bluuebunny/crossref_metadata_2025 huggingface dataset:
History-Matched Reservoir Model Validation Based on Wavelets Methods
Authors: Kind Martin V. , Quinteros Javier
Published: December 2007

Many predictive methods based on numerical simulation generate undesired changes on the distribution of their parameters that depend mainly on the numerical method or the grid orientation (artifacts). On the other hand, it is common to find an appropriate match of the production history through the use of reservoir properties as calibration parameters, even when this procedure generates in many cases geological inconsistencies. Also, as real time data acquisition is becoming a powerful and popular technique, it is important to achieve a methodology that allows the input of new sources of information without disturbing the history matching previously validated.

In this paper a new methodology to integrate a history-matched reservoir model with other geological data is presented. It is based on the methodology proposed by Sahni and Horne1, that based on the Haar wavelet transform allows for the improvement of the history-matched geological model through the inclusion of additional geological constraints without needing to perform the history matching every time the reservoir model is updated.

The first step of the method presented in this study is to match the production history of the reservoir that will be modeled by means of numerical simulation. Then, the wavelet function that better fits the distribution of the considered properties, keeping the highest Energy Compaction Ratio (ECR), is chosen. After performing the wavelet transform, the most sensitive coefficients to the production data are determined. Those that are not significant for the model validation can be modified and geostatistical interpolation algorithms can be applied (e.g. Sequential Gaussian Simulation). Finally, when the inverse transform is performed, the data set is not only validated by the production history but also by the geological properties.

If the wavelet transform is not Haar, an additional benefit is obtained. It is possible to interpolate the geological information in the different regions where the data acquisition is difficult or doubtful.

This new heuristic methodology has been tested in different reservoir configurations. In this paper, we validate the results achieved for a test case reservoir with patterns of 4 producers and 2 injectors. This procedure is very helpful in numerical simulation of reservoirs and it has a direct impact on its management, risk analysis and the development of depletion plans.
Novel Frac-and-Pack Technique for Selective Fracture Propagation
Authors: Hidalgo O. , González O. , González V. , Sánchez A. , Peña A.
Published: December 2007

Frac-pack is a pervasively used completion technique in wells targeting high permeability, poorly consolidated and depleted sandstone formations located in Bachaquero, Tía Juana and Lagunillas fields in West Venezuela. This technique combines stimulation and sand production control in a single treatment by placing a short and wide fracture which bypasses the near-wellbore damage, while gravel-packing the zone of interest.

This paper describes a novel and economical frac-and-pack technique which consists of pumping a sand plug with the downhole tool set for circulation to isolate a bottom set of perforations, followed by conventional frac-and-pack. When this procedure is followed, the fracture is forced to propagate along the upper intervals. This novel technique is particularly useful for wells with water-producing zones near the bottom of the target zone, because it induces selective growth of the fracture along the upper intervals and mitigates the risk of growing the fracture into the water-producing zone.

A case study of a frac-and-pack performed in a Lagunillas field well with a water contact 40 ft below the target zone is reviewed. The intervention rendered an increase in well production rate from 27 to 173 net barrels per day with a reduction in water cut from 25% to 9%. In contrast, two wells in the same field and with very similar characteristics which were frac-and-packed conventionally rendered 100% and 63% water cuts, respectively.

Another application of this technique refers to frac-and-pack of wells with long perforated intervals where early wellbore screen-out may occur due to proppant bridging of the annular volume between the screen and the casing. Conventional frac-and-pack of twenty wells in these fields with perforated intervals exceeding 90 ft rendered a 40% early wellbore screen-out rate. The early wellbore screen-out rate was reduced to 12% in a sample of twenty eight wells with the new technique. The average production rate increased from 2 to 135 BOPD, whereas the average estimated after-treatment production was 130 BOPD, for which this technique was considered successful. A shortcoming of the technique for this application is the fact that the bottom of the perforated interval is not fractured. High-end frac pack techniques that overcome this issue such as use of shunt tubes were found to render higher normalized oil production rates.
Casing Drilling Connection Qualification for Shell Rocky Mountain Project
Authors: Lu Qing , Hannahs Dan , Buster Jerry , Coe David , Langford Steve
Published: December 2007

Shell has operations in Pinedale Anticline, Wyoming. Most wells in this region are approximately 14,000 ft deep and take an average of 30 - 40 days to drill. Drilling within their 4 1/2" production tubing strings will allow deeper penetration into the production zone resulting in increased production. To reduce well cost, Shell requested Grant Prideco to qualify the 4 1/2", 13.50ppf, P110 DWC/C-SR to utilize for its production string. This paper details the specific test plan.

