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Dr. Richard Stocker, PhD, MSc. Senior Geoscience Consultant
Pablo Alvarez, MSc., BSAT. Senior HSE Advisor
VISION PROJECT SERVICES (UK) LTD., Dorset, England.

Introduction
Any client contemplating a marine seismic program should be cognizant of the general principles for seismic acquisition. The details are also very important but the brevity of this article precludes their discussion. If the client adheres to the general principles, the right consultants and contractors will attend to the details.

Exploration Objectives
All seismic acquisition should flow from well-defined exploration objectives. These are geological objectives translated into seismological objectives, that is, the characteristics and attributes of the finally processed seismic data. They dictate the acquisition design and the technical specifications.

The Contract - Stand-by Time
The best contract is turnkey with chargeable stand-by time. The turnkey provision puts the responsibility on the seismic contractor to be logistically efficient when the crew can work but acknowledges situations out of the contractor's control when the crew cannot. In such circumstances, the contractor should be compensated for the operating expenses. If extensive standby time occurs and the cont

Necessary Consultants
An instrument engineer should conduct a pre-production audit and act as a resource throughout the entire program. Consultants to perform the dockside verifications and calibrations of the positioning equipment and to examine the positioning data from the first acquired data are the norm.

Client representatives for real time verification to ensure the work complies with the technical and HSE specifications. Extensive QC seismic processing or final data pre-processing on board may require a seismic processing client representative.

For marine acquisition the standard is two sets of rotating client representatives, one for seismic and one for navigation-positioning. Commonly the client only requires an initial HSE audit before the vessel leaves port. At sea, the seismic and navigation-positioning client reps have responsibility for overseeing HSE. Some clients may also require a technical audit, which is conducted partly at the dockside, and at sea during the initial deployment of the equipment (energy source and streamer(s))

Selecting Consultants and Contractors
The simple answer is to select personnel who have done a good job previously but this begs the question. For individuals, recommendations from trusted and knowledgeable colleagues who have worked with the people are the best method. Given the gravity of this decision, a telephone interview is warranted.

Selecting a seismic contractor is much more difficult than selecting individuals. Many, if not most seismic contractors have many crews. Not all are of equal quality. The composition of crews change with time. What was a good crew may become less so and vice-versa. Many seismic contractors divide the world into different administrative regions and the regions may not have the same attitude toward HSE and data quality. Every seismic contractor, to hear them speak, is dedicated to world-class HSE procedures and data quality. However, seismic contractors are not charitable organizations. In effect, seismic contractors sell the time of their personnel and rent their equipment to the client. The better the HSE procedures and the higher the data quality, the more time is required to complete the program and often more equipment is necessary. World class HSE and high-resolution data cost more – as a client do not expect something for nothing from your seismic contractor.

The technical and HSE specifications must be part of the package sent to the seismic contractors bidding on the work. How else can the seismic contractors bid appropriately? The client should involve the consultants in writing said specifications. The instrument engineer should comment on the appropriateness and the reliability of the instruments and sensors proposed by the bidders. One seismic contractor may propose equipment with a significant advantage. Remember that the specifications are the "rules of the game" that the "referees", i.e. the client representatives enforce. Poor rules leave the client representatives powerless.

The Acquisition Design
The mantra of all seismic acquisition is acquiring data which meets the exploration objectives at minimum cost. Clearly, this goal cannot be accomplished with imprecise exploration objectives. Even with precise exploration objectives the acquisition design can overdesign or under-design the program. Overdesigning the program means the exploration objectives will be met but the cost will be unnecessarily high. Under-designing the program means the data will at best only partially meet the exploration objectives. The client needs two independent designs to consider.

The seismic industry has made remarkable technological and methodological progress over time. The issue for the client is, do you need the "latest and greatest equipment and/or methodology"? For marine acquisition do you need MAZ or WAZ methodology? If you do, be thankful it is available. If not, it represents overdesign. For an expert and objective discussion of these issues read the books and papers by Gijs Vermeer.

The Technical Specifications
The technical specifications, despite their importance, are the bete-noir of acquisition. Learned treatises, papers and meeting presentations consider acquisition design. Very little public discussion of technical specifications is available. Seismic contractors have their internal specifications but generally are loath to disclose them

Since the technical specifications concern what constitutes lost data and the percentage of lost data that is acceptable, the seismic processor should be the ultimate decider. For example, it is not the signal-to-noise ratio on the raw records that is important but the signal-to-noise on the final processed data. How seriously does a channel failing a particular test degrade the trace? What tests can be failed and still have acceptable data? The instrument engineer knows the effect of a test failure on the amplitude and phase characteristics of the response but only the seismic processor knows if incorporating such data would do more harm than good.

In the field, the observers have to make the judgment whether to record or stand-by in real time. They require numbers for the maximum permissible ambient random noise and how many channels can be above the limit. They need to know what tests to run on the instruments and sensors and what are the tolerances. The instrument engineer has the expertise to advise the client on the tests and tolerances. The seismic processors, given they have at least a sample of the seismic data, know the maximum permissible ambient random noise and how many channels can be above the limit. The recommendations of the seismic processors can then be translated into the numbers required by the observers.

Extensive and Comprehensive Start-up Meeting
An extensive and comprehensive start-up meeting should be conducted after the seismic crew has completely mobilized and just before the parameter testing, Attendees should include the client, client representatives, the instrument engineer if possible, the heads of department from the seismic crew, the party chief, the country manager and the seismic contractor regional HSE and technical gurus if possible. All technical and HSE specifications should be discussed deliberately and thoroughly, and then agreed to as appropriate and doable by all parties.

Parameter Testing - Production Testing
To reduce the expense of parameter testing all relevant data should be analyzed prior to generating an acquisition design. Existing seismic and well data are the most valuable. Clients need to do their homework.

The ultimate parameter testing is production testing. A production test acquires an appropriate interval of fullfold seismic data along a production line and then evaluates the parameters from the fully processed seismic data. The client has either to have the data fully processed on-board or have fast-track seismic processing on shore.

