bluuebunny/crossref_metadata_2025_split huggingface dataset:
Russia: A Critical Evaluation of Its Natural Gas Resources
Authors: Economides M. J. , Geng P. , Laskar S. , Ndefo E. O. , Tawofaing L. 
Published: December 2007

Abstract
The dissolution of the Soviet Union in 1991 and its replacement by the Commonwealth of Independent States (CIS), prominent among which was the Russian Federation, was a welcome development around the world. However the development of Russian resources such as natural gas has been nothing short of disappointing. The future of the Russian natural gas industry is even more pessimistic. If the current trends do not change, there will be a severe natural gas shortfall in Russia by 2010. This prediction is contrary to widely held beliefs and astonishing considering that Russia has more reserves than any other country and one of the largest reserves-to-production ratios.
The reason of this coming gas shortfall is simple. In the past several years, Gazprom, the state owned natural gas monopoly in Russia has not invested enough and does not have the technology to develop new gas fields to replace existing aging ones. From a western point of view, the solution is simple. The Russian government should terminate Gazprom's monopoly position in Russian natural gas and involve more foreign and independent Russian oil companies in natural gas exploration, production and transportation. However, the government has no intention of terminating the current Gazprom monopolistic position at least in the near future. Typically, Gazprom announced recently that it will not share its huge Schtokman gas fields with any other companies.
The reasons leading Russian natural gas industry to its current state are complicated. A thorough understanding of Russia's natural gas industry and its history is required before we can even discuss the gas industry. This paper summarizes Russian natural gas reserves, production and transportation.
Special attention is paid to recent geopolitical events involving the Russian natural gas industry.
How the Russian government handles and legislates activities around natural gas production provides important clues to understand Russia's view on its natural gas resource exploitation and to predict Russia's action on future similar events. Based on these studies, the problems and possible solutions to the Russian natural gas industry are discussed.
The Use of MPD and an Unweighted Fluid System for Drilling ROP Improvement
Authors: Foster J. K. , Steiner A. 
Published: December 2007

Abstract
A drilling technique that is increasingly being used for performance drilling purposes is Managed Pressure Drilling (MPD). MPD is typically considered a tool to mitigate drilling hazards, and reduce the resulting non-productive time due to encountering lost circulation zones, tight pore pressure/fracture gradient margins, and high pressure, low volume nuisance gas zones. MPD can also be applied as a tool to increase rates of penetration (ROP) in applications where techniques such as air drilling and underbalanced drilling may be unsuitable due to limitations such as borehole stability, water flows, coal seams, or environmental concerns such as flaring gas.
The subject well for this case study was drilled in the Bullmoose area of North Eastern British Columbia, by Shell Canada. Experience from numerous operators working in this area identified the Nikanassin as a very hard, slow drilling formation, which negatively impacts the drilling time and cost curves. The Nikanassin is a hard and abrasive formation, and ranges from 1000 to 1800m in thickness. Also, in certain instances, elevated mud weights are required to deal with high-pressure nuisance gas and/or water flows. This further impedes drilling performance.
In the offset wells that were examined, various mud systems and bits were used, resulting in average ROP's ranging from 1.4 to 2.4m/hr. The implementation of an MPD program allowed for the use of an unweighted flocculated water fluid system, which increased the average ROP to 4.0 m/hr. When compared against low fluid loss mud systems, such as invert, the improvement in ROP was notable, and resulted in considerable time and cost savings.
As with any advanced drilling technique, successful application of MPD technology requires a detailed understanding of the potential benefits as well as limitations.
This paper summarizes the process that was used to identify, plan, and implement MPD as a technology to increase ROP. Lessons learned while planning and executing the MPD operation are discussed, as well as enhancements that are being considered for future applications of MPD in the Bullmoose area.
Method for Optimal Placement of Sensors in a Wired Pipe Drillstring
Authors: Fossgaard Eirik , Nygaard Gerhard H. , Vefring Erlend H. 
Published: December 2007

Abstract
This paper introduces a method for selecting the best sensor layout when using wired pipe for drilling operations. The introduction of wired pipe in drilling operations increases the data rate significantly compared to standard telemetry systems.
Various sensors systems are available, measuring parameters such as drillstring vibration, drillstring torque, downhole fluid temperature and downhole annulus pressure. Also available are measurements from various logging tools placed as a part of the bottomhole assembly.
The data from the sensors can contain important information that can be used for preventing various operational problems, such as high vibrations, insuﬃcient hole cleaning, kick incidents, and loss of circulation.
The method described in this paper can be used for designing a sensor layout for a wired pipe drillstring. The method analyzes data available from the sensors to yield the information required to detect operational problems.
The paper presents two different cases where the method is applied, one from a kick incident and the other from a loss of circulation incident. The results show that by optimizing the sensor layout for a wired pipe drillstring, cost eﬃcient performance can be ensured with regards to potential drilling problems.
Managed-Pressure Drilling with Dynamic Annular Pressure-Control System Proves Successful in Redevelopment Program on Auger TLP in Deepwater Gulf of Mexico
Authors: Chustz Mark J. , May James , Wallace Cameron , Reitsma Don , Fredricks Paul , Dickinson Scott , Smith Larry D. 
Published: December 2007

