funding we annually put into research. In Russia, at different points over the last 6 years, we’ve brought several frac technologies including FiberFRAC*, foamed frac fluids, and AbrasiFRAC*; these focus on frac geometry and operational efficiency. In the next few years, as multi-stage fracturing in horizontal wellbores gains in popularity, StageFRAC* will become a more common fixture in the market. But we are most excited by a revolutionary new technology coming soon! Look for HiWAY* to be rolled out this fall season!

Igor Kuvshinov: Halliburton’s Pin-Point Stimulation group of technologies for multi-stage fracturing combine well with known technologies such as hydra-jet perforating, fracturing and coil tubing to achieve precision placement with full fracturing technologies that significantly reduced completion time. Some of these technologies  (CobraMax, Surgifrac and DeltaStim Completion) have been deployed in the Russian oilfields since 2004. Waterfracturing is incorporated as one of efficient proppant placement technologies but has not been deployed in Russia operations yet. In order to promote long-term conductivity and reduce proppant diagenesis phenomena, Conductivity Endurance and Monoprop technologies can be deployed.

To what extent are open hole multi-stage frac jobs being carried out in Russia?

Michael Tulissi: Though still in developmental stages in Russia, the application of open hole multi-stage frac technology will certainly increase as horizontal well lengths increase, and the average permeability of the targeted formations decreases. In these cases, the technology will also improve the economic advantage of horizontal wells relative to traditional vertical completions. Trican has extensive experience in open hole multi-stage fracturing and is prepared to expand operations of this nature into each of its geographic regions.

Andrey Smarovozov: Several common technologies for open hole multi fracturing were tested as field trials. The technologies are more or less similar and are represented, for instance by: BJS (DirectStimТМ), Baker Hughes (Frac-PointТМ).

Kevin Mullen: This completion method has yet to take firm root in Russia at this point, but there has been significant interest in the technique of late. Several operating companies are just beginning to trial multi-stage fracturing, and I suspect that others are eager to follow. The trick behind this technique is to effectively segment off the horizontal section to allow for control over the fracture initiation point. Current completion strategy in Russia (commonly slotted liners) does not allow for control over frac placement. So in order for multi-stage fracturing to take off, completion designs will need to be altered significantly.

Igor Kuvshinov: The application of open hole multi stage frac operations are still in their infancy in Russia. However there is a growing interest among the major producers to open hole multi stage frac technology. You could reflect that the reason for this is that growing demand is making low permeability assets profitable. Several of the above mentioned technologies have been trialed and accepted for wider implementation.

Post frac analysis can readily identify whether the frac job has been a success. What is the level of uptake of post analysis in the region? (What would need to change in order to improve this?)

Michael Tulissi: Post frac analysis is performed to evaluate a treatment and help design the next one. It refers to the analysis of the fracture treating pressure and the obtained production rate, and are both performed routinely. However, this method can be unreliable as the results are not unique. More accurate analyses, such as flow and build up or pressure transient analysis, are performed quite infrequently. These latter tests are time consuming and require an interruption of the wells production, making them less desirable. To improve broad acceptance of post frac analysis, a desire to design, execute and evaluate fracturing treatments in a holistic way rather than as independent processes is required.

Andrey Smarovozov: One of the objective factors of a successful frac operation is a post-frac production and its match with the designed pos-frac production rate. Although all the largest Operators in Russia conduct post-frac analysis (and in some special cases it’s actually a must) the extent of post fracture analysis could have and should have been larger. Further more, to improve and optimize a frac job a data frac is conducted prior to the main frac treatment with post data frac analysis on location followed by the main frac schedule adjustment.

Kevin Mullen: It is Schlumberger’s policy here in Russia to make an individual post-frac analysis on 100% of wells in which we perform a propped fracturing treatment.  We do net pressure matching to validate the fracture geometry which we’ve created, and together with the pre-treatment calibration test data, we’re able to improve upon our fluid and rock modeling in subsequent job designs. Pressure matching does provide a reasonably good assessment of actual fracture geometry, but the accuracy can be improved through analysis of either bottom-hole pressure data or by direct measurement of fracture height using our SonFracMap* service.

Igor Kuvshinov: Post frac analysis in Russia is not yet receiving sufficient attention yet. Despite of significant advances in region in achieving understanding of fracture geometry the improvement is needed. That is especially true for those companies who decide to make step change in understanding fracture geometry for purposes of generating efficient oilfield-wide reservoir fracture assisted drainage system, with the aim of maximizing hydrocarbon production.

With the above target in mind, it is very important to utilize the best available modeling practices to identify the response of the rocks and resulting geometry at an early stage of field development. The pressure matching approach that is currently used alone is not sufficient for throughout analysis. Pre-treatment specialized diagnostic pumping and microseizmic fracture mapping are well recognized techniques, and are mandatory for correct fracture geometry analysis. The long-term performance of fractures should be much easier to forecast when analysis is completed utilizing above data.

Waterfracturing is not being fully implemented in Russia as yet. As the region develops it’s shale gas reserves do you think this technology will be utlised in the region? What benefits will it bring over the current solutions?

Michael Tulissi: Waterfracturing is a low cost, virtually non-damaging method of fracturing wells where only low fracture conductivity is required. In the Russian region, few reservoirs are currently being developed with permeability that is low enough to benefit from waterfracturing. We expect that as very low permeability shale reservoirs begin to be exploited, this technology will become better utilized.

Andrey Smarovozov: That is correct, since CBM or tight gas formations are not being developed in Russia, slick water fracturing or fracturing with Light Weight Proppants application are not used in Russia for now. The benefits these technologies could bring would be minimized fracture surface damage with maximal reservoir fluids reserves being evolved into production. That means conventional type of fractures opening hydraulically additional reservoir areas at longer distances from wellbore with minimal residual formation damage.

Kevin Mullen: Different reservoirs require different characteristics for their hydraulic propped fracture.  The shape and size of any propped frac is exclusively dependant on the fluid and rock properties of the reservoir.  For the low-mid permeability oil formations typically targeted today, the current techniques are preferable.  If exploiting shale reserves become prevalent, then high-rate water fracturing might also become more popular in Russia.  But the main question that any operator and service company needs to first ask themselves before deciding is “what geometry can this technique provide, and how much does that directly affect the well’s production?”