The final concept is that of seismological areas. The optimal values of acquisition parameters for a given seismological area differ from those of adjacent seismological areas. Differences in bathymetry, near-surface and subsurface geology create seismological areas. The larger the program area the more likely there is more than one seismological area. Each seismological area requires a separate parameter and production testing.

Approaches to Seismic - Rational versus Budget-Constrained
The principles stated form the basis of rational seismic exploration in which data meeting the exploration objectives is the independent variable and cost the dependent variable. Hopefully the budget for the project is adequate. Cost is the independent variable in the opposite approach, which may be termed budget-constrained seismic or you-get-what-you-get seismic or hope-and-pray seismic. This approach is quite common, in fact probably the more common. Again, one hopes the budget is adequate, otherwise the data will only partially met the exploration objectives or may not meet them at all. One may contemplate the aphorism that the most expensive seismic data is data that fails to meet the exploration objectives.

Health, Safety and the Environment
For the HSE professional, marine seismic offers the advantage that Safety is an integral aspect of all marine operations following IMO (International Maritime Organization) regulations as well as IAGC and OGP directives on this subject.

All personnel and crew in a boat can only board after following minimum training, which ensures that HSE is part of the marine mind set.

Still, HSE in marine operations is a demanding task. Many sets of regulations must be followed to ensure compliance with "best practices". One example is MARPOL, the International Convention for the Prevention of Pollution From Ships (1973, modified by the Protocol of 1978). Guidelines and regulations are clearly explained there, so the role of the HSE personnel is to manage a complex system, as opposed to implementing one.

Training and drills are also clearly stated and scheduled. That leaves the HSE personnel the freedom to concentrate on the quality and effectiveness of the training program, as opposed to whether these drills are performed (or which ones should).

Still, high seas operations are complex scenarios. In streamer marine jobs, the handling of the heavy equipment poses clear dangers. Proper planning, from fully fledged operations (those that are not routine) to the daily "Tool Box Meetings" must be carried out, and documented. The TBM's can be used specifically for planning and reviewing procedures, which may have a higher level of risk if the crew begins to see them as routine and "easy". It is the role of the HSE professional and Heads of Departments to foresee problems that break with this routine and can lead to incidents.

In Ocean Bottom Cable (OBC) jobs, the key issue is the use of several different types of crafts. HSE must ensure that different regulations and levels of seaworthiness mesh together, and that maintenance and safe practices cover all procedures. OBC also calls for land bases, mixing both land aspects with marine. This usually leads to duplicate or "extended" HSE departments.

These must ensure that emergencies in both land and sea are taken care of while not relying on the same personnel and services. The intrinsic spreading of personnel, crafts and equipment over both sea and land make these operations more complex than the Streamer jobs, calling for a more detailed planning of the initial aspects of the operation, as well as the day to day after the job has started.

Labels: Exploration, marine seismic, offshore acquisition, Russian oil gas

posted by The Rogtec Team @ 17:02  2 Comments

Integra is one of the world's leading geophysical companies with over 40 crews operating in Russia and Kazakhstan as well as having an international presence. In Russia, the company's subsidiary, Integra Geophysics, is one of the leading companies by volumes acquired and Azimut Energy Services, it's Kazakhstan subsidiary, leads the industry in acquisition volumes. The company has acquired 2D and 3D seismic surveys for all of Russia's leading oil companies (Gazprom, Rosneft, LukOil, TNK-BP etc) and in Russia and Kazakhstan has a growing reputation with international oil companies like ENI, Shell, Chevron and BG after acquiring major 3D surveys over some of the world’s largest oil and gas fields.



Since 2006 Integra has been investing in new equipment and technology to improve health and safety (HSE) and operational performance. The result is that that the company is now equipped with some of the most advanced geophysical equipment available including a fleet of modern ION and Sercel vibrators and recording systems. This allows Integra to compete with some of the world's leading geophysical companies and implement technology routinely used in other areas of the world.

Heli-portable operations
In the summer of 2008 Integra Geophysics conducted a heli-portable seismic operation for TNK-BP in the Uvat region of West Siberia. The objectives of the survey were to improve operational efficiency, reduce the impact of seismic operations on the environment and test the viability of summer operations in areas where winter acquisition is the norm. Helicopter seismic operations are widely used in Canada and the USA to over come logistical challenges in mountainous terrains. Equipment is moved by helicopters thus reducing the need for heavy cross-country vehicles which can cause a long lasting impact on the environment.



The absence of helicopters suitable for heli-portable operations in Russia meant the company had to work closely with service provider UTair to acquire 2 AS350 helicopters and access Canadian pilots to train their Russian counterparts to conduct operations. Equipment required to carry large amounts of ground equipment and slings and hooks to allow helicopters to pick up equipment on the fly was also acquired. Restrictions on satellite receiver technology to help with positioning limited the full impact of operations.

The Uvat region is heavily forested and requires a significant amount of tree cutting. Typically shot and receiver lines are cut to a width of 4 metres to allow the passage of cross-country vehicles and tree-cutting is both labour intensive and a significant HSE risk. In summer, the region is very boggy and the movement of vehicles causes deep ruts and restricts movement. The use of helicopters allowed Integra to reduce the amount of tree-cutting and limit the use of vehicles thus reducing the impact on the environment.

In the Uvat region helicopters were used to move geophysical ground equipment and demonstrated nearly a 2 fold increase in productivity measured by the average number of shot points acquired per day with a daily maximum of over 700sps/ day. The increased costs of helicopter operations can be offset by increased efficiency and reductions in vehicles and personnel. Future operations could be extended to include movement of drilling equipment as well as seismic recording equipment.

Mulchers
Over the last few years the biggest contributor to seismic industry fatalities and injuries was tree-cutting. The industry cuts a significant volume of trees every year, approximately 300,000 line kilometers, and tree-cutters are exposed to significant HSE risks due to falling trees and debris. The efficiency of seismic operations is also dependent on the quality of line preparation. Typically tree cutting operations are carried out in summer to ensure residual tree stumps are cut to a minimum - stumps visible above winter snow cover often limit the movement of drilling equipment. The disposal of cut trees and debris is both time consuming and a requirement to allow the safe passage of vehicles. This adds to the time and risk of manual tree-cutting operations.



