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Abstract The depletion of the majority of mature fields with the best reservoir properties and the easiest extracted reserves determines the necessity of involvement in the elaboration structurally complex reservoirs of different kind. Among them a special place occupy laminated sands, which can contain and produce oil and gas. However, ther is a number of problems associated with determination of their reservoir properties, reserves volume and effective development. In this context PK formation of Russkoye field in Western Siberia is the classical example of such kind of objects (Pic. 1.). The main problem is that the shale microlayers are not resolvable on the logging curves, as their thickness is much less than the resolution of the main well logs. The logging methods characterize integral rock properties (sandstone and shale alternation). The usage of classical approach does not allow determine the real properties of sandstones, and net thickness estimated by conventional log evaluation is not real, as it contains impermeable shale microlayers. So, the petrophysical model of homogeneous reservoir, made previously, does not correspond to the results of hydrodynamic modeling. There was no success in its adaptation without significant increase of permeability and oil and gas saturation.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
Abstract At different penetration depths, mud-component invasion creates multizone structures in the vicinity of the wellbore. These structures include external mudcake (mud particles and mud clay deposited at the sandface), internal mudcake (which is formed by mud particles invaded into the reservoir formation), and mud-filtrate invaded zone. We present a new technique for estimating empirical parameters of both external and internal mudcake by combining laboratory data on mud flooding experiments and measurements of the profile of the invaded mud components by X-ray microcomputed tomography (XmCT), image processing of core cross-section photography, and ultrasonic wave scanning. The technique is validated on flooding experiments with simple ("model") muds: slurry of bentonite clay, suspended solid particles and polymer Xanthan. Examples of reconstructed profiles of invaded mud components (solid particles and bentonite clay) as well as the procedure of determining internal mudcake parameters are provided.
- Europe (0.29)
- North America > United States (0.16)
Abstract Subsea pipeline transportation is a subject of hydrates/ice associated problem, risk of exposure of hydrates-related issues is significantly increased in extremely cold arctic condition. In case of emergency situation or technology process failures could result to partial chock or complete hydrates blockage of long part of subsea transportation system. In such case scenario costly and time-consuming replacement of affected pipeline section could not be carry out in safe manner because of presents of high pressure gas pockets distributed in hydrate plug. To reduce the overall risks, new technology and improved operational efficiency are required to meet the ambitions for hydrates plug removal. Coiled Tubing conveyed method is proposed as a light weight and efficient in both mobilization and operations point of view that enables operations to be performed more quickly and put pipeline on stream faster. Coiled Tubing equipment could be installed on wide range of types of marine vessels that helps to perform the job in a more cost and time effective way. This paper review the engineering and operational challenges related to utilizing Coiled Tubing in offshore pipeline intervention and the solutions required overcoming these issues. Advantages of usage Coiled Tubing technology: Small footprint; Versatile service offerings; Not rig-dependent; Reduce risk of damaging pipeline; Return pipelines to transportation faster; Lower risk of equipment getting stuck; Reduced personnel; Fewer lifts; Cost-effective; Improved logistics; Increased flexibility; Less people are being exposed to fewer risks; HSE advantages.
- Europe > Norway > Barents Sea > Hammerfest Basin > License 100 > Block 7121/7 > Snøhvit Field > Stø Formation (0.99)
- Europe > Norway > Barents Sea > Hammerfest Basin > License 100 > Block 7121/7 > Snøhvit Field > Nordmela Formation (0.99)
- Europe > Norway > Barents Sea > Hammerfest Basin > License 100 > Block 7121/5 > Snøhvit Field > Stø Formation (0.99)
- (30 more...)
Abstract Inflow Control Devices (ICDs) are used as a permanent part of the well completion to control and to effectively equalize the inflow from the reservoir to the wellbore along the length of horizontal section. Key consideration in ICD optimization are good reservoir modeling using in-house and commercially available Petroleum Engineering software, complete geological data from the existing wells and accurate permeability profiles (minimum and maximum permeability values and well test analysis). Successful design and implementation of ICDs in horizontal sections depends on identifying and evaluating the correct Key Parameter Indicators sets (KPI's). The optimum ICD selection and placement is achieved by evaluating both non-ICD completion as a basic scenario and, a set of scenarios with varying pressure drop through the identified isolated zones along the horizontal wellbore (compartmentalization). Selection is governed by the appropriate ICDs selection and Flow Restriction Ratings (FRR) setting. The ultimate goal is to the maximize the recovery factor by generating a uniform flow pattern through the drainage area in long horizontal wellbores, despite the differences in the frictional pressure drop from toe to heel, which is of major concern regarding water and gas coning. In addition to a good understanding of both reservoir behavior and sand control completion technology, the process under discussion will help to overcome the geological challenges and to maximize the production.
- North America > Canada (0.29)
- North America > United States > Texas (0.28)
- Europe > Austria (0.28)
- South America > Brazil > Campos Basin (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Surmont Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- (11 more...)