Abstract
Access to previously unattainable offshore drilling targets continues to expand through advancements in Managed Pressure Drilling (MPD) and Dynamic Annular Pressure Control (DAPC) technologies since their first application on the Mars TLP in 2005. Shell Exploration & Production Company successfully executed a second MPD operation, eliminating lost circulation and hole instability risks by utilizing a DAPC system on the Auger TLP.
Redevelopment drilling in maturing deepwater fields is challenged by high circulating density (ECD) and depletion induced fracture gradient (FG) reduction for intervals that still require original mud weights (MW) for borehole stability. The DAPC system provides automated control of surface applied annular backpressure to the wellbore to a specified bottom hole pressure (BHP) set point. This allowed drilling on the Auger TLP with a surface mud weight lower than required by conventional drilling, effectively reducing the ECD magnitude on the open hole.
The well design will be discussed, along with the equipment, methods, planning, preparation and training to successfully execute MPD offshore. Execution results and key learnings will be summarized.
Environmentally Sensitive Well Successfully Drills Underbalanced Using Recycling Technology
Authors: Schmigel Kevin , Code Scott 
Published: December 2007

Abstract
In 2005 a sour underbalanced horizontal gas well was designed and drilled in a pristine, environmentally sensitive region of southern Alberta, Canada. There were two primary drivers for the client. One was to remain under reservoir pressure throughout drilling and completion operations and the second driver was to safely recover 9.0% hydrogen sulfide (H2S) gas production and recycle the H2S contaminated drilling fluid. The well was not classified as critical sour because of its proximity to populated areas and a low well productivity of 0.015 E3m3/kPa (0.37 Mscf/psi); however, a cumulative flaring limit of 240 E3m3 (8.5 MMscf) was imposed by Alberta’s Energy and Utility Board (EUB).
Casing and hole sizes were optimized after confirming the well could be successfully drilled underbalanced to total depth (TD). Both well engineering and process engineering were integrated to provide the process and equipment to accommodate the sour well effluent while controlling the downhole multiphase flow and pressure environment. The injection gas for the underbalanced section was supplied via on-site compression from a sales quality gas supply line at a rate of up to 55 sm3/min (1,950 scf/m) at 10 000 kPa (1,450 psi). National Association of Corrosion Engineers (NACE) certified equipment was employed to create an enclosed gas and liquids separation system. The sour return gas was recompressed down an existing pipeline to a gathering station approximately 10 km (6.2 miles). To ensure the safety of the rig floor personnel, the drillstring was purged with an inert gas to the top float, and then bled off back to a low pressure separation system for drillstring connections. The well was successfully drilled underbalanced for 21 days, with 1.3% (8.5 E3M3)(0.3 MMscf) of the cummulative gas being flared. The use of recycled and recovered natural gas has economic benefits when compared to conventional disposable inert gas supplies, especially on a project basis.
Fishing 10,000 ft of CT from a Deep Gas Well in Saudi Arabia
Authors: Jubran Hasan H. Al 
Published: December 2007

Abstract
This paper will present two unique fishing operations using a Snubbing unit and Workover rig to recover a 10,500 ft of 1%" High Pressure Coiled Tubing (HPCT) that got stuck in a new deep gas well in Saudi Arabia while performing the post-frac proppant clean out operation.
A snubbing unit was used to fish the stuck HPCT. The objectives were (1) to fish the 10,500 ft of the 1%" HPCT, and (2) to clean out the well to the Plug Back Total Depth (PBTD). Therefore, a scope of work was prepared that included calculating the free point of the stuck HPCT, running with a chemical cutter using electric wire line and cutting the HPCT above the free point, and laying down the HPCT. Then, run with 2%" washover pipe and clean around the HPCT by swallowing it several times until the remaining HPCT is retrieved and finally, clean out the remaining proppant/PropNET from the wellbore. (PropNET is a fiber pumped at the end of prop-frac treatment for solids flowback control.) The snubbing operations recovered ±9,400 ft of HPCT out of 10,500 ft and the operation was terminated due to no progress after encountering the chemical cutters that were lost during the fishing operations.
The snubbing operation results were studied and used in planning for the rig workover operations. The preparation of the workover included discussing with fishing specialists the different fishing scenarios, identifying and ordering all tools and equipment that may be needed in the operations and putting together contingency plans. The objectives of the workover were to retrieve the remaining HPCT, fish the lost chemical cutters that were left in the hole subsequent to the fishing operations with the snubbing unit.
The paper will discuss the different techniques used in both operations and will highlight the lessons learned from both operations.
Supersize Hole Creates Drilling Opportunity
Authors: Mason Colin J. , Wenande Bill , Chen David C-K 
Published: December 2007