Igor Kuvshinov: Waterfracturing could definitely improve results in shale development in Russia. Some of the major benefits of this technology would be the distribution of propping agents and the use of low-damaging fluid. The benefits could be more visible for gas reservoirs, however oil reservoirs will see improved production as well. This is however true for any new technology introduced.



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SMART FIELDS OF SALYM

Tuesday, August 31st, 2010

Salym Petroleum Development (SPD) has equipped its well stock with Smart Field technology that allows real time remote monitoring and control of the produced oil and injected water.


From the very first day of operation of the Salym oilfields, SPD has placed high emphasis on regular monitoring for oil production and water injection, watercut and bottom hole pressure. This data provides important information to help improvement of well performance and reduce costs.

Until recently, measurements of flow rates and watercut were carried out on a daily basis on all well pads. In addition, fluid samples were taken on a weekly basis to identify watercut in laboratory conditions. Sensors, for continuous bottom-hole pressure and temperature tests, were installed in every production well. Key production and injection wells were also equipped with special high resolution downhole gauges which provide continuous record  of high quality pressure data. All production data, including the information obtained during well development and work-over operations, were entered into the oil-field database. However, the situation has changed recently. Whereas before operators used to regularly visit well pads and managed to service 15-20 wells, nowadays the operator spends most of the time in the office, being responsible for 30-40 wells. This has become possible due to the implementation of “smart fields”. This Smart Field technology is part of a major project in SPD on well and reservoir management, focusing on the development of a comprehensive approach to field development. Smart Field technology allows real time data transfer from wells to the control unit. Consequentially, the number of operator visits to the well pads decline considerably, allowing the operators to respond faster to the performance of the well equipment. Thanks to this Smart Field technology, SPD is able to use the increasing scopes of its well stock more efficiently, cutback on operation costs, optimize water injection, boost production and increase flow rates. The result is a continuous improvement in planning and more cost effective oil production within the framework of the whole oilfield.

SPD launched a Well and Reservoir Management project in 2008, when two well pads in West Salym field were equipped with Smart Fields technology. The results of this cutting-edge Smart Field technology proved successful. Well data became accessible at Central Processing Facility (CPF) in real time, which considerably reduced works on manual data acquisition and data entry. Furthermore, due to the decrease in the number of unscheduled breakdowns of the well equipment, the run life period of electrical submersible pumps (ESP) increased as well as production volumes.

In 2009–2010, SPD implemented a full-scale project on Smart Field technology in entire well stock. This was a first in Russia, and indeed among Shell. SPD specialists have successfully equipped all injection and water supply wells in Salym fields with Smart Field technology for water production, injection and preparation – Fieldware Water Injection System. Any employee of the company that has access to the smart fields system has the opportunity to monitor and change the parameters and levels of injection and production from the water reservoirs, as well as supply and pressure parameters of electrical submersible pumps in real time.The system is accessible both from the Salym field itself and from the Moscow office. Similar Smart Field technology has been implemented in all production wells of the Salym group of oil fields. A network of smart technologies – Salym Fieldware Production Universe, Fieldware Well Test and Fieldware ESP – allow for remote monitoring and control of ESP operations and well tests assessment with the confirmation of the results and receiving of a signal on the fluctuation of parameters from the normal operation range in real time.

Integrated Production System Modeling software was launched in the Salym oilfields to improve oil production planning. Production wells, including water intake and water injection systems, have been equipped with this software.

The information system Andon Board has been developed and introduced within the framework of this project. This system helps to monitor in real time the fluctuations in the well performance using traffic light system. If the performance indicators of any well fall outside the adjusted range, the operator will immediately receive an automatic notification via email. This allows the operator to find a solution immediately, and improves the process of oil production and water injection.

The implementation of Smart Field technology allowed SPD to create an integrated production model, which represents a reliable foundation for further projects targeting oil production growth. This system allowed the whole well and reservoir cycle to be integrated in one loop. SPD specialists receive information in real time, process this information using well stock integrated control instruments, identify the corrections needed for each well via an automatic control system.

Optimization of oil production, enhanced oil recovery, reduction of operating costs – all these are the results of the introduction of Smart Fields technology systems in the Salym group of oilfields. Thanks to this, SPD has managed to improve production by 2–2.5% per year on average and reduced unscheduled downtime, and the average failure free performance period of the well equipment has increased. Chemical additives have also been reduced, as have the number of trips to the oilfield, which has not only reduced the costs, but also minimized the risks for the employees while travelling on infield roads. All this, in its turn, resulted in the improvement of the overall performance in the oilfield.To date, SPD is working on the next stage of implementation for further contro technologies. All production wells are being equipped with automatic echometers. The operators will be able to remotely monitor the level of liquid in the casing-formation annulus, and, if corrections required, change the parameters of the electrical submersible pumps with the help of the smart oilfields. The application of this equipment will further increase production and reduce costs.



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Remote Well Monitoring at Rosneft

Monday, August 30th, 2010

А.S. Malyshev, A.A. Pashali, (NK Rosneft OJSC),
С.Е. Zdolnik (RN-Yuganskneftegas LLP),
М.G. Volkov (RN-UfaNIPIneft LLP)

Introduction
Many oil companies around the whole world have the same problems in common – declining oil production, cost escalation, complications of the geographical conditions for oil production, deterioration of hydrocarbon reserves and quality, shortage of experienced personnel and a high level of ambiguity in the data used for decision making.

One of the ways for solving these issues is the introduction of new engineering techniques and technologies, including computerisation and electronic communication development of the production process. At Rosneft, we place high emphasis on this line of development. This article deals with the remote monitoring of production wells – an approach developed within the framework of a Remote Monitoring Centre on the Rosneft-WellView Platform project and New Technologies Systems (NTS) of Rosneft. The perspective of the remote monitoring system in the structure of oil producing companies is described in this article, with a method for the classification of these systems proposed. Current achievements and future development perspectives for remote monitoring systems in Rosneft are also discussed.

Comparison of Monitoring Systems Worldwide
The review of world-wide experience in the development of  remote monitoring systems (Table 1) shows that it is possible to distinguish five levels of “ideal” monitoring systems, beginning from the acquisition and transfer of data on the operation of equipment and finishing field development optimisation. The ideal monitoring system, consisting of five levels, is presented in the form of a pyramid in Fig 1. We shall examine monitoring systems for wells equipped with Electric Submersible Pump (ESP) in detail.