In 2007, Integra purchased a mulcher to test the efficiency and suitability of equipment regularly used in other areas of the world for tree-cutting. The equipment was deployed on the same summer project as the heli-portable operations in the Uvat region. The advantage of mulchers is that the number of people involved in tree-cutting operations is reduced from a typical 5 man manual tree-cutting crew to a single operator who is totally enclosed in a safe cabin. The machine effectively "pushes-over" trees and a series of teeth, on a rotating drum, chop the fallen trees in to a fine mulch of wood chips that are deposited behind the machine.



The deployment of mulchers has demonstrated a significant reduction in HSE incidents on tree felling operations with no incidents to date. The effectiveness of mulcher operations has also been proven with a single mulcher capable of clearing between 4-5 kms/day compared with a typical 1km average for a tree-cutting brigade. The advantage of the debris left after mulcher operations is that it provides a flat surface through the cut line that allows a safe and efficient "road-way" for drilling and seismic recording vehicles to follow. A further advantage of a better roadway is that there is less stress on cross-country vehicles and therefore reduced equipment failure and maintenance.

Average operational costs for mulchers and manual teams are comparable but reduced camp sizes and lower HSE risks demonstrate the benefits of such technology. The down-turn in North American seismic market means operators in Canada and the USA are now able to offer high quality machines suitable for the Russian terrain and climatic conditions. Now many leading seismic operators are now looking to stimulate the Russian contracting industry to provide a significant volume of mulchers for the 2009-10 winter season.

High productivity vibroseis acquisition
Approximately 50% of Integra's projects use vibroseis seismic sources. These are commonly used on the flat terrains of the Russian tundra and Kazakhstan Steppe. Individual vibroseis shot points typically use 4 vibrators simultaneously vibrating for up to 20 seconds, known in the industry as a sweep. Oil companies normally request up to 4 or 6 sweeps per shot point. Average survey acquisition rates for Integra operations are between 250 - 300 shot points per day. Daily productivity can be as high as 400 - 500 sps / day depending on weather conditions and terrain. Standard 3D seismic surveys require the acquisition of 20 - 25,000 shot points which will generally take 3-4 months to acquire - the normal duration of the Russian winter season.



Globally, acquisition companies have started to deploy multiple fleets of vibrators and significant volumes of ground equipment to increase vibroseis productivity. This means oil companies are able to acquire larger surveys or high data density coverage during a single operating season. In 2009 Azimut Energy Services has been contracted by a consortium of oil companies to conduct a 3D seismic survey requiring over 250,000 shot points in a area of complex field infrastructure. At typical acquisition rates this would normally take over 2 years to acquire but the consortium's requirement was to acquire the entire data set in 2009.

Working closely with the operator, Azimut was able to design a survey that could be completed within 9 months. The requirement was to utilize up to 10 vibrators, 18,000 channels and 19,000 geophone groups. With it's combined Russian and Kazakhstan resources the company was able to offer the consortium top quality HVA-IV ION vibrators and Sercel 428 ground equipment. The survey design called for 4 groups of 2 vibrators working in both flip-flop and slip-sweep acquisition mode acquiring a single sweep at each shot point. The chosen deployment of the vibrator groups allowed simultaneous operations with some groups vibrating and acquiring data whilst others travelled to a subsequent shot point. 18,000 channels were deployed in the field with an active spread of 9,900 channels. The 428 central electronic system was upgraded to handle the large active spread and new communication equipment acquired to allow the central electronics to "manage" the vibrators and distribution of the channels in the active spread.

The current operations are impressive and have almost certainly set a record for daily production in Russia and Kazakhstan. To date over 100,000 shot points have been acquired in just over 2 months with an average daily productivity of -1700 sps / day. The highest productivity achieved to date was just under 2900 sps / day, the equivalent of 6 seismic parties under normal conditions.

The handling of such daily volumes and advanced electronics has not been without its challenges but the experience gained on this survey will allow Integra to offer advanced acquisition technology to oil companies in Russia and Kazakhstan and allow it to compete globally with western seismic acquisition companies.

Labels: 2D 3D seismic survey, Exploration, onshore acquisition, Russia oil gas

posted by The Rogtec Team @ 16:03  0 Comments

Ye. O. Cherkas (OJSC NK Rosneft-NTC, D. A. Antonenko and P. V. Stavinsky (OJSC NK Rosneft)

Introduction
Drilling of horizontal holes imposes special requirements on the reliability of prediction of reservoir structure and quality within a large radius from the borehole. However, the reservoir prediction tools currently available to geologists suffer, to some extent or another, from measurement errors, which inevitably leads to modeling uncertainty and increases risks associated with drilling of horizontal holes. In view of the high costs involved in horizontal drilling projects and uncertainties inherent in any model, it has become imperative to address this issue. Incorrect description of a reservoir may result in swelling of irrecoverable field development costs. In a typical geological model, four major sources of uncertainty may be identified: (1) data quality and interpretation; (2) structural and stratigraphic models; (3) geological-statistical model and its parameters; and (4) uncertainty related to equiprobable realizations. In an ideal case, uncertainty decreases as the field becomes more developed.
As regards the Vankor field, which is currently under development, the most challenging tasks from the uncertainty standpoint are as follows: (1) reducing risks associated with horizontal drilling; (2) putting together a program for detailed exploration; and (3) refining the drilling program.

This paper proposes a method for analyzing uncertainties inherent in geological models. Modeling based on this method will yield data (in the form of maps) representing the quantitative distribution of uncertainties in determining the presence of a reservoir and its properties, which must be used to evaluate potential drilling risks.

General Information about the Field
The Vankor gas and oil field is located in the Krasnoyarsk Krai. This paper deals with one of five productive reservoirs with about 390 million tonnes of original oil in place. The field was discovered in 1988 and is yet to be put into commercial production. As of this study, there were 27 wells already drilled into the reservoir of interest. The deposit is a layer-uplifted pool, and the reservoir is terrigenous.

The Vankor uplift is an isometric structure extending from the south northward. The predominant depositional environment was shallow-water (barrier-bar complex).