Abstract
Traditional well designs for high angle and extended-reach wells often mandate long 12¼″ hole sections through the overburden. Effective hole cleaning and wellbore instability management are key technical challenges commonly associated with delivery of this section. However, despite the use of rotary steerable systems, which help promote good hole cleaning and minimise open hole exposure times, problematical trips out of hole are commonplace. The symptoms of tight hole are often associated with significant cuttings bed accumulations, use of packed assemblies or creep arising from swelling formations.
In an attempt to improve overall drilling performance, a supersize hole strategy has been implemented to intentionally drill an enlarged hole through the overburden. At face value, this tactic seems to have as many disadvantages as advantages. However, practical experience of simultaneously drilling and underreaming 12¼″×13½″ hole sections over a number of wells has resulted in overall efficiency improvements.
The primary benefits associated with drilling an enlarged hole are ease of tripping-out drilling assemblies and more straightforward casing runs. Other advantages relate to lower downhole pressures or equivalent circulation density (ECD), decreased swab and surge pressures, and less string contact area. Disadvantages relate to increased hole cleaning requirements, additional tool failures as a result of higher vibration and a decreased rate of penetration (ROP).
The paper discuss es various aspects of drilling and underreaming and contrasts results between enlarged and conventional hole sizes. Results from drilling both 12¼″ and 12¼″×13½″ hole sections in the Azeri-Chirag-Guneshli (ACG) fields in the Caspian Sea are reported. ROP (Rate of Penetration) and a new metric TTSW (Time To Secure Wellbore) are used to provide meaningful comparisons.
Recovery Factors in High-Pressure Air Injection Projects Revisited
Authors: Gutiérrez D. , Taylor A. R. , Kumar V. K. , Ursenbach M. G. , Moore R. G. , Mehta S. A. 
Published: December 2007

Abstract
High-Pressure Air Injection (HPAI) is an IOR process in which compressed air is injected into a deep, light-oil reservoir, with the expectation that the oxygen in the injected air will react with a fraction of the reservoir oil at an elevated temperature to produce carbon dioxide. The resulting flue gas mixture provides the main mobilizing force to the oil downstream of the reaction region, sweeping it to production wells. The combustion zone itself may provide a critical part of the sweep mechanism.
In 1994 Fassihi et al. (SPE 28733) proposed a method for estimating recovery factors of light-oil air-injection projects based on the performance of two successful HPAI projects. Their suggested method relies on the extrapolation of the field gas-oil ratio up to an economic limit. In other words, it treats HPAI as an immiscible gasflood and neglects any potential oil that could be recovered by the combustion front. The truth is that, although early production during a HPAI process is mostly due to re-pressurization and gasflood effects, once a pore volume of air has been injected the combustion front becomes the main driving mechanism. Moreover, one of the unique features of air injection is the self-correcting nature of the combustion zone, which promotes good volumetric sweep of the reservoir.
This paper presents laboratory and field evidence of the presence of a thermal front during HPAI operations, and its beneficial impact on oil recovery. An analysis of the three HPAI projects in Buffalo Field, which are the oldest HPAI projects currently in operation, shows that only a small fraction of the reservoir has been burned and, if time allows and the projects are managed appropriately, burning of more reservoir volumes could result in much higher oil recoveries than predicted by the gasflood approach.
Measurement of Gas Condensate, Near-Critical and Volatile Oil Densities, and Viscosities at Reservoir Conditions
Authors: Al-Meshari Ali , Kokal Sunil , Al-Muhainy Ahmed , Ali Sajjad 
Published: December 2007

Abstract
Gas condensate liquid dropout can occur in gas reservoirs, especially near the wellbore when the pressure falls below the dew point. In near-critical and highly volatile oils, extreme phase behavior effects can occur, especially near the critical temperature. Liquid dropout phenomena in these fluids affect well productivities. To simulate the liquid dropout phenomenon, as well as the flow of fluids in these reservoirs, viscosity values of reservoir fluids at high pressures and temperatures are required. Viscosities of gas condensate and near-critical fluids at elevated pressures and temperatures are not measured routinely due to inherent problems associated with their capture, measurement difficulties, and considerable time and effort required. Therefore, it is frequently not possible to obtain measured values, and viscosity values must be estimated from correlations. Empirical correlations have been published for determining viscosity as a function of pressure, temperature, gas-liquid ratio, and gas composition. Their accuracy for gas condensates and near-critical fluids has not been evaluated due to lack of data.
This paper presents some new and unique viscosity data for gas condensate and near-critical systems at elevated pressures and temperatures. A new, state-of-the-art pressure-volume-temperature, PVT, apparatus was designed and commissioned to measure the densities and viscosities of Saudi Arabian gas condensate, near-critical and highly volatile oils at reservoir conditions. The data include viscosity and density values above and below the saturation pressure. The data were used to evaluate existing correlations that are typically used for predicting viscosity in PVT software.
Prevention of Occupational Back Pain: Saudi Aramco Experience
Authors: Alotaibi S. T. 
Published: December 2007