DWC/C-SR is a thread seal connection which has been integrated with a resilient seal. Both fatigue and seal ability performances were to be verified because the connection will be used for drilling applications. Fatigue testing followed API RP7 guidelines. Seal ability testing was based on ISO 13679 qualification requirements.

Finite element analysis (FEA) was performed on different ISO configurations to determine the worst-case fatigue configuration based on linearized Stress Amplification Factor (SAF) analysis. In addition, FEA was used to determine the worst-case galling configuration. Three specimens were tested at targeted stress levels to determine the connector fatigue life. Next, four specimens were fatigued to a pre-determined number of cycles at a target stress level. This was followed with ISO series B tests. In order to evaluate high temperature performance, one of the ISO Series B test was conducted at 300°F. Additionally, make/break specimens were tested to verify galling resistance.

Casing drilling technology is quickly expanding into more stringent applications. However, connection performance under these severe fatigue and combined load applications is uncertain. Previously, casing drilling connection design focused on providing high torsion capacity and fatigue resistance; however, sealability characteristics should be seriously evaluated. The test program detailed in this paper evaluates connection performance for both fatigue and sealability. This information will assist in facilitating a broader application of casing drilling connections.
Reducing Drilling Risks in Highly Overpressurized Formation: A Case History in Nororiente Basin, Argentina
Authors: Frydman M. , Restrepo J. D. , Palacio J. , Airoldi C. , Eguia H.
Published: December 2007

Different oil operators have faced technical and economical challenges while drilling wells in the Nororiente basin. Drilling in a tectonic active setting creates problems ranging from influxes and stuck pipe incidents to circulation losses and reservoir damage. Operations in Ramon Lista experienced similar problems, especially wellbore instability, lost circulation and influxes. The presence of a salt member increases the drilling risks, with very high pore pressure (up to 19.3ppg) just below this member. Drilling nearby wells has evidenced many catastrophic events, like 120 days to control an influx with simultaneous losses. This article will describe the application of the process used to reduce risks and cost while drilling in the Nororiente basin.
Value-of-Information Applications In Unconventional Resource Plays
Authors: Leach Patrick E. , Brown P. Jeffrey , Haskett William J.
Published: December 2007

Unconventional resource plays (e.g., tight gas plays, coal-bed methane, etc.) play an increasing role in the global energy budget. Those in the United States have attracted a lot of attention and study in recent years, but for many of the international unconventional plays, information regarding likely production rates, ultimate recoveries, development costs, and the overall profitability of these plays is often exceedingly scarce. As such, companies interested in pursuing these plays must make decisions regarding what information to acquire. Seismic surveys, regional studies, exploration/appraisal wells, pilot programs, etc. – all are possible sources of data regarding the ultimate behavior of the reservoir. Unfortunately, all are possible wastes of money and manpower, too.

Maximizing the probability of financial success in these plays requires a thorough, consistent value-of-information (VOI) process. This paper presents an approach that emphasizes estimating the reliability of these information sources in a consistent way, including performing sensitivity analyses to see how the VOI changes by varying input parameters (including reliability).

Results can give the decision-maker confidence in the decision to acquire information (or not to do so), and yield insights into the overall profitability of the venture. They also highlight those uncertainties that merit further attention, versus those that can be ignored (or must simply be accepted) for the time being.

In the absence of VOI analyses, the value of highly uncertain opportunities can be grossly mis-estimated. Such analyses should play a key role in estimating the profitability of unconventional resource plays.
Effective HSE Management and Auditing System Guarantees Results
Authors: Mahfouz Mamdouh , Rashwan Abdel Razek
Published: December 2007

The oil and gas industry prides itself on having some of the best safety records compared to many industry sectors. Health, safety and environment (HSE) became a familiar term and number one consideration in oil and gas industry. Nevertheless, traditional HSE manuals, bulletins & instructions are not enough to guarantee that the system is effective and serving the organization. Well structured safety policies, training and employee handbooks are the norm but for a safety policy to have any relevant meaning HSE values cannot remain as words on paper, they must be taken up and used by employees and translated into performance.

It became mandatory to the industry to find a way to make sure that HSE instructions reach every employee and accurately implemented. This could only be achieved if proper auditing is employed. Proper auditing for a professional HSE system can definitely close the loop and fill the gap between what is written in manuals and what is eventually implemented. In the mean time, while establishing your HSE system make your reference one of the recognized international standards known to most of companies. This will make the language of your system familiar to others and help auditors when reviewing the system.