Level 1 provides for the acquisition of on-line data from the operation station of ESP’s and other sources and the transfer of these data via a communication channel to a reference station. Telemetry systems executing level functionality have been used by the company for a number of years and proved their efficiency for the operational management of the deposit fields. Often however, only 20% of data is used for decision making.

Level 2 provides for data consolidation from various sources (Database (DB), software systems (SS) used in the affiliated companies), preparation of reports based on the data and their visual presentation, for example oil production profile development. Reporting development systems have been also acquired with wide recognition.  Often, for the solution of specific tasks, a new system for reporting development is created resulting in a large number of such systems and, consequently, the problems with their replication and standardisation.

Level 3 provides for data processing designed for detecting extraordinary situations and abnormalities in the work of the equipment and the well. Means of this level allow for detection and localisation of problem wells and for the consolidation of the data required for their analysis. These systems are less known. Usually, such analysis is carried out manually using Excel. This is due to the fact that an expert is required to identify a problem, to collect data from various sources and to confirm the existence of a problem, its importance and the need for response. The best monitoring systems contain elements on which experts are able to identify problem wells.

Level 4 provides not only for the equipment operation analysis, but also for the well including the mine, to be used for the optimisation of the well operation; for example, reaching full production potential. This level requires a wide set of data not only on the operation of the equipment, but also on the well surveys. This level is executed by experts and multidisciplinary groups (Center of Excellence, and others) and is not significantly computerized (special software, not connected with lower level systems are used for the analysis of well and equipment operations).

Level 5 provides for due diligence of all factors influencing the operation of the oil field. Optimisation of an oil field in real time, even with the application of monitoring systems, is a complicated engineering task. A solution for this type of work is only at the development stage in most companies. In the majority of cases, the due diligence is carried out at the design stage, requiring a significant amount of time and recourses.

The most efficient systems, such as LOWIS [1], ESPWatcher [2] in the computer-based mode provide for the solution of tasks of first, second and, partially, of third levels. For the solution of higher level task design groups are required.

Rosneft have several software systems for data collection and data analysis with their areas of application, often overlapping. For example, the analysis of data on oil production is carried out at the production enterprise RN-Dobycha, which allows data to be accumulated on the operation of a well required for the preparation of monthly reports on oil production. The system is used for planning maintenance on the wells. Production enterprise CDS, which has a large number of modules for the solution of various tasks on oil production monitoring, has a role within the monitoring system. On-line data on equipment operation (currents, pressure from the telemetering sensors) are stored in archived files.  Production enterprise EPOS has the role of a record keeping system for the well equipment and to store the results of the analysis of the equipment which failed during operation.

To carry out due diligence analysis of the operation of a well equipped with Electric Submersible Pumps (ESP) the data from all the above mentioned sources is required. This makes monitoring the ESP very complicated and requires considerable expertise. As a result, on frequent occasions, it never comes to the solution of the issue of the optimisation of the development on the basis of the data on the work of the equipment.

In connection with the above, within the framework of the New Technologies System (NTS) project, Rosneft assigned a task to create a comprehensive approach for the development of the ideal monitoring system for well operations. To date, a system has been created which covers the first three levels. During the course of project implementation it was confirmed that the system
was effective.

Well Operation Monitoring in Rosneft-WellView
In 2007, the Remote Monitoring System project, Rosneft-WellView Software System (SS) was developed (Pic. 2). This System pallows for data acquisition from various sources, including on-line data from the ESP Control Station, both in automatic (provided relevant equipment is available) and in manual mode (with the application of the archived files) [3].


The system performs the following functions:
» data collection from the wells from their initial processing, structuring and entering into the database;
» data aggregation from various DB;
» identification of wells with deviations from the normal  operating conditions;
» approximate analysis of the well operation with  allowances for the complicating factors and history of work;
» development of analytical reporting.

Further, we shall examine the specifics for implementing tools of various levels, included in the Rosneft-WellView Software System, in detail. Specifics of the Data Collection System (First Level Functions). To monitor and analyse the mechanised well stock it is necessary to provide the required data. For this purpose the visualisation of data dynamics archives from the frequency-regulated drives and the submersible pumps control station were made available.

For example, currently RN-Yuganskneftegas uses a multitude of various ESP control station models of various generations from six different manufacturers. For the on-line and effective use of the information it is necessary to have the individual software for each model of the control station, which considerably complicates the acquisition and the analysis of the important information for the identification of well problems and the equipment. Ways of viewing the archived data from the control station, which are assembled by the service companies providing maintenance for the submersible and surface equipment, has been implemented in the Rosneft-WellView Software System and is now being refined. Data is consolidated on the corporate servers on the basis of the approved schedule and viewed in the Rosneft-WellView Software System without any additional software, which allows for unit analysis operation and planning of effective maintenance to minimize any loss of oil production. At present, Rosneft-WellView Software System allows data to be analysed from the control stations and frequency-regulated drives of 17% and 41% of the mechanised well stock of RN-Yuganskneftegas LLP and RN-Purneftegas LLP, respectively.

Computer-Aided Manufacturing for Report Preparation
(Second Level Functions)
Engineers, in collaboration with the specialists at RN-Yuganskneftegas LLP, carried out expert analysis of the labour required for the provision of the oil production processes at service department level. The results of the analysis are shown in Table 2 below.

It was established that an average of 900 man hours per month are used for report preparation and analysis of the existing decline in production at RN-Yuganskneftegas LLP. The colossal amounts of man-hours accelerated the process for the development of the computerised reporting system for the determination of well production rate decrease on the basis of the Standard Production Factor Analysis (SPFA) algorithms, developed by the corporate Scientific Research Technical Centre Rosneft. High repeatability of the computerised and the traditional manual reporting was confirmed by the geological and technological departments of RN-Yuganskneftegas LLP (Table 3).

At the following technical meeting of one of the affiliated companies a decision was taken, on the basis of the project results, to continue the works on this project in order to find the solution of the current tasks, release of the additional time to be used for the qualitative decision making on the complicated issues and self-improvement of the geologists and production engineers.
Monitoring System Analytical Unit (Third Level Functions)

During the development process of the top level analytical software, specifial attention was paid to the application of the high-performance algorithms for data visualisation. TreeMap [4] (Pic. 3), which allows for the simultaneous presentation of a large number of the prioritised objects on one screen, is used to display data on a many different wells. According to the feedback from the users, this algorithm has been successfully implemented in the software and provides an increase in its efficiency.

