Drilling activity in most operations in Russia is a "controlled?? schedule of events. This makes the management of change process extremely difficult and challenging should the fundamental well design conditions fail or are no longer applicable. With little or no planned contingencies, recovery is usually difficult with unplanned events. For turnkey projects the general contractor is expected to to bear the cost for unforeseen events if these are not identified within the "project book". The use of technical institutes for drilling related field development planning is a thorough process culminating in what is normally referred to as the "Project Book??. However, the quality of the final product as with all roles requiring a level of expertise, is limited to the experience and competency of all contributors to the planning document. This is due to a combination of factors:
1. The absence of contractors at the field developing planning stage to challenge concepts and provide more realistic operational limitations;
2. Poor risk identification and mitigation process at the planning stage leading to loss of efficiencies and financial loss;
3. A reactive approach to project delivery;
4. Poor planning or a lack of it;
5. Lack of leadership or ownership through the project life-cycle; and
6. Undue interference from project stake-holders.
Project books are developed by institutes contracted by the operating companies. These project books are documented evidence that technical, health, safety and environmental considerations are accounted for to meet the requirements of the government. These documents are thorough and carefully formaulated. However, the lack of input from the field to project books makes contingency planning difficult to implement and sometimes and impossible consideration. Project books contain details of equipment and technologies to be deployed for each project. In most places if a plan becomes unattainable a management of change process may be required to adopt changes to ensure success. For most projects in Russia this is not the case. The general contractor model has been here a long time and there is no illusion of change apparent. It is a convenient way of doing business with advantages and disadvantages as well. One major advantage removes the bureaucracy of permits and licenses to operate specific types of equipment from the operator. It ultimately makes one company solely responsible for well delivery and all (or most) contractual relationships with sub-contractors. It transfers the risks associated with the project to the general contractor, thus making them liable.
For the general contractor, disadvantages are not limited to liabilities. Since contingency planning is not within the scope of the project books, it tends to create bottlenecks especially where it is not captured during risk assessment and subsequently in the compensation matrix. Furthermore, the process of decision making and ensuring client acceptance for compensation for costs related to unforeseen events, is rather cumbersome. The very same bureaucracy that is an advantage comes into play as each event is followed up by a series of carefully worded letters of correspondence with a stay of action on a matter until an official response is received. A typical approach in the West may need an email communication to the client as sufficient notification demanding immediate response for the operation to carry on..
This paper looks at some of the events over the cause of the last one year and their eventual impact to both the client and the contractor. Impact assessment to client/contractor can be quantified in monetary terms, inefficiencies and profitability as well as an estimate of the cost of not meeting production quota/schedules and the overall project delivery objectives.
Operators and service companies are considering alternative methods to remedy shortage of qualified and experienced staff to manage increasing activity and complexity. TNK-BP's approach has been creation of Drilling Support Center (DSC) as part of upstream peer review and technology center in Tyumen. The Company has eleven subsidiaries spread across Russia, and operations are managed by 6 regional drilling teams. DSC is centrally located to ensure geographical coverage of both eastern and western regions, with a mission to improve drilling performance, as well as support new technology implementation.
Main drivers for creating DSC were:
- Increasing complexity of wells and wide geographical spread,
- Limited drilling personnel with experience and expertise,
- Commencing international operations requiring central support,
The center currently provides support in three main directions; firstly, monitoring complex and critical operations using real-time link from rigs by experienced staff with relevant expertise, including regular contact with operations teams to provide proactive feedback. Second direction is engineering support to well planning and new technology implementation by experienced specialists in directional drilling, cementing, drilling fluids, completions and drillbits. Third direction is Geosteering support of horizontal wells including real-time update of sector models. The center is active over a year now and subsidiaries regularly contact DSC for critical operations review.
In this paper is given an estimate to the resource potential of the Artic shelf of the Russia and prospects of its development. The comparative analysis of multiphase technologies of wellstream gathering, applicable for conditions of Arctic shelf on an example of fields of the Barents and Kara Seas, is carried out. Various aspects of the joint transport system application of gas hydrates and oil on one pipeline for solving the problems of associated petroleum gas utilization on an example of the Artic shelf fields are considered.