Method
The best criterion for assessing the overall ambiguity determining the accuracy of geological model parameters is the "validity of the oil-in-place estimate". This criterion is dependent upon the basic characteristics of the reservoir and, therefore, may serve as a measure of accuracy in constructing the model. To evaluate the validity of the reserve estimate, one must evaluate the calculation accuracy of every parameter in the calculation formula


where stands for "stock tank oil initially in place", GRV stands for "gross rock volume", N/G stands for "net-to-gross", is porosity, is oil saturation, is oil density, and is the oil shrinkage factor.

To this end, a general procedure was established for handling each parameter, namely:

1. estimating possible variations in the value of each input parameter;
2. defining the RMS deviation;
3. mapping mean values of the parameter, with fixed values assigned to individual wells and taking into account the RMS deviation in the crosshole space;
4. estimating parameter variance; and
5. mapping oil-in-place variance by multiplying out variance maps for all parameters, provided that they are independent (this condition has been introduced to simplify the estimation process).

Uncertainty Calculation Approach
The principle of accounting for uncertainties is as follows: At first, one should estimate the possible error of the measurements determining the RMS deviation. Then, this error is multiplied by a random surface whose spread of values follows a Gaussian curve with mathematical expectation equal to zero and a variance equal to unity. Finally, the result is added to the reference surface:



where is one of the surface realizations, is the reference surface, is a surface or a constant determining the RMS deviation error, and is a random surface of errors with + and - values around zero.

A characteristic feature of the error surface is the fact that errors at well points acquire zero value, to increase gradually as one moves away from the wells. Thus, the RMS deviation depends on data quality and distance to the well. This approach suffers from the drawback that the range of the error variogram is unknown. It cannot be taken as equal to the variogram ranges used in the modeling of a property of interest because of their heterogeneity. Besides, randomly modeled errors may acquire positive as well as negative values because possible scenarios lie on either side of the baseline interpretation. The variogram range is selected by the interpreter based on subjective estimates of the error variance length. If the range is excessive, the final uncertainty map is smoothed out with partial or complete loss of information. If the range is too small, one will end up with a heavily "noisy" picture.

Structural Uncertainty: Presence of Reservoir
One of the burning questions during early phases of field development is whether oil is present in field areas not covered by exploratory drilling. Analysis of uncertainties may give a feel about the degree of uncertainty in identifying the presence of oil. One of the criteria for such analysis is the position of the top of the OWC. Analysis should proceed along the following lines: (1) delineate a surface over the top of a reservoir (average value); (2) introduce an error into the average value; and (3) derive intersection contours for multiple realizations of the top of reservoir and OWC surfaces.



A set of 200 contours of the top of reservoir-OWC intersection contours has been obtained for the Vankor field. The extreme values are shown in Figure 1. It can be seen that uncertainty in the position of the OWC top, which is essentially the sum total of uncertainties in the positions of the top of reservoir and the OWC, may give rise to a serious error in oil-in-place estimates. In the Vankor field, no reservoir was present within the area marked by the solid black line in 23% of cases out of the set of multiple realizations. A well drilled into the questionable target after this work had been completed failed to reveal any presence of oil. Thus, the high likelihood of absence of oil, predicted by modeling, was corroborated by real evidence. In the course of this work, two other areas characterized by great uncertainty as regards presence of oil were identified (marked by broken lines).

Structural Uncertainty: Rock Volume
Uncertainty in the position of reservoir boundaries and contact determination contribute the error in the gross rock volume measurement. As regards the structural modeling error, its major source is the ambiguity of structural surfaces in the crosshole space. The error grows with distance from wells and is zero in their immediate vicinity.

The error in determining the position of reservoir boundaries was selected based on the quality of seismic data. For the Vankor field, it was assigned as +-15 m.

Estimation of the spread of OWC values was based on the results of well tests in target sands. The spread of values was defined as the difference between the highest and lowest OWC levels. In the case of the Vankor field, the spread of OWC values was 15 m.

In this case, selection of variogram ranges was based on seismic data pertaining to the reservoir and well spacing.

As a result, maps of potential errors in determination of the top and bottom of the reservoirs as well as OWC were produced. Within the boundaries of the field, the average spread of reservoir top and bottom positions is about 5 to 6 m. Uncertainty in OWC position approaches maximum toward the field boundary and between the two blocks of the Vankor field. The rock volume was calculated as the product of gross thickness within a cell times the cell area. Figure 2 is a map showing possible deviations of the gross rock volume from average values.


Proceeding from the results of analysis of structural uncertainties, one can draw conclusions as to the presence of oil in field areas yet to be covered by exploratory drilling. This information is useful in deciding whether additional exploration of the field is needed. Information about possible variations in reservoir boundaries and OWC levels in the presence of oil is instrumental in decision-making processes as part of the field development strategy, especially when it comes to drilling of horizontal holes.

Uncertainty in Reservoir Properties
Variances of reservoir properties are mapped as follows. The input data include zero-variance points or, in other words, correlation marks by wells. An algorithm using a continuous Gaussian distribution and predetermined variogram parameters provide the basis for constructing error surfaces for a property with a given deviation from the mean. Variogram parameters are assigned based on the depositional environment (barrier-bar features, pronounced lateral consistency of properties) and well spacing. All realizations of error surfaces for a given property are reduced to a single variance map of this property at the assigned level of deviation from the mean.

Net-to-gross Ratio
The primary sources of error in identification of pay zones in wells include the resolution of logs, accuracy of determination of reservoir quality by logging, and error in the use of critical values to identify a reservoir. In order to assess uncertainty in reservoir properties, one must first know the deviation from the mean. It is recommended to select the deviation of the net-to-gross ratio from the mean on a distribution bar chart of the model (tied to log data), because we are dealing essentially with assessment of the uncertainty inherent in the model’s volumetrics. As can be inferred from Figure 3(I) the maximum net-to-gross ratio distribution density in accordance with the model is close to the interval of 15% deviation from the mean. The deviation of the net-to-gross ratio from the mean in the crosshole space is close to 4-5%.