Effective visualisation software represents the third level tool, designed for the solution of the monitoring tasks (identification of wells operating outside the range and requiring close attention) and diagnostics. The monitoring window is broken down into objects depending on selected parameters (oil production rate, type of liquid, oil losses during repair, water cutting, etc).  Box sizes corresponding to the individual wells are proportional to the liquid rate. The colour of the box represents the achievement of the oil production potential. The boxes are grouped per oil deposits fields. Pic 3 shows information on over 500 wells.

For the visual display of detailed information on individual wells, a mapping method called “a rose of problems” is used – a third level tool showing the status of the total object. A simultaneous display of the dynamics of the technological and electrical parameters allows for the simultaneous analysis of data (the second level reports on the acquired information). All diagrams are scalable for convenience.

The software allows the current operating point to be assessed with reference to the nominal use-flow characteristics with the allowance for gas degradation, wear and properties of well fluid, which is realised as monitoring criteria, and also for the analysis of the group of wells selected by the user.

In the window specifying the well a “rose of problems” on the well is displayed, which shows the level of various well issues, the position of the current operating point on the electric centrifugal pump performance diagram,  dynamics of the main performance data of the electric centrifugal pump (three groups of diagrams: dynamics of well performance data, technological and electrical data) and a no-failure operation time of the electric centrifugal pump unit.

The signal in the software provides the user with the instant information on the changes and deviations of the selected parameters.

During the development, the Rosneft-WellView ESP monitoring system was introduced into the following affiliated companies of Rosneft: RN-Yuganskneftegas LLP, RN-Purneftegas LLP, RN-Sakhalinmorneftegas LLP and RN-Stavropolneftegas LLP.

Administration – Remote Monitoring Room
(Fourth Level System)
It is not yet possible to optimise oil production without the participation of experts. The Remote Monitoring Centre (RMC) was proposed as a solution in conjunction with the remote monitoring systems of NK Rosneft. The RMC allows for on-line collection of all data required for analysis, tools for engineering analysis and the presence of experts, able to make a decision using the system. Currently, this Centre may be a long-distance from the wells, and may be a short-distance to the centre where there are experts and available capacity to analyse thousands of wells at the same time.

When analysing world-wide experience during the development of the RMC,  the following key factors for their successful introduction are the following:
» ability of the RMC to make decisions on well operation, which requires experts and company management support;
» on-line access to the consolidated information on the well operation, where it is preferable to have a computerised data collection system.

Therefore, in order to facilitate the integration of the oil production affiliates of the company into the existing structure, an approach was proposed for the organisation of a decentralised RMC (Pic. 4). The following tasks had to be solved:

Visual display of losses (in interactive mode):
» identification of fluid and oil production decline;
» notification of oil and gas production departments (OGPD) on the deviation of the performance benchmark for the real-time response (according to the individual settings of the user);
» proximate analysis of the well, diagnostics of the current status, identification of reasons for failures;
» management of priorities (higher flow-rate wells  must be put into operation first).

Search for reserves:
» visual display of the reserve source failed to achieve a potential;
» auto-summaries – templates for the preparation of procedures (initial data processing for analysis). Optimisation of response procedures:
» analysis of well and well equipment operation mode;
» forecast for ESP work on the basis of monitoring of its parameters;
» support for decision making while working with the mechanised well;
» automatic mode selection for automatic re-closing (ARC).

Pic 4 shows the interaction of RMC with the Central Engineering Board (CEB), Main Board for Oil & Gas Production (MBOGP) and Board for Production Improvement of Reservoirs and Work-Over Programs (BPIR & WOP).

The following are the advantages of the decentralised system of interaction:
» non-existence of additional personnel in the affiliated company;
» individual work of the technical support specialists in each centre with the accent on their key tasks;
» automatic summaries (elimination of non productive time) and recommendations on key categories (gold fund, automatic re-closing, etc.)

In this interaction pattern, the rating of influence to the decisions is average, at the level of recommendations, which assumes the interaction under the conditions of the organisation with properly adjusted and smoothly running business procedures and with a high number of qualified specialists.

Summary
Development of the monitoring system for ESP is a complicated multidisciplinary and comprehensive task. Its multilevel representation allowed us to identify several stages of work and to demonstrate the effect on each of the individual levels.

RMC is a large integration project of the New Technologies Systems of Rosneft, covering such areas of activities as the remote control of ESP, analysis business procedures, optimisation of oil & gas production processes, development and introduction of competitive equipment for monitoring and optimisation. The results of the pilot project implementation are as follows:
» reduction by 10% in failure to achieve the potential oil production rate (based on the results of Rosneft-WellView project tests);
» downtime reduction by 50 %;
» man-hour reduction due to the introduction of auto-reporting on the decline in production (97% precision) and auto-reporting on the definition of well-candidates for stimulation of oil production (99 % precision).

In the future, the project is planned to develop in the following directions:
» field equipment performance efficiency monitoring;
» consideration of restrictions on the surface equipment;
» analysis and optimisation of bottom hole oil pumps;
» optimisation of the system for maintenance of reservoir pressure.

Existing software, planned developments, scientific research and the accumulated experience of the project working group shall be integrated into the oil production process of the main affiliated partnerships of the company in the future.

To achieve maximum efficiency of RMC is the connection of the controlled well stock to the monitoring system. This will allow for the immediate acquisition of the complete data set on the operation of the equipment in real time enabling fast and qualitative decision making and to remotely assign the required mode of operation.

Reference Material
1. Weatherford. LOWIS™ Life of Well Information Software. http://www.ep-solutions.com/solutions/Software/LOWIS.htm
2. espWatcher. A service for remote real-time surveillance and control electrical submersible pump systems.

http://www.slb.com/content/services/artificial/submersible/espwatcher.asp.

3. Real Time Optimisation Approach for 15,000 ESP Wells

S. Zdolnik, A. Pashali, D. Markelov, M. Volkov//SPE 2008.

4. Shneiderman B. Tree visualization with Tree-maps: A 2-d space-filling approach.
ACM Transaction on graphics. – 1992. – Vol. 11. – № 1. – P. 92-99.