Before you start, a team of experts must be formed to sponsor this task. Team members must be solicited from different company disciplines to cover all potentially hazardous areas. The team will thoroughly consider the following areas when designing the project; equipment reliability, maintenance standards, operations procedures, emergency preparedness, proper documentation and people.
Candidate Selection for Underbalanced Drilling: An Approach
Authors: Rehman Shaikh Abdul Mujeer Abdul
Published: December 2007

Underbalanced drilling is often done to reduce formation damage, avoid lost circulation problems, stuck pipes, etc. Thus, there has been a growing acceptance for underbalanced drilling. By far, it has also been proved that the advantages of underbalanced drilling are most evident in depleted reservoirs. Though there are some challenging issues with UBD such as bore hole instability problems due to the lack of positive support from the bore mud, these issues can be dealt with the evaluation of in-situ stresses and a realistic estimation of formation rock mechanical properties. Thus the above two factors and proposed borehole trajectory and mud weight design play an important role in avoiding borehole instability problems and achieving the field objectives.

Candidate selection is the key to the success of underbalanced drilling (UBD) projects. The question to be answered is why sometimes UBD significantly improves productivity compared with conventional overbalanced drilling (OBD) practices but sometimes it doesn't. To answer this question, an extensive reservoir engineering study to understand the mechanisms of productivity improvement from UBD must be performed. A single-well model can be built that simulates the UBD process and the OBD process (while taking into account drilling filtration invasion, mud cake, and permanent formation damage) and their impact on production under a variety of reservoir conditions. Production rates should predicted for both UBD and OBD cases. Then, a model should be used to analyze the economic benefits of UBD operations (if any) for the given reservoir.

Reservoir properties play a role in the success of UBD operations. The study would clearly demonstrate that UBD works for some reservoirs but not for all reservoirs.

The study results would provide a set of reservoir criteria that can be used as guidelines to choose potential UBD reservoir candidates.
Successful Application of Novel Cementing Technology in Hassi-Messaoud, Algeria
Authors: Bouras H. , Toukam E. , Martin F. V. , Bedel J. -P.
Published: December 2007

The ultimate objective for cementing a casing string is to achieve long-term integrity of the well. This can be achieved through long-term zonal isolation between the penetrated formations with appropriate mechanical properties, low permeability, and shear bond strength properties provided by the cement sheath placed in the corresponding annuli. Experiences in the Hassi-Messaoud field have shown that zonal isolation is a very complex problem for some formations such as the LD2 zone, which exhibits, in some cases, corrosive fluids and highly saline formations as well as lost circulation zones. Cementing operations are critical and the need for cementing systems capable of solving these problems is crucial.

This paper focuses on the factors that have contributed to the potential failure of the existing cement system. Stress modeling has been used to select the appropriate cement system to overcome the challenges faced by the cement sheath in this type of environment. Stress analysis calculations, combined with mechanical properties testing of the cement system, has suggested the use of a novel cementing technology. This new system has been able to solve these problems to provide flexibility, improve corrosion control, expansion properties of the set cement, reduce the chances of microannulus creation, and therefore avoid overpressurization of the annulus casing. To ensure correct cement placement in the lost circulation zones, this slurry system has been successfully combined with fibers specifically engineered for cement slurries.

This technology has been a cost-effective solution for cementing 12 1/4-in sections in the Hassi-Messaoud field and 8 1/2-in sections in the Berkaoui and Hassi-Guettar fields. Field results have proven that significant workover costs, up to USD 1 million on wells in production, can be saved with the application of this technology.
One-Trip Installation of 4¾-in. Expandable Screen Assembly
Authors: Mohamed Omar Y. , Waters Ray , Attia Ahmed , Pierfelici Stefano , Abdelaaty Petrobel Gharib , Ripa Giuseppe
Published: December 2007

Expandable metal technology applications can provide cost-effective solutions to drilling and production challenges.

One such application is expandable sand-control screens that eliminate annular flow and help prevent sand migration and "hot spotting." A recent project with our partner Petrobel (operating company joined between ENI and EGPC) employed a Baker Oil Tools expandable screen assembly to recover reserves in the offshore Mediterranean Sea North of Port Said City.

The aim of the project was to install, in one trip, the 4-¾-in. Expandable Screen Assembly in Well PFM-8 in order to isolate shale layers above and below the 4 MT thick gas bearing sand in a 6 inch open hole. The Expandable Screen Assembly design combines sand control with expansion technology, providing formation particle exclusion, annular flow reduction, hole stability, and large inside diameters (IDs).

Upon conclusion, the project yielded very positive tangible results: Production was 1.8 MM m3/d and likely to increase after further cleanup. The first run of 4-3/4-in. Expandable Screen in Egypt offshore the Mediterranean Sea has been successfully in well PFM-8 for Petrobel. The success was not only in flawless installation, but also in sustaining long terms sand-free gas production at 1.8 MM m3/d and more than 2000 bbls of associated condensate from 4 MT thick reservoir in 6" open hole.