Porosity Ratio
The sources of porosity determination error include measurement techniques, instrument error, and subjective factors. The deviation was selected from porosity distribution based on log data in correlation with core data (Fig. 3(II). It can be seen from Figure 3(II) that the maximum density of porosity values coincides with the 0.18-0.22 interval. This spread of values corresponds to 10% deviation from mean porosity. In the crosshole space, the deviation of porosity values is 0.6%, increasing to 0.8% toward field boundaries. The map indicates areas requiring updated data.

Oil Saturation Factor
The error in determining the oil saturation factor stems from the quality of interpretation of log data, reservoir resistivity determination error, groundwater level, height above groundwater level, capillary curve, etc.

According to the model, the distribution of the oil saturation factor is at its maximum in the 0.4-0.7 interval, which corresponds to 25% deviation from the mean (Fig. 3(III)). In the crosshole space, the deviation of oil saturation from the mean is 4.5%.



Uncertainty in Oil Properties
The oil shrinkage factor and density at the surface were determined as the average of a number of analyzed samples. To take the determination error into account, distribution functions were created with due account for the results of analysis of all oil samples in surface and reservoir conditions. The distributions provided the basis for calculation of oil parameter variances.

Uncertainty in Oil-in-place Estimates
After mapping of variances of each parameter in the oil-in-place estimation formula, variances of oil-in-place estimates are mapped by multiplying out variance maps for all parameters, provided that they are independent.

A map of uncertainties inherent in the density of oil in place is shown in Figure 4. According to the map, the overall uncertainty in field reserves may amount to about 10% of original oil in place.



A set of structural maps and maps of reservoir parameters with whatever errors they contained was used to produce a set of Vankor field reserve density maps, and estimation was made of the probability density and cumulative frequency functions for oil-in-place reserves expressed in tonnes. Over a set of a hundred realizations, the spread of oil-in-place estimates is within +-10% of the mean. According to the diagram of sensitivity of oil reserves to the major estimation parameters, the most tangible impact on uncertainty in oil reserves within the bottom portions of the reservoir is produced by oil saturation, although in most cases it is the gross rock volume. This can be explained by the fact that most of uncertainty is associated with the edges of the field and the space between two of its blocks, where rocks exhibit poorer reservoir properties (see Fig. 3).

Conclusion
The proposed method for assessing the overall uncertainty inherent in oil-in-place estimates makes it possible to plan detailed exploration of the field and to refine the reservoir management plan in order to reduce the combined geological risks and, consequently, increase the profitability of the project.

Labels: drilling risk assessment, Exploration, horizontal well, Label, modeling, oil gas, reservoir, Rosneft, Russia, Vankor field

posted by The Rogtec Team @ 10:50  0 Comments

TNK-BP strategy in exploration and production is focused on application of new technology to turn the Company's huge resources into proven reserves. TNK-BP's investment into seismic should be supported by solutions ensuring secure information storage, and investment into exploration should be supported by solutions ensuring data reliability and accessibility.



Oleg Bantyukov (ONBantyukov@tnk-bp.com), Data Quality Improvement Section Head, IT and Database Dept., TNNC


Pavel Potapov (PAPotapov@tnk-bp.com), Acting Head of Archive Systems Section, IT and Database Dept., TNNC

Data Management Organization of Tyumen Petroleum Research Center (TNNC) is in charge of developing a quality data management system in TNK-BP (see "Data Management: the Future is Defined by the Newly Established Organization", Innovator 20). Today, it manages all exploration and production data flows within the Company and supports all TNK-BP's Performance and Business Units. The Organization provides over 40 various services on corporate exploration and geological and geophysical (G&G) databases and archives to users from all subdivisions of the Company.

Creating TNK-BP Seismic Archive
One of the priority tasks for the TNNC data management specialists is to develop a corporate seismic archive.

The seismic data is currently stored in IT and Database Dept., TNNC, on a specially allocated 500 GB disc array, as well as in PCMS seismic data management system. However these recourses are not sufficient, and up to 75 percent of the information is stored on single-copy magnetic tapes. In standard conditions, these records loose their properties after five to seven years of storage. Thus, in several years the Company may loose up to 25 percent of the acquired seismic data if it does not provide the right storage conditions.

Moreover, data volume increase, random data storage on multiple media, data duplicating and lack of a consolidated corporate storage system hampers efficient work with the information and creates additional risk of data loss. These all dictated the necessity to develop a comprehensive shared information system to manage the seismic data and store primary seismic information and the results of its interpretation.

Over the last two years, TNNC has made major efforts to create and equip the Company's seismic archive which is to start working in 2009. In summer 2008, a core storage facility was commissioned; it is now being equipped - racks have been purchased to store the seismic data storage media (Fig. 1), their installation is planned for the next spring. Furthermore, terms of reference have been developed and approved to create an indexing system for the seismic data storage media. It is planned to begin its installation in December 2008. After that, the storage media will be marked and indexed. The system will provide for the opportunity to identify the location of the required data in 3D mode showing the numbers of the room and the shelf.



In January, a hardware and software complex will be shipped from Finland which will help expand the disc space for data storage and provide backup. In 2009, it is planned to equip the seismic data storage with a ventilation and humidification system to ensure reliable and longterm media storage, complete the data indexation, and arrange a centralized system for initial seismic data storage media search and complete the media bar-coding.

Data Quality Means Operations Quality
Another priority in data management is to ensure the quality of the G&G data. The lack of appropriate processes in the Company's PUs impacted data quality and integrity, as well as delayed its download into the Corporate Database (CDB). The inconsistence of information flows caused massive duplication both for the initial information and the interpretation results which resulted in the need for sidetracking and pilot drilling as well as causing unjustified expanses of the Company.



Data quality and integrity is negatively affected by the fact that PU specialists do not have a tool to check and visualize operational G&G data coming from the contractors. That is why the key objective for TNNC Data Management Organization in this field is to develop tools and software to control the quality and reliability of the information downloaded into the CDB. Data Quality Improvement Section within TNNC IT and Database Dept. is in charge of this work.

The Section initiated the development of software to convert unstructured G&G and exploration and production data into the Company's standard format and provided it to the contractors in geophysical studies. For the first time ever, the Company has developed regulations for the submitted data and the tools to convert the data into the desired format.