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Deriving Business Value from Implementing WITSML

Monday, August 30th, 2010

Dr. Julian G. Pickering, Director, Digital Oilfield Solutions
Randy W. Clark, President & CEO, Energistics

The Wellsite Information Transfer Standard Markup Language (WITSMLTM) enables the upstream oil and gas industry to communicate wellsite information efficiently. The benefits for adopting a standardized approach to exchanging drilling information are intuitive for most drilling engineers and managers in the industry and usually include the following reasons:

»    WITSML allows energy companies to leverage their investment in highly instrumented fields and enables new capabilities for automation and optimization that would otherwise be impossible or difficult to achieve.
»    WITSML reduces the cost of information exchange between software applications within an operating company and between operating companies, joint ventures, partners, contractors, and regulatory authorities.
»    WITSML reduces the cost of replacing or substituting software which results in improved functionality.

WITSML, facilitated by Energistics, is celebrating its tenth anniversary this year with more than 50 member companies supporting its Special Interest Group (SIG) and is embedded in over 40 software products and applications used by oil and gas companies globally. So why has every new drilling operation in the last two years not used WITSML as its base data communications technology for near real-time data exchange and historical information? The answer lies in rate of adoption rather than proven functionality. In some energy companies, notably Statoil and Saudi Aramco, there is a proven understanding of the benefit that is provided by utilizing WITSML and as a consequence their master service agreements stipulate that WITSML must be used to deliver real-time drilling data. However, this is certainly not true of the broader oil and gas industry.

While the energy industry as a whole has been a late adopter of certain technologies, there have been several technology innovations such as 3-D seismic and horizontal drilling which have increased safety and made drilling operations more effective. However, adopting new technology, simply for efficiency, is often perceived by the industry as a “nice to have, rather than a need to have” decision.

For most oil and gas operators the approval and implementation of a project follows a rigorous process. The intent is to be as objective as possible and to answer questions such as:

»    Is the project affordable given budget constraints?
»    What is the timeline to delivery and how soon will I get payback?
»    What are the risks of the project failing to deliver?
»    If there are several project proposals which have the highest priority?

It is very easy for data communications to be overlooked completely in this high level decision process but usually they become critical once the project is underway. The challenge is quantifying the business value from implementing effective data communications and understanding the added business value from using an open industry standard rather than a proprietary solution.

In the early phases of most projects, usually prior to sanction, an Authorization for Expenditure (AFE) or similar document is developed setting out the business case for undertaking a project. For a project to go live, the AFE must either demonstrate significant business value or else fit into the category of a “must do” project to satisfy regulatory requirements or address Health, Safety, Security and Environmental (HSSE) issues. The question is – what is meant by significant business value and how is it measured in the case of a project adopating a communications protocol such as WITSML?

A good approach to addressing data communications requirements in the pre-project phase is to establish a clear understanding of how standards can mitigate risk and enable decision making and therefore be an integral part of the drilling strategy. This could take the form of a workshop, facilitated by a real-time data professional, attended by drilling engineers, supervisors and managers from the project team. The project team should identify what data is required, by whom and in what form. Having detailed discussions about the consequences of losing installed data communications will lead towards identifying business value but it is only the first step. If data communications are implemented from a business perspective they open up a wealth of opportunity.

Let us use WITSML as an example and review the cause and effect map shown in Figure 1 that looks at the premise that “WITSML is becoming a de-facto open industry standard for real-time drilling and production information”. The light blue boxes are consequences of the premise and an experienced project engineer could assign financial benefits to each of these boxes based on existing project knowledge. The dark blue box shows the business impacts which would have detailed cost savings assigned and be prioritized accordingly. The high-level map shown in Figure 1 illustrates the process, but for a real project, it would be structured in much finer detail.


Armed with factual information on business value in the AFE, the case for WITSML becomes much more compelling. Add to this the consequential value of deploying new software tools to analyze the real-time data and a likely future requirement to provide process or sub-process automation and suddenly WITMSL becomes an integral part of the drilling strategy.

In the case of a new well project, there are two distinct phases – well planning and well delivery. Both require service support to the well team from the sub-surface and drilling disciplines as shown in Figure 2. A number of software tools will be used by the discipline engineers and well team to support well planning and well delivery and this architecture will deliver far greater business value when planned in advance.

The individual processes are understood clearly in most oil and gas companies but the degree to which they are implemented in a coherent manner with efficient data sharing varies widely from project to project. The main reason is that the “do it as we have done it before” approach emerges and there is a lack of planning of the complete data flow. Data communications are sometimes perceived as a necessary evil, rather than as an opportunity for enhanced value delivery by the project managers and well team leaders.

The situation is complicated further if the software tools are sourced from multiple vendors, which is often the case. Although WITSML provides only a partial solution to this problem at the moment, the standard is moving in a direction that will improve considerably the efficiency of data exchange in the future, as development is accelerated by end user demand.

In conclusion, the subject of data communications should be a critical discipline in well delivery systems and the use of WITSML is likely to have a profound effect on the value of a project. Documented cases exist where WITSML has delivered significant business value but all too often standardization is not part of the project strategy. It may be that the project decision makers lack the technical knowledge of WITSML and the important role that it can fulfil. Under these circumstances the result, at best, is that the project delivers some business value in spite of data communication inefficiencies. A significant question to ask is what value could have been derived if WITSML had been part of the overall strategy? And more importantly what will the overall value be to the oil and gas industry once adoption and deployment of WITSML is universal?

For more information please visit the Energistics stand at the SPE Russian Oil and Gas Technical Conference and Exhibition, Moscow (26 – 28 October 2010) at Stand C-60 or visit

http://www.energistics.org/

and

http://www.digitaloilfieldsolutions.com/.

References
[1] Pickering, J., Grøvik, L., Franssens, D., Deeks, N., Doniger, A., Schey, J.:
“WITSML Comes of Age for the Global Drilling & Completions Industry”,
SPE 124347, Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA, 4-7 October 2009.



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ROGTEC talks with Alexander Dementjev, Country Manager of PGS in Russia

Monday, August 30th, 2010

Alexander Dementjev
Country Manager, Petroleum Geo-Services, Moscow

The last year has been extremely tough for the oil exploration sector globally as well as in Russia. How is business for PGS in Russia today?
Yes, indeed, all service companies have experienced a serious negative impact due to the economic crisis. Companies working with old and, hence, less effective technologies have suffered from the crisis the most because of the severe competition in this sector. PGS is positioned in the high-end sector, which effectively allows us to stay “afloat” amidst the reduction of overall demand and volume of investments in geologic exploration.