Abstract
This paper reviews the scientific research on occupational back pain focusing on prevention and the Saudi Aramco experience. The challenges of translating the medical evidence into policy for this multi-factorial condition are discussed. Medical science is currently unable to clearly distinguish between back pain caused by work and that possibly due to other causes but affecting the individual’s capacity to work. Back pain affects the majority of people at sometime in their lives and it is costly to medical services and industry. Once the risk factors for occupational back pain are identified, it can be prevented in the majority of cases or else it can become chronic and disabling. Failure to follow preventive programs may lead to a high incidence of occupational back pain.
One-Trip Completion in Petrobras Campos Basin
Authors: Ferreira Heleno M. , Dantas Juliano C. , Lembi Fábio , Lopes Ronaldo L.O. 
Published: December 2007

Abstract
During part of the Campos Basin (CB) development, tubing installations in just one trip (deployment of the production string together with the tubing hanger without using DPs) were not considered very important. This fact was justified, mainly for the following reasons: –Until the beginning of the last decade, the water depths in which the CB wells were completed ranged from 100 to 400m.–The time spent with "spacing out" operations was not significant.–The rigs’ daily rates were considerably lower than they are today.–Many of the completion projects were not suitable to this technique.
Therefore, we can conclude that the scenario was not attractive for one-trip completion.
As we proceeded to deeper water depths, we realized the need to look for solutions to minimize the installation time, since in this case, the impact of the time spent with "spacing out" the tubing string, became significant.
Today, more than 90% of the developing wells in CB are located in water depths from 1000 to 1900m. Futhermore, we are facing a significant increase in the rigs’ daily rates impelled by soaring oil prices which we expect to remain high for the time being. Consequently, the rig time saving accomplished by using this technology becomes extremely attractive.
The objective of this paper is to describe the evolution of this technique, review different methods and key production string components, as well as the lessons learned from the first phase of this technology application.
Well, It's Good to be an Engineer!
Authors: Sawaryn S. J. , Farley K. , Gay S. , Banks M. 
Published: December 2007

Abstract
Over the last couple of years, both the global and UK oil and gas industries have grown to meet demand. Prices have increased, and less accessible oil and gas accumulations have become economic. Engineering skills critically underpin this work.
There is a general shortage of trained engineers and skills match in the UKCS, a problem that is compounded by demographic change and intense competition for existing resources from within our industry and from other sectors that recognise the value of the analytical skills offered by engineers. The shortage is being addressed at governmental level, providing guidance through strategic reviews such as the Roberts report, and at the corporate level with activities that span secondary and higher education as well as training and development during employment.
Figures (2005) for the UKCS suggest there is a further 21.1 billion boe total reserves. Global reserves stand at over 50 years production at current rates, offering opportunities in the UK's growing services sector. The diverse educational, recruitment and development activities of drilling engineers in a major oil operator are discussed against this background. The case is made that existing employees can do much to help attract newcomers to our industry and that the oil and gas industry in the UK still offers a challenging and rewarding career. Possible gaps and opportunities are identified, such as the increasingly global nature of the candidate pool, changing expectations and use of technology to help train the next generation of drilling engineers and manage the demographic challenge. Work in multi-disciplinary teams and the need for increased knowledge outside traditional drilling engineering skills has also increased the attractiveness of the job and opened it up to a wider pool of science, engineering and technology disciplines.
Surveillance—Maintaining the Field from Cradle to Grave
Authors: Grose Trevor 
Published: December 2007

Abstract
The reservoir is our primary asset – "surveillance is the maintenance strategy to enable delivery"
– You would not dream of poor maintenance delivery on plant and well integrity – How do we minimize poor maintenance of reservoir delivery?
Surveillance is our primary tool for managing reservoir and well delivery; however, it is not always properly thought through and executed. On occasions we fail to act on the data we have, or capture lessons learned. Acting on this information is often where we stumble. Our ability to follow a plan, do, measure, learn loop is key to good execution and delivery of a surveillance programme that delivers the short term production and long term reserves recovery.