The emergence of real-time enabled support centers has significantly improved the level of service delivery that is received by the operator companies that are drilling across the numerous oil fields in Russia. These support centers are multidisciplinary in approach and are focused on supporting measurement-while-drilling, logging-whiledrilling, and directional drilling services and executing work flows without incurrence of nonproductive time. Many challenges, ranging from ensuring connectivity in remote areas to client acceptance of the role of support centers in their internal decision-making processes, have been successfully overcome. Key to this success was the implementation of work flows that optimize drilling processes in the holistic well construction cycle with incorporation of geomechanics and that support the optimal geological well placement based upon petrophysical analysis and interpretation.These process work flows were synthesized to capitalize on the strong petrotechnical expertise and synergies existing within the collaborative environment of the support center. To further improve on the performance of such support centers, an engineering study was conducted in 2010 to assess further possibilities for improving service quality. Several areas of opportunity were identified, one of which included the incorporation of Lean and Six Sigma techniques to quantify the effect of modifications on these work processes. It was critical in this assessment to ensure that these process work flows seamlessly integrated into the work flows of the internal and external stakeholders that are beneficiaries of the support centers. This paper discusses the results from the initial generations of these process work flows and the way forward for the continued process work flow integration, using a support center that was developed in Russia as an example. The application of these work flows has brought demonstrable financial and service-quality benefits to both operators and service companies, and the broader applications in its consistent execution have presented a critical step change in Russian environment drilling performance.

Evolution in the manner in which real-time data is provided by service companies in the drilling industry has led to real-time data being available via the Internet from most wells drilled worldwide. The platform for viewing this real-time data is usually through a variety of viewers embedded in Web server software. By using technologies to enable the clear presentation of this Web-based data in real time to the end user—including data visualization, model comparison, and rig time usage—it is possible to improve real-time collaboration and perform drilling optimization actions from both a location remote to the wellsite (e.g., the operator's office or even a service company office) and the wellsite itself. By looking at three case studies in two locations (the North Sea and the Gulf of Mexico), it is possible to show how technologies that enable collaboration between onshore and offshore personnel and manage drilling risks not only improve operations monitoring and reporting but reduce drilling process time. The three case studies demonstrate aid which eliminated an intermediate liner string; improved real-time understanding of well conditions by managing hole cleaning and drilling risks, ensured that a casing string could be successfully landed on bottom; and enabled cause-and-effect analysis of drilling events in real time in addition to post event analysis for improved evaluation of the drilling process. In all these cases, the use of enabling technologies within one integrated application brings advantages to the drilling process through the clear presentation of real-time drilling data, which allows easier interpretation of real-time drilling measurements. Introduction With the advent and evolution of the digital oilfield, an increased flow in real-time data is readily available to any operating company for drilling operations at any rigsite (Zachariah et al, 2002; Kartviet et al., 2003; McCann et al., 2004; Nathan et al., 2006; Milter et al., 2006; Edwards et al., 2006; Lauche et al, 2006; Gyllensten et al., 2006; Tollefsen et al., 2006). In turn, this flow of data provides drilling engineers with an improved understanding of events occurring at the rigsite in near real time and increases the data, originally only available from the daily paper report, to continuous, real-time data. But, visualization of past events and long-term trends have until now been limited by the method of visualization, e.g., via website-imbedded log packages or application-specific data-visualization packages. The next step in improving visualization and interaction with drilling data at either remote locations (for example, at client or service company offices) or at the rigsite is to improve interaction capabilities of the software to allow improved analysis and visualization of the real time data present at a web-based location. In the case of this paper, the application presented is a standalone software toolkit with the capability to simply pull data directly to any server which has adopted the Wellsite Information Transfer Standard Markup Language (WITSML) 1.31 standard; but it can additionally be used with other servers and data types. The software toolkit application is an integrated data visualization and interaction tool designed specifically for drilling optimization services. Within this paper, we present the advantages of using such an application within the drilling domain. With its significant technology enablers, the toolkit not only aids drilling optimization, but it can be used to improve collaboration and decision making by being an enabler to expertise. Expertise Enabling Technologies Within the application being presented there are a number of technologies that enable expertise to be applied easily and efficiently.