Our business in Russia last year was rather good. We successfully carried out restructuring, considerably improved financial and production figures of the PGS Khazar Joint Venture, created, in my opinion, a sustained work strategy on such a challenging market like Russia.

PGS has made some significant inroads into the Caspian region; how is your Caspian business developing?
I would describe the Caspian region as the perfect ground for the development of PGS’s business in Russia. We are learning a lot there, testing new technological ideas, strategies and implementing international management systems with allowances for national specifics. As a result, we have seen a significant increase in productivity, radical improvements in the quality and safety of operations in such a difficult region as the Caspian Sea. If you add the picture investments into the development of human resources and new multi-purpose vessels, which we are building in Astrakhan, it will become obvious why the PGS Khazar Joint Venture is ahead of our competitors and is demonstrating growth despite the crisis.

What do you feel were the key factors to PGS’ success in Kazakhstan?
First of all, it is our excelent regional knowledge, the demands of the oil and gas industry, professionalism and the vast experience of our specialists working in the Caspian Sea. Apart from PGS Khazar, there is a large PGS centre for the processing and interpretation of seismic data, which has been successfully working in Almaty for a long time. Secondly, we do everything we can so that each project would support the national industry and ensure that the majority of works are carried out by Kazakh companies. Thirdly, constant presence in the market is an important element. That is why we created a subsidiary company in Kazakhstan and that is why the PGS Khazar management often meet the authorities and the local oil and gas companies of Kazakhstan. And the last factor is how we approach our targets. We always try to exceed our clients’ expectations.

Are there practices and ways of working in the Caspian that would improve and stimulate the offshore sector in Russia?
I would like to point out the positive experience of Kazakhstan in the stimulation of international competition for the offshore market and in the control of the level of the national content in the projects, implemented by the international companies.

What is the current state of the Marine Seismic industry in Russia?  What are the major surveys currently under way?
Russian offshore oil and gas production does not exceed 3 per cent of the total volume. The intensity of the geological exploration (GE) of the shelf does not comply with the targets set by the State Energy strategy. This, without doubt, has a negative effect on the development of the Russian geophysical sector. On the other hand, stagnation of this sector is also caused by the lack of economic incentives for geophysical companies to engage in the shelf exploration independently, underdeveloped market for geological information and the inability to implement commercial multi client exploration projects in Russia. Furthermore, various legal barriers slow down the development of international offshore competition in Russia and, hence, the access to the modern technologies.

Intensification of the shelf exploration will give the country a better understanding of the important resource base and help to effectively plan a prompt step-by-step development of the shelf. This is essential for a more flexible management of global energy resources, which means a more predictable and stable market and a regulated balance between demand and supply, which in turn will mean avoiding any crisis in the future.

I’m confident that the marine geophysics industry in Russia can and must develop in partnership with international leading companies. Indeed, the Ministry of Natural Resources and Ecology estimate that investments in the offshore exploration could amount to more than 600 bn Roubles for the period until 2020. Gazprom estimate that their projected reserve growth of 43% will be achieved due to the shelf. Rosneft assert the necessity of investment in the development of the offshore projects to the tune of 30 bn US Dollars for the period until 2030. These targets cannot be achieved without a specialised geophysical fleet, modern exploration technologies and international cooperation. The right moment will be lost and the shelf will not become the country’s engine for modernisation.

What can be done to stimulate demand for offshore data?
First of all, it is necessary to support the intensification of the geological exploration on the shelf. It is necessary to develop the geological information market and secure international fair competition in this area. It is essential to allow geophysical companies to independently invest as early as possible and to implement the results on a commercial basis (multi client projects). Direct involvement of the Government in oil and gas projects, including multi client GE, could secure considerable additional budget revenues and more effective offshore development.

The use of modern technologies must be especially profitable in Russia. A favourable tax regime is essential here (GE expenses, testing of new technologies should be deducted from the tax base).

Development and implementation of clear framework of terms for investors in GE and geophysical contractors, lowering of legal and bureaucratic barriers for international companies (fleet), a review of the provisions on secrecy of geological information is required. All these measures will open the doors to the implementation of effective technologies and necessary investments. Implementation of the proposed measures as a whole will undoubtedly lead to the prompt increase of industrial energy resources, strengthen global positions of the Russian Federation and, obviously, boost the country’s attractiveness for investment.

Many different regions employ Multi Client Services to make offshore data available to prospective operators. Russia, however, has so far not embraced this form of data collection and distribution.  Why is this and should they be utilizing MCS?
I think the multi-client model does not work in Russia because of the groundless strict regime of secrecy around the geological information. Taking in to account the experience of other countries – Norway for example – shows that transparency in the resource management system and an active market of geological information provide for effective offshore development. I very much hope that the favorable conditions for implementation of multi-client GE projects will be established in Russia as soon as possible.

What advantages would MCS bring to Russia?
Multi client works convert production capacity (fleet, supercomputers, geologists, geophysicists) to intellectual property, which generates profits for geophysical companies and the state over a period of 10-15 years.

Moreover, multi-client projects significantly improve the quality of exploration and attract leading technologies. As a result, investor interest in the shelf grows and new investors are attracted, new geological prospects and ideas are generated and the Government will have a better understanding of the potential.

Other benefits will include an increase in tenders and auctions for subsurface use (license rounds), subsequent GE programs will be optimised, geological risks will be reduced the exploration cycle will speed up, all leading to reserves being brought online much quicker and more effectively. Basically, multi-client GE will help oil and gas companies to identify the most attractive licenses or the best prospects in the license portfolio.

Even if multi-client GE turns up relatively poor prospects, the results will still have commercial value; oil and gas companies buy information for a better understanding of geology of a particular region and the planning of further exploration steps.

Where would you see the company’s strongest regional growth over the next few years -  marine surveys, data processing or software sales?
Without question, in deep water seismic offshore works in the Arctic sea shelf.

What new technologies have you introduced recently?
Our company invests 70-80 mil dollars annually in the development of new technologies. I think that even our respected competitors will admit the innovative nature of our corporate culture. One of our Russian partners commented that PGS in marine geophysics is like Apple in the world of personal computers – highly innovative, exclusive and desirable.