Abstract As the world's population continues to grow, the energy demand is forecasted to increase directly proportional by 52% in between 2010 to 2035 (OPEC, 2013). With the oil prices predicted to be stable in the long run and expected to be as high as $165 per barrel by 2035, the search for more oil continues (OPEC, 2013). An estimation of 70% world's oil and gas production originates from mature fields with recovery at an average of 35% worldwide (Hull, 2012). This proves that there are still opportunities to recover more through enhanced primary, secondary or tertiary recovery in creating further hydrocarbon flow of a mature field. Lower reserve with high operating and field redevelopment cost for a tertiary recovery program has deteriorate the economics for a mature field. Developing tertiary recovery for a mature field requires major modification at surface and sub-surface. Leaving the operators with the challenge to maximize recovery under current operating conditions and limited work scope of a primary recovery mainly through artificial lift method such as gas lift in oil wells. Gas lift has been part of the primary oil recovery ever since the 1800s and the effectiveness has proven to aid the acceleration of oil recovery in a well for centuries (Gas Lift: Wikipedia, 2014). Deterioration in surface equipment and sub-surface well completion condition in a mature field, such as worsening well integrity with leaks and holes, inaccurate production metering, instability of gas compressor availability and efficiency, has resultant in the ineffective of gas lift distribution and injection downhole. Despite the challenges faced, through prudent technical analysis and effective execution at site, the production of D-field in Malaysia has managed to increase up to 8,000 bbl/d (barrel of oil per day) instantaneously merely through production and gas lift optimization exercise. This paper will run through the challenges faced and the technical analysis conducted in overcoming the handicap at site. This has led to the successful implementation/formulation of production philosophy and strategy to overcome challenges under different production scenarios, resulting an instantaneous production gain of some 30%. To some extent the production has been sustained and the decline arrested.
Abstract Formation overpressures have traditionally forced operators to weight-up mud systems in order to advance drilling operations while preventing formation fluids invasion. As a result, drilling rate of penetration (ROP) is reduced, additional casing seats/strings are required and risks associated with kicks are increased. This drilling hazard is a major source of invisible non-productive time (NPT) and increased operational costs. Today's drilling environments present many challenges, such as high-temperature/high-pressure (HPHT) with mud losses and fluid or gas influxes that require a lot of time and resources to address. Inaccurate or late detection of an influx can result in costly nonproductive time, or in some cases, increase the likelihood of a well control incident. Improper mud weight management to control a kick can result in increased of differential pressure and mud losses if the reservoir frac gradient is exceeded. This in turn will cause fluid kick and mud loss cycles that will cost weeks of rig time and millions of dollars. These operations result in reservoir damage, reduced flow rate, minmized production or even the need to sidetrack. This paper will further explain MPD techniques and its unique ability mitigate today's toughest challenges related to a wellbore's pressure profile. We would like to discuss the possibilities of the system to indicate the kick and losses on early stages and address them accordingly to the automatically controlled system. The system will allow to separate the kick from such events as ballooning and breathing, run dynamic FIT and LOT tests, will let to determine the actual pore pressure figures throughout the intervals of interest, simultaneously control influxes and losses before they get built into the well control events. Using the MPD can be the key for most of the applications to enhance safety, improve drilling efficiency and to get a better understanding of the fields nowdays and further on.
- North America > United States > Texas (0.28)
- North America > Mexico (0.28)
Abstract This paper describes a methodology for waterflooding pattern optimization based on multi-criteria analysis of the interaction between producers and injectors. This method takes advantage on the use of streamlines which are generated from the post-processing of finite difference simulation results to define the flow paths between injectors and producers and characterize flow allocation between interacting wells. This information is then combined with well production/injection data (oil / water rates, pressures etc.) to calculate parameters like compensation ratio and injection efficiency for each well. Having all this information, a set of cross-plots is used to rank the producers and injectors by their sweep / drainage efficiency. The results of such analysis allows the planning of workovers, optimization and allocation of the volumes of injected water and ultimately enables a comparative assessment of the efficiency of each individual workover event in terms of incremental oil production, water-cut reduction and decrease in non-effective water injection. One of the advantages of this method is the use of already available results from finite difference simulation. This fact dramatically increases the time available for the waterflood optimization process and significantly widen the range of scenarios where streamlines technologies can be applied. Moreover, this approach does not require significant or time-consuming computational efforts, which make it a very convenient decision-making tool for field operations planning.