This paper describes the MINK tool which is based on pulsed neutron-neutron (PNN) logging technology, its key principles and differences from other logging and data interpretation methods, and illustrates its applications to estimating oil saturation in wells.
The principal feature of the MINK tool is its data recording technique in which all neutron-count decays are saved to memory and processed separately. In conventional PNN logging, 100 decays are initially accumulated and then averaged before processing, which results in information loss.
Theoretical considerations and available experimental data have indicated that the probability distribution of neutrons is governed by Poisson's law  and allows the use of the maximum likelihood method (MLM) for experimental data fitting  with a substantial advantage over the conventional least-square method (LSM). This was particularly important for reservoir characterisation, as the rock's response is mainly recorded at late times. Neutron count rates at late times are small, and the least square method becomes a hit-and-miss technique. The authors have developed algorithms and software for the efficient and reliable determination of single- and double-exponential approximation parameters using the maximum likelihood method.
The processing of data from three selected wells has shown that Sigma profiles determined by the least square method are noisier than those determined by the maximum likelihood method. Moreover, some thin reservoir units were not seen in Sigma profiles obtained by the least square method, in contrast to those obtained by the maximum likelihood method.
Statistical modelling has been performed to validate the developed algorithms. Decays with experimentally determined decay times and Poisson's distribution of neutron count decays have been generated. Modelling data processing has shown that the maximum likelihood method provides 1.7 to 2 times higher accuracy than the least square method under equal conditions or 3 to 4 times smaller data collection volumes.
The MINK technology is expected to determine the oil content in dense reservoirs and low-salinity wellbore fluids.
This paper was included on the proceedings CD for the 2012 Russian Oil and Gas Exploration and Production Technical Conference and Exhibition as SPE 162969. The correct paper number is SPE 163096.
The main problem of pipeline transport of associated petroleum gas (APG) and natural gas - the need for transfer of a multicomponent hydrocarbon mixture. The purpose of this paper is the disclosure of technical, methodological, and economic aspects of a comprehensive approach to training, transportation and processing of gas through the use of supercritical states of multicomponent hydrocarbon mixtures for deposits of oil company OAO "Rosneft" in the Western and Eastern Siberia. The development of this technological approach allows oil and gas organizations to more effectively utilize resources and achieve routine associated gas utilization degree of the problem which, to date, is associated with a weak refinement and low cost-effectiveness of technologies proposed for utilization of associated gas. Of particular importance in this context takes the introduction of innovative technologies capable of solving many problems faced by the subsoil user during transportation of hydrocarbon gases.
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-160741-MS.
Two large identical 6-cylinder Ariel JGB/6 reciprocating compressors each of 7.5 MW, are used for an underground gas storage system in (UGS) plant located in Epe, Germany.
The compressors can be operated at a wide range of operating conditions, e.g. variable suction and discharge pressures, 2-stage mode during gas storage, 1-stage mode during gas withdrawal, capacity control by speed variation and valve lifters.
The system should operate efficient, safe and reliable for the complete range of the operating conditions, which can be guaranteed by an extensive optimization analyses during the design stage of the project. For that purpose TNO has carried out different dynamic analyses according the API Standard 618 to be sure that the system can operate efficient, safe and reliable for the long term. In the present paper a summary of the underground gas storage system is given and the different steps in the optimization process of the system have been indicated. Finally, the results of vibration measurements after start-up of the system are presented, conclusions and remarks are given.
Biryukov, S. D. (JSOC Rospan International) | Zakirov, I. S. (JCS TNK-BP Management) | Severinov, E. V. (JSOC Rospan International) | Gaidukov, L. A. (JSOC Rospan International) | Miroshnichenko, A. V. (TNK-BP LLC TPRC) | Kudlaeva, N. V. (TNK-BP LLC TPRC) | Endalova, Y. V. (TNK-BP LLC TPRC) | Chameev, I. L. (TNK-BP LLC TPRC)
The new green fields of Yamal region and Eastern Siberia today is one of the important areas for oil production during next 10 years. One of the key problems of field development in these regions is poor infrastructure and lack of input data of geology, target formations and fluids properties. For decision making during field development preparation stage its necessary to carry out estimation of possible scenarios.