One article is not enough in order to answer your question. I would like to give just three examples. I have already mentioned that the PGS Khazar Joint Venture is completing the construction of three new vessels in Astrakhan. The new type of vessels will effectively operate in 2 to 25 meter water depth. Having said that, the vessels can work with the bottom cable as well as with towed streamers.These vessels will certainly increase the productivity and the quality of seismic surveys in the Caspian Sea. The size of these vessels will also allow to use them in other offshore areas.

Our Ramform fleet is the pride of PGS. Last year we commissioned two new vessels to join the fleet; the Ramform Sovereign and the Ramform Sterling.

The first obvious feature of these vessels is the hull shape. At just more than 100 m in length, the vessel is not long by modern standards, but with 40 m in the beam at the stern, the hull takes on a futuristic appearance. This is strikingly different from the conventional slim hulls, and while the vessel is no slouch at 16 knots cruising speed, it cannot be classified as a high-speed vessel. About 30,000 hp of propulsion capacity makes the vessel the most powerful in the world. When collecting seismic data, the Ramform Sterling generates around 160 tons of thrust, equivalent to two Boeing 747 aircraft at takeoff.

Onboard the vessel you see many innovations which are designed to maintain the productivity of the vessel. Many of these are only possible due to the space, volume and power of this unique vessel.

The latest Ramforms have significantly higher acquisition and transit speed, 25 percent longer endurance, and 60 percent higher production capacity compared to the previous Ramform class vessels. The vessels are equipped to tow up to 22 acoustic streamers – more than twice the capacity of most conventional vessels. The 400 tons of highly sensitive electronic equipment is deployed over an area equivalent to 830 soccer pitches. This translates to higher productivity in operations, which is advantageous to customer. The volume also allows for extreme fuel capacity of about 6,000 metric tons, offering extreme survey endurance. As an illustration of what this means in practice, the vessel would be able to sail twice around the planet without having to stop to refuel.

For crew changes, the vessel has the world’s first roll-compensated helideck, allowing safe helicopter landings in conditions where landings would normally be too hazardous to attempt.

On the equipment side, there are also several features that can be expected to find their way onto other new seismic vessels in the future. For instance, the sources are equipped with devices that enable the sources to be steered rather than simply towed passively behind the vessel. Sophisticated software interfaced to the vessel’s seismic navigation system allows the source arrays to steer predetermined tracks to repeat the source positions of previous surveys. This is of great benefit for advanced 4-D surveying. The range of technologies employed is the new benchmark for 3D, 4D and wide azimuth acquisition – in terms of productivity, efficiency, safety and data quality.

Another example of the revolutionary technology is the dual-sensor towed streamer GeoStreamer® developed by PGS. The design of this streamer utilizes two types of sensors: pressure and velocity.

This new technology gives opportunity to significantly improve the quality and efficiency of seismic surveying in comparison with the conventional streamers where only the hydrophones are used.

The analysis of the data acquired with GeoStreamer® demonstrates 4-5 times increase at the low side of the spectrum, double increase of the high frequencies (before any processing for the purpose of signal amplification) and also an increase of signal to noise ratio for all frequencies and depths.

As a result we achieve deeper penetration or imaging of deep sub-basalt and sub-salt targets while providing higher resolution of e.g. stratigraphic traps images. GeoStreamer® towing depth is now about 15 – 25 m. It can take advantage of the fact that the noise effects of weather-induced surface waves decrease significantly. And increased “insulation” of the streamer from the effects of bad weather increases the operational weather window and enhances productivity.

What would you like to have achieved with PGS in Russia and the Caspian in the next 12 months?
We work in Russia and other former USSR countries in accordance with a certain strategy, the targets of which are quite ambitious, but realistic. I believe that in the next 12 months our joint venture will not only strengthen its position and expand its presence in the Caspian region, but also will be ready to enter the international market outside the boundaries of the Caspian.

We also hope that in 12 months time the organisational decisions will be found and the necessary conditions will be created for the deployment of the most efficient seismic vessels in the world, along with other PGS technologies, for effective geological exploration in the Russian Arctic sea shelf. First and foremostly, this is for the benefit of Russia. Our country deserves this.



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Blackbourn Reports: Development of the West Siberian Basin during the Mesozoic and Tertiary: Palaeogeography and Stratigraphy

Monday, August 30th, 2010

Graham Blackbourn: Blackbourn Geoconsulting

Triassic
Beginning at some point during the late Permian, and continuing through the Triassic, dominantly north-south and northeast-southwest-oriented rifting occurred within the area of the West Siberian Basin, apparently in part reactivating Palaeozoic lineaments (Enclosure 2). This followed a period of Permian uplift across much of the WSB, where Permian deposits are now scarce (Chapter 2). The main rift runs N-S through the northern WSB, passing below the Urengoi gas field, and another parallel rift runs to the east through the Yenisei Fold Belt. These are the Urengoi and Khudosei rifts respectively. The Khudosei rift joins at its northern end with a NE-SW-trending rift that runs along the Yenisei-Khatanga Trough. To the south, within the central WSB, the two major rifts split up into a number of smaller rifts with more variable orientations. The Urengoi rift is in fact just the northern portion of a more extensive rift system, the Koltogor-Urengoi graben, which extends for approximately 1800 km in an approximately north-south direction from Omsk in the south to the southern Kara Sea in the north. Indeed this graben aligns in turn with the Saint Ann Trough in the Arctic Ocean, which opens into the deepwater Nansen Trench, although it is uncertain whether there is any genetic relationship between the two. The width of this graben increases from several kilometres in the south to 80 km in the north.

The rifts were associated with, and filled by, up to at least 2 km of latest Permian to Early Triassic basic volcanics. The origin of the rifting and volcanism is debated; many Russian authors have related them to a “superplume” beneath the WSB. This model has been strongly supported by Saunders et al. (2005), based on a study of a substantial amount of seismic data from the Northern WSB, together with well records. Saunders et al. have calculated that crustal extension (ß-factors) associated with the rifting may have been as high as 1.6 across the Urengoi rift in the north, reducing to about 1.1 in the central WSB (Surgut area). They conclude therefore that the plume was located directly beneath the area of the Urengoi and Khudosei rifts in the northern WSB. These authors consider that the co-eval Siberian traps, which outcrop over a huge area of the Siberian Platform adjacent to the eastern margin of the WSB, were generated by the same episode of magma formation, and that the trap basalts on the Siberian Platform flowed there either across the surface, or along subsurface dykes or sills.