- Asia (0.46)
- North America > United States (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.39)
Practice and Future Potential of Multilateral Horizontal Drilling for Lower Permian Reservoirs: Case Study from Lemezinskoe Field
Krasnevsky, Yu. S. (JSOC Bashneft) | Ganeev, A. I. (JSOC Bashneft) | Mescheryakov, O. E. (JSOC Bashneft) | Chervyakova, A. N. (LLC BashNIPIneft) | Trofimov, V. E. (LLC BashNIPIneft)
Abstract Lemezinskoe oil field is situated in Iglinsky region, Republic of Bashkortostan, 84 km to the east of Ufa and 35 km to the south-east of the regional center Iglino. The field is located in the region with well-developed infrastructure. In the regional tectonic setting the field lies in the northern part of the Belsk Depression, Pre-Ural Foredeep Basin. It is associated with a buried Lower Permian reef build-up (P1ar-P1s). Oil shows of various intensity and nature were recorded in the Kungurian, Artinskian and Sakmarian sequences. Commercial oil reserves of Lemezinskoe field are discovered in the porous and permeable limestones of the productive Artiskian-Sakmarian reservoirs. The reef build-up consists of carbonates which differ in their mineral composition, origin, structure and texture as well as porosity and permeability. The oil is heavy, viscous, waxy and sour. One production target is identified within the field and two reservoirs which are located at a considerable distance from each other. The key parameters of the developed Artiskian-Sakmarian Reservoir 1 (Reservoir 2 is not developed due to its location in the sanitary-protection zone) are summarized below. The reservoir layers within the body of the reef are characterized by discreet spatial distribution. In most cases the permeable streaks are isolated by tight carbonate rocks. Well-to-well correlation of the reservoir intervals is impossible due to the heterogeneous lithology of the section. Geological cross-sections show the distribution of the reservoir intervals only in the wells whereas in the interwell space the presumed distribution pattern is rather schematic and simplified (Fig. 1). One distinct feature of Lemezinskoe field as a reefal build-up is lack of biodegrated oil or gas cap.
- Geology > Mineral (0.86)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.69)
- Europe > Russia > Volga Federal District > Bashkortostan > Lemezinskoye Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.98)
- North America > United States > Texas > Permian Basin > Yates Formation (0.98)
- (22 more...)
Abstract Various inhibitive additives are used during drilling in the Vankor deposit to stabilize the clay slate, such as Polyacrylamides, Acrylic polymers, inorganic Silicates, Asphaltens and Glycol mixtures. These reagents are used in aqueous slurries to help drill surface casing and process and extract columns. Complex drilling conditions related to well trajectory, increased penetration speed, and increased rate of locating an instrument at the bottom hole continue to warrant the search for improved tools to better penetrate wells, increase wall stability, and optimize the drilling slurry process. For such reasons, it was decided to perform an industrial test on a new compositional inhibitor with a secondary function as a lube additive and microsealant. The service company proposed (and the operator supported) compositional inhibitor testing consisting of a dissolved sulfur asphalten mixture in glycol in certain proportions specially developed to increase the efficiency of inhibitive properties and the multifunctionality of an additive. The testing was applied in a complex well (168° along the azimuth, horizontal projection length of 1,771 m, and a penetration angle of unstable argillites at 63.5°) to help demonstrate the technical efficiency of the new reagent (full dispersion in the aqueous drilling fluid, reduced processing time, and improved productivity of the treatment system) and the practicality of launching it (reduction/replacement of single-component inhibitors) in industrial volumes within Vankor field wells.
- Asia > Russia > Siberian Federal District > Krasnoyarsk Krai (0.74)
- Europe > Russia (0.70)
- Asia > Russia > Siberian Federal District > Krasnoyarsk Krai > Vankorskaya Area > Vankorskoye Field (0.99)
- Oceania > Papua New Guinea > Papuan Peninsula > Central Province > National Capital District > Petroleum Retention License 15 > P’nyang Field (0.97)
- Oceania > Papua New Guinea > Papuan Peninsula > Central Province > National Capital District > Petroleum Retention License 15 > Elk-Antelope Field (0.97)
- (13 more...)
Abstract The success of the drilling campaign including drilling efficiency, service quality, personnel safety and cost is critically dependent on robust solutions developed during the design phase of the overall well construction process. One of the most critical stages of the overall well construction process is the well design phase. The drilling project service quality, personnel safety, drilling efficiency and cost directly depend on the robust solutions elaborated at the design phase. This paper describes the advanced technical engagement between an operator and an integrated services company to generate a basis of design for drilling and completing development wells in the Filanovskogo offshore field, in the north of Caspian Sea. The basis of design is a document that describes well design principles, engineering solutions and technologies required to drill and complete the wells. The paper explains the design approach selected by the project team, project design stages, foreseen challenges and technical solutions to deliver efficient well designs that could meet operator requirements and comply with Russian regulatory rules. The key technical challenges of the Filanovskogo field are that the reservoir zone is located at shallow true vertical depth (TVD); the high formation collapse gradients and low mud loss gradients create a narrow mud weight window environment, along with complicated well profiles involving – multilateral horizontals and extended reach (ER) wells. This paper illustrates the development of a basis of design to ensure cost-effective access to reserves. It covers the operator and the service company experience in the drilling of ERD wells, applying advanced technologies for windows milling, completion options screening process and designing a multilateral junction. It also provides an understanding of the importance of operator and service company departments integration processes in order to achieve well objectives. To support the basis of design development, a comprehensive risk register was generated to minimize drilling risks. The process of technical integration between the operator and the service company in the early stages of operational planning by developing drilling and completion design is unique for Russian O&G operators and was done by assuming that it would be very efficient through providing technical integrity and minimizing the project risks. The drilling and completion design consideration processes described in this paper can be used to provide valuable insight for future projects where up-front complex technical study is key to success.
- North America > United States (1.00)
- Europe (0.68)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)