Drilling on top of the Mesa in the Piceance Basin presents a significant loss circulation and stuck pipe challenge to operators wanting to exploit the huge gas reserves in the area. Operators have experienced losses that exceed 4000 barrels of mud when the intermediate section is drilled using conventional techniques. This is due to a combination of natural fractures and weak rock. Various strategies have been deployed to tackle the problems, including under-balance drilling operations and Direction Casing While Drilling (DcWD). A new technique described in this paper is now the best practice for ConocoPhillips in the area. It involves acquiring realtime circulating density (ECD) measurements and control of mud weight in the annulus, using direct air injection through a parasite aerating string (PAS).During the development stages of this new process an annular pressure sub (APWD) was run to gather diagnostic data. Analysis of the data shows conventional drilling practices often yield up to 3 ppg variation in circulating density exposed to the formation. Analysis of the data also suggests there is a fracture reopening gradient of approximately 8.3 ppg and there are huge circulating density variations during connections. The new strategy shows these wells can be drilled with an ECD in the range of 5-7 ppg using conventional water based mud systems. This strategy allows wells with a very narrow mud weight window to be drilled safely. This simple approach avoids the use of complex multiphase models, giving the flexibility to quickly deploy the technique to the well site without the need for expert personnel. The information enables the driller to control and keep the ECD within recommended limits, delivering a safe and productive well.The alternative approach of using conventional well design techniques would result in multiple casing strings and cost overruns, while more advanced techniques such as DcWD and under-balance drilling would require specialized equipment and crews. This new technique uses existing and common drilling technologies along with new software tools for geomechanics analysis and drilling surveillance to achieve excellent results. This paper presents a simple risk management technique using today's conventional technologies to successfully manage loss circulation risk in the Piceance basin.

Drilling on top of the mesa in the Piceance basin presents a significant lost-circulation and stuck-pipe challenge to operators wanting to exploit the gas reserves in the area. Operators have experienced losses that exceed 4,000 bbl of mud when the intermediate section is drilled using conventional techniques. This is because of a combination of natural fractures and weak rock. Various strategies have been deployed to tackle the problems, including underbalanced-drilling (UBD) operations and directional casing while drilling. A new technique implemented by an operator in the Piceance basin is described in this paper; it involves acquiring real-time equivalent-circulating-density (ECD) data and control of mud weight in the annulus by use of direct air injection through a parasite aerating string (PAS).During the development stages of this new process, a real-time annular-pressure sensor was run in the bottomhole assembly (BHA) to gather diagnostic data. Analysis of the data shows conventional drilling practices often yield up to 3 lbm/gal variation in ECD exposed to the formation. The analysis also suggests that there is a fracture-reopening gradient of approximately 8.3 lbm/gal and that there are significant ECD variations during connections. The new strategy shows that these wells can be drilled with an ECD in the range of 5-7 lbm/gal using conventional water-based-mud systems. This strategy allows wells with a narrow mud-weight window to be drilled without significant mud loss to the formation. This approach avoids the use of complex multiphase models, and the downhole ECD can be displayed on the driller's console in real time from the data measured by the annular-pressure sensor and sent through the mud-pulse-telemetry measurement-while-drilling (MWD) tool. Alternatively, if an annular-pressure sensor is not included in the BHA, the downhole ECD can still be estimated accurately by use of a simple spreadsheet calculation (Scott 2009). This gives a measure of flexibility in deploying the technique to the wellsite. Expert personnel were used in the initial diagnostic stages to establish the procedures and validate the effectiveness of the technique. After that, they will not normally be required at the wellsite to manage the process in subsequent wells because the ECD data from the annularpressure sensor can be understood by the driller, and the alternative spreadsheet solution, if used, can also be managed by the wellsite supervisor to calculate a reliable downhole ECD measurement. The ECD data enable the driller to control and keep the annular pressure within recommended limits, ensuring that lost circulation risk is reduced and wellbore stability is maintained.The alternative approach of using conventional well-design techniques would result in multiple casing strings and in cost overruns, while more-advanced techniques such as directional casing while drilling and UBD would require specialized equipment and crews. This new technique uses existing and common drilling technologies along with new software tools...

The Verkhnechonskoye (VCNG) oilfield located in Eastern Siberia is developed on pad clusters, with in excess of 200 wells drilled to date. Typical well geometry consists of a vertical 13 3/8in. conductor followed by directional 12 ¼ in. and 8 ½ in. sections ran with subsequent 9 5/8in. and 7in. casing strings. Production hole is drilled in 6in. with a 4 ½in. liner set prior to completion. The predominant well design incorporates a double build profile which lands horizontally in the Verknechonskiy reservoir with an approximate 600m lateral drilled in the productive zone. VCNG field has evolved of key strategic importance to deliver oil through the Eastern Siberia Pacific Ocean (ESPO) pipeline from Russia to the vast Asia-Pacific market located to its South East. Increasing production targets have been required to deliver hydrocarbons to fulfill aggressive pipeline commitments. Meeting these requirements have in turn initiated a relentless drive to enhance operational efficiency since the inception of development drilling phase in 2007; leading to a significant increase in drilling performance and reduction in overall well construction time in the period to date. This improvement has been achieved against the backdrop of an environment which is extremely challenging on several distinct fronts; remoteness of the project with >600km from the nearest major conurbation, harshness of an extreme continental climate with temperatures seasonally dropping to -50°C and coupled with a unique and problematic lithological column all serve to make drilling, logistics and general operations a complex undertaking. The purpose of this paper will be to take a holistic review of drilling performance in the field and to chronicle the numerous incremental technological and procedural advancements which have led to a reduction in average well construction time from 58 to 21 days between 2007 and 2011. Incorporated into this dramatic efficiency improvement includes a 465% increase in average well ROP along with a corresponding increase in meters drilled per circulating hour (MPCH) of 390%.