The Urengoi rift was penetrated to a depth of about 7500 m by the Tyumen superdeep well, SG-6, the stratigraphy of which is illustrated schematically in Fig. I.3.1. The deep crustal cross section illustrated in Enclosure 3 also passes through the location of the Tyumen SG-6 well. Igneous activity associated with the superplume is thought to have begun around 250-253 Ma in the form of alkali to ultrabasic activity in the Maimecha-Kotui region, but the greatest volume of traps formed around the Permo-Triassic boundary from 249-250 Ma. Medvedev et al. (2003) obtained Ar/Ar dates confirming this age for basalts obtained from wells in the the north of the WSB. It has been postulated that the huge outpouring of volcanic material and gases was responsible for the major extinction event which defines the Permo-Triassic stratigraphic boundary. Traps were forming at about the same time within rift basins in the WSB and surrounding areas, and also within the Kuznetsk coal basin during its final stages of formation. The igneous petrology of the Permo-Triassic volcanics of Western Siberia has been considered in detail by Medvedev et al. (2003).


The western limit of the Triassic volcanism occurs at Chelyabinsk and other coal-bearing grabens on the western slopes of the Urals; there are no traps here, but Early Triassic basite dykes. More common within the Urals are Late Permian to Early Triassic granitic rocks and bimodal volcanics, considered as late-collisional. They are not thought to be associated with the trap formation, although they are of a similar in age. The most well-defined link between the trap formation and sub-alkaline granitic intrusions has been established on the Taimyr Peninsula (Fig. I.1.1). The Taimyr traps are a continuation of those on the Siberian Platform, although probably slightly younger (220-230 Ma). Saunders et al. (2005) consider that following the main period of continental flood-basalt volcanism in the WSB, the locus of magmatism (i.e. the plume) migrated northwards relative to the overlying crust, to the Taimyr region, before migrating further onto the Barents shelf. Like the Kara Sea basalts, some of the trap intrusives here are highly differentiated, containing monzonites and sub-alkaline granitic rocks.

The depth as well as the width of the Triassic grabens increases to the north, where in addition to volcanics they may contain as much as 5 km of Triassic sedimentary rocks. Within the grabens, variegated conglomerates and sandstones are interbedded with volcanic rocks, which predominate in the Lower and Middle Triassic deposits. The upper parts of the rift-fill mostly lack volcanics, and coals beds are common. North of approximately 64° N, the basin contains a sequence of mixed continental and marine sandstones, siltstones, and shales of Triassic age (Tampei Series; Fig. I.3.2), up to 3 km or more thick, possibly including basal Jurassic deposits. The sea is thought to have penetrated the basin from the north, over the West Siberian Sill or possibly along the Yenisei-Khatanga Trough, and spread at first along the rift basins, but extended in time over the intervening platformal area (Fig. I.3.1). The Tampei Series sediments are broadly similar to those of the overlying Jurassic deposits, and represent the initial cycle of Mesozoic platformal marine sedimentation in the basin. Seismic data indicate that these deposits may be more than 6 km thick in some troughs in the northern basin region. In the Khatanga region, up to 3 km or more of Triassic clastics occur, sourced from the Taimyr uplift.

There appears, however, to have been some delay between the ending of trap volcanism in the WSB and the onset of significant thermal subsidence (Saunders, 2005), which corresponds with the start of the main phase of Jurassic deposition, in about the Pliensbachian. However, once begun, thermal subsidence continued until at least the Oligocene, with an almost complete stratigraphic sequence broken only by short-lived discontinuities resulting primarily from eustatic effects.

The lengthy period prior to deposition of the earliest Jurassic sediments was one of weathering and erosion over much of the West Siberian Basin. Brecciation, leaching and
chemical transformation of the pre-Jurassic surface in many areas created a porous network which was later to host numerous, though largely small, sub-unconformity oil and gas accumulations (Section II.2.1).


Jurassic
The post-rift Mesozoic-Cenozoic sedimentary cover of the West Siberian basin, beginning with the Lower Jurassic, is up to 8-10 km thick in the northern part of the basin, and averages about 3-4 km over the remainder of the basin, thinning to zero around the basin margins (Enclosure 6). The sediments were mostly deposited in an extensive shallow inland sea, with coastal plain and continental environments around the margins. The sea was generally deeper in the west and north owing to the main source provenances lying to the east and south.

The sediments are almost entirely clastic (sandstones, siltstones, and shales), apart from some quite extensive argillaceous limestones towards the top of the Cretaceous (Maastrichtian), and a few locally developed limestones elsewhere. Deposition in the deeper parts of the basin was virtually continuous from the Early Jurassic to at least the mid-Miocene, although unconformities of variable extent are present at the base of or within the Callovian, Kimmeridgian, Hauterivian, Barremian, Aptian, Turonian, Palaeocene, Middle Oligocene, and Miocene. These result mostly from eustatic rather than tectonic events.  The Jurassic deposits have undergone only mild tectonic disturbance since deposition.

As noted above, the major sediment-source areas during the Mesozoic lay to the east and southeast of the basin. The Ural, Novaya Zemlya and Taimyr uplifts formed subordinate but still significant sources. The western side of the Siberian plateau to the east appears however not to have been a major sediment source; it was covered with Triassic trap basalts and Late Proterozoic to early Palaeozoic clastic sediments, whereas the sedimentary fill of the WSB is dominantly arkosic, derived from a granitic terrane. However, it is possible that during the Jurassic the precursor to the Lena River, which now drains the eastern side of the Siberian Platform and flows northwards into the Laptev Sea, flowed along the Yenisei-Khatanga Trough from east to west and transported sediment into the northern WSB. Local uplifts within the basin also acted as minor sediment sources during the Jurassic, before they were blanketed by sediments. The Jurassic to Recent evolution of the WSB, in simple terms, comprises the passive infill of a (structurally) remarkably symmetrical, gently subsiding basin, and the simplest model for this subsidence is one of thermal sag which followed doming associated with high heat flow in the Basin during the Triassic, and which was in turn associated with the contemporary volcanism (Section I.3.1).



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