Thus, File Inkl View includes a standard algorithm to calculate directional survey parameters based on tool-measured parameters, such as depth, angle and azimuth; average angle method is used to calculate trajectory. VDL (variable density log) Converter is used to convert unstructured files containing cementing quality findings into structured WDEF files. Another tool, PGIS (Development Logging) Converter, converts unstructured files containing well log control findings into structured WDEF files. Templates for the created files are generated based on appropriate Corporate Technical Standards.

An effective tool was developed for PU specialists to evaluate input data quality based on certain criteria and visualize the acquired data in 3D mode.

File Inkl View is designed for directional survey data (Fig. 2). When analyzing the well data, the user can easily change the borehole image scale and dimensional orientation to view the trajectory from all sides. The software provides for batch control of structured files, and the quality of the provided geophysical data is assessed within minutes. FileTest is used to process structured text files containing well data in LAS (Log ASCII Standard) format, ver. 1.2, 2.0 and 3.0. PGIS Test checks the structured WDEF files containing well log data for certain types of errors, the list of which will be further expanded. Another tool, VDL Test, is used to menting quality findings. It helps identify gross errors in cement bond log findings at the initial stage, as well as submitting quality data to CDB.

All the software is conditioned for both individual and batch testing.

New Solutions to Ensure Data Quality and Integrity
To control the incoming file data integrity and track the information flow, TNNC specialists have developed ArchiveShare data flow management system. It includes of two subsystems.

The registering subsystem automatically receives the incoming data and includes it into own incoming database. The data sources may be an e-mail box, DVD, hard drives, or FTP. After this, the received data are located in dedicated file resources where they become available for further work.

The web-subsystem helps visualize these data. It has a set of functions to facilitate and manage data flow. Moreover, the web-subsystem uses e-mail to notify the users of key events, such as moving to the next stage of data processing or holdback.

To control data quality and integrity, CDB has tools for the comprehensive information assessment in data array. They help accumulate a studies knowledge hub which, in its turn, improves the data testing quality.

View Inkl is used to display and visually assess the quality of G&G information downloaded into BASPRO Database, including data on directional survey, segregations, layer intersection coordinates, wellhead coordinates, altitude, and correction of magnetic variation. The software enables us to track the path of an individual well or a whole well pad. Export Inkl is designed for modeling specialists. It helps obtain directional survey data for a PU from BASPRO Database. This can be done both in technical standard format (to submit data to regulators or contractors) and in a format ready to download into modeling software (subject to correction of magnetic variation).

In 2009 data management will become much more effective, upon implementation of technical standards and software for data quality control. The Company will be able to operatively track depletion of the remaining hydrocarbon reserves, simulate well interventions for enhanced oil recovery more accurately, and identify the most efficient and cost-effective options for reservoir development.

Labels: data management, Exploration, Information storage, production, Russia, seismic, TNK-BP, Tyumen

posted by The Rogtec Team @ 17:07  0 Comments

Ye. A. Kopilevich and D. N. Levin, Rosneft Oil Company OJSC
One of the most promising methods for solving the problem of predicting geologic section types and reservoir permeability and porosity in crosshole space is spectral-time analysis (STAN). An innovative technology for complex spectral-velocity estimation (CSVE) in two and three dimensional crosshole space has been developed based on STAN and pseudo-acoustic transformations of seismic log data (Ye. A. Kopilevich, I. A. Mushin, Ye. A. Davydova and M. L. Afanasyev, 2000-2008); the technology makes it possible to determine geologic section types and reservoir permeability and porosity in crosshole space by a set of geophysical methods with mean accuracy of -17% (including permeability) based on subsequent drilling data. The procedure and technology for determining reservoir permeability and porosity and predicted oil productivity in two and three dimensional crosshole space are based on the use of certified seismic spectral-time attributes (STA) and seismic volume spectral attributes (SVSA), pseudo-acoustic velocities (impedances), and their integrated interpretation using modern mathematical tools: artificial neural networks (multilayer seismic perceptron) and statistical spectral correlation algorithms.

Integrated analysis of certified STA, SVSA and pseudo-acoustic velocities (impedances) using statistical spectral correlation algorithms consists of selecting statistical, correlation and gradient curves of certified SVSA and VPAC, screening types and classification methods. Integrated analysis of attributes is performed on this basis, culminating in constructing data cubes and charting geologic section types (clusters) of productive oil deposits. The basis for selection of the mathematical algorithm for artificial neural networks (ANN) for integrated interpretation is the fact that artificial neural networks controlled by sufficiently complex algorithms always produce a better result than evaluations of the discriminability of classes by simple computation procedures.

Figure 1 shows spectral-time patterns (STP) for various geologic section types of reef carbonates at the Kuyumba site compared to the corresponding lithologic columns and cross-section photographs. The parallel changes in the STP of the section types and their geologic appearance is clear. Sections with maximum development of macrofracturing are advantageous, since they preserve their basic productivity even when the procedures for opening up and testing are patently non-optimal. This group includes section types 1 and 2. The average group includes section type 3. Interlayering of dolomite, shaly dolomite, sandstone and mudstone is characteristic of this type. Reservoirs with limited development of macrofracturing type 4 were considered unfavorable. This type features both limited inflow of formation fluids and the potential for reducing the inflow in the presence of non-optimal procedures for opening up and testing. Shaly section type 5 includes mudstone which is dolomitic to various degrees. Type 6 is made up of dolomites. These are coarse carbonate deposits along sunken block edges. The presence of fracturing is typical; fissures are almost completely filled with clay materials, as is clearly visible in the cross-section photograph.

All the information presented above indicates that the nature of the distribution of seismic energy in frequency-time coordinates in STAN columns and their energy spectra is extremely specific for the different types of reef deposits (Fig. 1). This circumstance makes it possible to conclude that each section type has its own individual spectral-time pattern, which is consistent with the different lithogenetic characteristics of the section types, commercial productivity, capacity, permeability, etc. The diversity of STP makes it possible to map the development zones of the 6 distinct section types according to area and plot a corresponding chart. The chart was confirmed by subsequent drilling with an actual confidence level of more than 0.7, which is a high-quality result for such complex geological conditions.