Analysis of uncertainty will provide a range of changes in reserves and oil production profiles which can help to estimate economical part of field development project. Also these results can be used for design pipe lines and surface facilities.
Authors of paper suggested the approach how to estimate uncertainties in cases of lack input data of formation based on data of Russkoye oil field.
More than ninety eight percent of natural gas used in Turkey is imported predominantly from Russian Federation, Azerbaijan and Iran by pipeline, and Algeria and Nigeria as LNG. As in most developing gas consuming countries, Turkey's natural gas consumption varies in seasonal basis. Therefore, the country has had to work consistently to develop its transmission and storage systems. As a solution to this, Turkish Petroleum Corporation (TPAO) decided to convert the producing two gas fields, Kuzey Marmara (off-shore) and Degirmenkoy (on-shore) into underground gas storage facilities to accommodate seasonal variations in natural gas consumption.
The main reasons in choosing the Kuzey Marmara (K. Marmara) and Degirmenkoy fields as gas storage are the proximity of the fields to the gas pipeline network and Istanbul, and their suitability for gas storage because of their reservoir characteristics. The project area, however, is located in an environmentally sensitive region, which is also popular with its recreational and residential areas. Authority requirements regarding emissions, noise and other aspects were extremely severe.
The Silivri (K. Marmara and Degirmenkoy fields) underground natural gas storage (UGS) facilities with a storage capacity of 1.9 billion m3 were became operational on 13th of April 2007. Gas from the existing supply pipeline is currently being injected into the storage reservoirs and subsequently reproduced into the supply pipeline during the periods of high demand.
This paper provides the design and development process of the first and the only underground gas storage project of Turkey and also presents the status quo after the first three complete cycles.
Stenin, Vladimir (Lukoil) | Delia, Sergej (Lukoil) | Levchenko, Vladimir (Lukoil Engineering) | Vereschagin, Sergei Alexandrovich (Schlumberger) | Butula, Kreso Kurt (Schlumberger) | Enkababian, Philippe (Schlumberger)
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-160754-MS.
Rakushechnoe-8 is one of the exploration wells drilled in the Northern Caspian Sea. The understanding of the geometry and performance of the propped fracture completion in the Apt formation was considered critical for the economical development of this offshore oilfield. Because of this, and the potential risk of fracture breaking into the water zone below, no resources were spared and robust engineering methods were applied for the first time in Russian offshore operations to determine the formation productivity without and with a hydraulic fracture completion in place. This case history will detail how a planned joint engineered approach provided critical information for the reservoir and production teams to determine the formations potentials, ensuring at the same time reliable and safe offshore operations.
After a detailed feasibility and engineering study, a local supply vessel was converted into a stimulation vessel to meet the maritime regulation requirements and projected needs of the Russian Federation. As part of the Project Readiness Assessment, the 4000-HHP strong frac equipment was mock-assembled on the dock, tested, and all the hazards evaluated before sailing. The joint engineering team prepared a rigorous plan for multi source data collection before, during, and after treatment operations. The plan included running dipole cased hole acoustic measurements before and after the frac treatment, bottomhole pressure gauges, a complete mini-frac test, multiple post mini-frac temperature logging runs, production logging runs, and well testing and sampling operations before and after the frac. Finally, a novel vertical seismic profile and micro-seismic measurement was employed to further understand the hydraulic fracture behavior in the Apt formation.
The data analyzed before the main fracture treatment enabled safe placement of all 49 tons of 16/20 mesh Intermediate Strength Proppant (ISP) through the drillstem test string obtaining a Cfd = 2.7 deemed optimal for the formation.
Post frac measurements and semi numerical modeling indicated that the mechanical model created before the mini frac required some additional modifications and that the propped fracture remained within the target zone. The acoustic and microseismic post frac measurements and well-test results correlated with the expected fracture effective half-lengths and conductivity, confirming that the preparation and execution involved with attaining accurate measurements provided significant value.