A second example of the successful implementation of the innovative CSVE technology in a carbonate section is shown in Fig. 2, where data cubes have been constructed and charts of permeability and porosity and geologic section types have been plotted for highly prospective Lower Permian deposits in the fault-line area on the continental shelf of the Pechora Sea.

On the chart of geologic section types (Fig. 2A), the largest prospective zone, located between holes 1 and 3, matches the contours of reef seismic facies in plan. The smallest such zones which match the contours of reef seismic facies are located north of hole 3. Low-prospective and non-prospective section types are mapped in the rest of the area.


Fig. 1. Spectral-time patterns, lithologic columns, gamma-ray logging curves and cross-section photographs of six section types of carbonate reef deposits.

Fig. 2. A) chart of geologic section types of Lower Permian carbonate deposits; B) data cube of Lower Permian reservoir flow capacity.

The flow capacity distribution of horizon I(P1) (Fig. 2B) in three-dimensional space indicates significant vertical inhomogeneity, with the exception of reef bodies. It is worth mentioning that flow capacity has not been studied previously (before CSVE) based on seismic exploration data.

Hence the new geologic information obtained with the use of CSVE technology makes it possible to distinguish clearly the areas of favorable geologic section types and elevated values of reservoir properties -reef seismic facies- in two- and three-dimensional space.

The innovative CSVE technology has proven extremely effective for studying fractured Bazhenov shaly reservoirs. As we know, the study of deposits, much less prediction of their properties, based on seismic exploration data is not always feasible, and the results can be ambiguous, since there is often no persistent connection between acoustic and impedance parameters and productivity. As an example of the successful use of CSVE, Fig. 3 shows a chart of predicted oil productivity of Bazhenov deposits in the Sakhalin area (Western Siberia); three major zones of isometric form can be distinguished, located in the western, northeastern and southeastern parts of the area. The rest of the area is characterized by low prospectivity. The prediction was confirmed by subsequent drilling, with a confidence level of more than 0.7, which is a high-quality result for such an unconventional problem.


Fig. 3. Chart of predicted oil productivity of Bazhenov formations in the Sakhalin area.

Predicting the permeability and porosity of Lower Cretaceous reservoirs based on seismic exploration data and based on a combination of seismic exploration and gravity exploration was proven effective at the Vankor field (terrigenous deposits). Charts and data cubes of the porosity factor, effective thicknesses and specific volume (based on seismic exploration data and a combination of seismic exploration and gravity exploration) (Fig. 4) of Lower Cretaceous deposits (zones YaK III-VII and NKh III-IV) and a flow capacity chart (based on seismic exploration data) of NKh III-IV deposits were plotted and constructed. A correlation was identified between seismic spectral-time attributes (STA) and the permeability factor, and a data cube of the permeability of NKh III-IV reservoirs was constructed (Fig. 5); this had not been done successfully before. The basic pattern of the distribution of reservoir properties is that zones with elevated values are located on the flanks of the structure.

Fig. 4. A) NKh III-IV reservoir permeability cube; B) horizontal section of permeability cube.



Fig. 5. Charts of NKh III-IV reservoir porosity factor (A based on seismic exploration data; B based on a combination of seismic exploration and gravity exploration).

Within the Slavyansko-Temryuk petroleum zone (terrigenous deposits), seismic STA were used in combination with the VP-IP attribute (based on resistivity exploration data) to predict the reservoir permeability and porosity of Chokrak III1 deposits. Charts of the reservoir properties were plotted based on seismic exploration data, and a chart of the porosity factor was plotted based on a combination of seismic and resistivity exploration (Fig. 6). The data yielded new patterns in the distribution of zones with high permeability and porosity.

These results indicated that the innovative CSVE technology based on both seismic data and a combination of geophysical methods is highly effective for an extremely wide range of seismic geologic conditions. The CSVE technology is a new and little-known technology; accordingly, it is worth noting that its use is recommended in the "Recommended Practices for the Use of Seismic Exploration (2D and 3D) Data for Estimating Oil and Gas Reserves" approved by the Russian Federation Ministry of Natural Resources and endorsed by the State Reserves Committee in 2006.


Fig. 6. A) chart of the porosity factor of Chokrak III1 deposits based on seismic data; B) chart of the porosity factor of Chokrak III1 deposits based on a combination of seismic and resistivity exploration; C) chart of the permeability factor of Chokrak III1 deposits based on seismic data.

Labels: CSVE, Exploration, Geophysical, Porosity, Reservoir Permeability, Rosneft, spectral-time analysis, spectral-velocity estimation, STAN

posted by The Rogtec Team @ 15:00  0 Comments

David Nims (David.Nims@bp.com) Mikhail Kholodov (MVKholodov@tnk-bp.com),

Upstream Technology
It is commonly acknowledged throughout the TNK-BP drilling community that the last five years were about building the capability, embedding some basic technology in the Company, increasing the volume of work - from 250 wells in 2004 to 850 wells this year. As Darryl Willis, Vice President Upstream Technology, puts it, the past has been about the growth.

The future is about not drilling more, but drilling smarter – drilling right wells in the right places, shifting from single-well bores to multilateral-well bores, etc. To drill smarter, numerous changes are currently underway in TNK-BP use of drilling technology, most of which are part of two major trends:

- Enhanced rig capability

- Cutting-edge drilling technology

Enhanced Rig Capability
Three years ago the Uvat project developed a hybrid Russian / international design that encompassed the best of both worlds. It combined a proven Russian BU-3000 rig structure that facilitates easier inspection, certification and familiarization with state of the art international internal components. These internal components had best in class electronics, bearings, modularization and reliability. The hybrid design increased the drilling distance of the rig from 1.5 km to almost 5 km.

This capability in conjunction with high angle Frac capability "J type wells" helped save $480 mln NPV by cutting the pads / wells ratio per field from 24 / 175 to 6 / 130. Most of this saving was the reduced infrastructure costs resulting from the ability to drill all the wells from six pads versus the original 24 pad design. Building on this learning, our OFS internal drilling contractor, NvBN, developed a rig enhancement design for 22 rigs in our internal fleet. This $280 mln investment was one of the key levers in improving our drilling capability to drill the much more complex wells. These well designs have evolved from simple S-Shape wells to high angle 850m horizontal wells with step-outs in excess of 3,500 m. This has kept TNK-BP's drilling investment ratios at circa $35 per ton for the last three years despite double digit inflation.

Again, building upon this learning the VCNG project has introduced three new high technology rigs into the VCNG program and consequently the well construction cycle have fallen from an average of 125 days per well pre-project (2006) to an average of 35 days with one well with a best in class delivery of 26 days. These new rig designs are safer and capable of drilling much faster and further than conventional rig designs. This knowledge and the new hybrid coiled tubing drilling (HCTD) learnings will be applied on future Greenfield projects as well as selective applications on our existing fields.

Our exploration program is one of the most successful in Russia with a reserves replacement track record that is the envy of the Western world. This capability and performance will be further enhanced by the development of high technology heli-rig capability. Currently our exploration rigs in the more remote regions manage to drill around two wells per year before the departing winter leaves them isolated from our supply lines. Heli-rigs open up the possibility of pre-supplying up to six wells per rig and flying the rig into location on a year-round basis. This is much more equipment-efficient and is common practice in the more remote parts of North America. Firm proposals are being developed for a pilot application in TNK-BP; again this will be another proven technology 'first' for TNK-BP in the Russian market.

Following the Long Term Tendering exercise Company went through in the second half of 2007, 35 new high technology rigs are due to be operational in the field by January 2009. These rigs vary in size from 125-ton to 325-ton units and represent the state of the art for their respective sizes. Taking this innovative approach will result in TNK-BP having one of most modern rig fleet in Russia

Cutting-Edge Drilling Technology
Samotlor BU has successfully developed extended reach drilling (ERD) capability using rotary-steerable systems that enable the bit to independently track a predetermined optimum path through the production sand. This provides very accurate well placement in the production sweet spot for horizontal lengths in excess of 800 m. Using this technology Samotlor BU has delivered initial production rates four time larger than normal and exceeding 1,000 tpd. Moreover, ERD has allowed us to reduce the number of pads and wells per field.

This ERD technology has now been adopted by Orenburg BU while Samotlor BU is moving the technology even further ahead by developing ERD capability for their future sidetrack program.

Orenburg BU has developed a 15-well pilot program for the introduction of underbalanced coiled tubing drilling (UB CTD) with Schlumberger. This combination of underbalanced and coiled tubing drilling allows reservoir penetration with minimal formation damage and is key to unlocking tight reservoirs - applications in other places in Russia have resulted in a four fold increase in production rates. Successful introduction in Orenburg opens the opportunity for application in more difficult areas such as Talinskoye with its massive reserves potential.

Hybrid Coiled Tubing drilling is a relatively new technique which combines fast moving trailer rigs of up to 200 t capacity with coiled tubing technology. They have been used extensively in Canada with 5,000 wells drilled every year for the last four years. These are fast, highly safe, automated, reliable, environmentally friendly, PLC (Programmable Logic Controller) electronic rigs that permit operations with five-man crews. The 35 km pad to pad move times from tree on to spud of less than eight hours with 1,500 m wells completed in less than a day is transformational.

Samotlor BU is taking the lead in developing the HCTD technology in Russia, the first new rigs are expected in field by the end of this year and by 3Q 2009 we expect to be operating six of these world class units. On the environmental side, in addition to the low footprint of the HCTD rigs we will also be developing a pilot for drill cutting re-injection back into the ground. This will allow us to dispose of our drilling waste in a more environmentally friendly, hygienic manner than the current systems and permit the use of more exotic, higher performing mud systems.

The new and upgraded rigs allow us to develop more productive reservoir access technologies such as multilaterals where up to four or more long reservoir penetrations can be drilled from a single mother bore. This eliminates the access costs of drilling the over burden on three of the four bores and significantly reduces overall drilling costs.

Currently four to six multilateral wells will be drilled by the end of 2008. Less spectacular but equally important developments in bit design, especially PDC bits, have decimated the well times in hard rock areas such as VCNG where average well times of 55 days per well have been cut to a "best in class" well delivery of 26 days. These are early days and there is still much work and delivery to come for applying this technology across the rest of our well portfolio. Other upcoming technologies include the adoption of oil based mud to speed up the rate of drilling, reduce torque, provide better borehole stability and increase our well step-out capability.

Managing the Technologies
These technologies are further complimented by new exciting methods of benchmarking our performance using enhanced performance management systems such as the new STEPS contractor management system which is already yielding and applying significant value in Samotlor BU.

All of this technology should be managed in a measured manner and consequently Tyumen BU will implement a new remote operations performance center (ROPC) in 2009. This center will take real time drilling data from multiple rigs and transfer it to a centrally resourced technical expert center. This center will have directional drilling, geological, mud and other experts monitor, map and benchmark the performance of each well against a predetermined best in class model.

This will help the specialists make real time immediate changes of well trajectories to optimize reservoir sweet spots to enhance production and allow identification of potential performance shortfalls before the failure occurs. All this technology is tried and tested and is essential to unlocking the tighter, more difficult reserves of our upcoming programs.

However, perhaps more importantly, these technologies are the fundamental basis for success in the offshore ventures of the future and commercial performance delivery will grant us the permission to develop and apply even more radical access technologies.

We are breaking the mold and creating new access opportunities to increase our production potential. We are creating world class drilling capability in Russia and accelerating the development of our younger highly capable staff. We will have the best equipment for them to test and develop the new boundaries of the future. The sheer volume of TNK-BP business opens huge opportunities to try new ideas provided we can change the mindset to an acceptable tolerance of failure, "if you never fail, you haven't tested the boundary."

Labels: Darryl Willis, drilling, ERD, Exploration, Extended Reach Drilling, oil gas, Orenburg, Rigs, Russia, TNK BP, Uvat

posted by The Rogtec Team @ 11:32  0 Comments