This paper will explore the successful completion technique used in Egypt, using Expandable sand-control technology.
Integrating People, Plant, and Process in the Design and Operation of Process Industry Assets.
Authors: Hamilton W. I. , Cullen L. , Reeves G.
Published: December 2007

The fatal explosion at the Texas City Refinery in March 2005, highlights the importance of comprehensively addressing human factors during project design to avoid catastrophic consequences. While many factors contributed to varying degrees to cause the explosion, BP’s response to the explosion included developing a comprehensive procedure and supporting guidance on the integration of human factors with project engineering processes.

Other sources of such guidance do exist but they are generic in that they do not map onto an engineering or systems development process. Or they are specific only to certain stages of development. This work is original in its attempt to create a comprehensive solution to oil and gas projects’ development cycle, and in trying to map this onto an operating Company’s management systems.

This paper reports on the work undertaken to develop a human factors integration procedure for BP’s projects and operational management. It describes the requirements gathering and drafting phases of the work, and shows how the description of human factors practices has been tailored to the organisation’s established engineering and technical safety management systems. The human factors process model has been validated with stakeholders throughout the organisation and in support of a major project. The results of these validation activities are reported here.
Tracing Groundwater Pollution in the Oil Industry: Myths and Reality
Authors: Ostera H. A. , Torres C. , Fasola M.
Published: December 2007

During the last years, a complete set of brines, groundwaters and surficial waters surveys was carried out in oilfields in order to determine the presumed oil born contribution to the groundwater pollution. The survey included the most important basins in Argentina and a wide variety of geological and hydrogeological conditions. Although conventional hydrogeochemistry played an initial role, the isotope tool has been the key for unravelling some delicate and doubtful cases. Most brines are very well characterized by their isotope composition and high salinity, leading to an easy recognition in the case of mixing. Besides the stable isotope composition of oxygen and hydrogen, tritium and Sr isotopes helped to model the interaction of production waters, groundwaters and surficial waters. As a matter of fact, and except for some old passives, the results showed that the improvement and change in water managing practices during the last decade avoided major problems. Despite this situation, the lack of knowledge on the new practices of oil industry and a high degree of incredulity from the people, limits the appreciation of this improvement to the courts and specialists. A thoroughful campaign to clarify the results, utility, confidence and limits of a multitracer approach is necessary to face the public concern in order to demonstrate that the oil activity can be environmentally friendly and that the water resources are a common heritage that will be preserved.
Optimized Drilling Cost Per Foot in KPC Versus the Increase of Drilling Tangible and Intangible Cost (Case Study)
Authors: El Bakly O. , Ali K. , El Dawey M.
Published: December 2007

KPC challenges was and still to maintain the lower cost per foot in western desert of "Egypt" using a competitive solutions and designs to overcome increase of drilling materials & services costs in structures with low productive reservoirs.

This wasdone through customizing the following parameters:

Using slick BHA rather than stiff BHA which improved rate of penetration for western desert's formations (Doubling ROP) associated with good Hole trajectory. Improving casing design to minimize number of casing strings, exposing long (Stable) open hole sections while drilling. Reviewing & enhancing drilling mud systems to maintain good hole stability through long deep open hole sections (+/- 11000 FT exposed section). Optimizing bits usage to be compatible with drilled formations. Reviewing cement designs to cover low fractured formations, using low cost high quality cement to overcome gas migration by optimizing transition time. Optimizing rigs fleet and maximizing rigs utilization to perform drilling & workover wells effectively & safely. The use of slim hole design.

In this domain, KPC presents its experience in reducing the cost per foot. KPC's obtained cost/ft was proven to be the lowest cost all over Egyptian westetrn desert compared to sister companies in same area, wherever, the wells below 8200 ft have an average of 50 US$ versus 60 US$, wells between 8200 ft and 13100 ft achieved 140 US$/ft versus 175 US$, wells more than 13100 ft achieved 185 us$/ft versus 265 us$/ft.

It is concluded that, it is not necessary to depend only on the new technology for achieving lower drilling cost per foot, but it is as well as important to adapt the drilling techniques to desired requirements.
The Evolution of Communities of Practice in a Petroleum Services Organization
Authors: Smith David L.
Published: December 2007

Most knowledge management implementations include communities of practice or networks which allow people to connect to other people, share ideas and discuss issues. Communities have been shown to be informative, solve business problems, and create innovative solutions. They are usually focused around disciplines, projects, products, services, or general issues. Unfortunately, companies find the majority of their communities have little to no activity, do not show sustainable results or demonstrate any measure of business impact.

Only a very few knowledge management (KM) implementations produce true business value, and the oil industry is no exception. In fact, the April 2004 issue of CIO magazine1 noted that "85% of all KM initiatives fail". We can only assume that the communities of practice in these implementations are not creating value.

This paper will detail the evolutionary changes in communities of practice within a petroleum services company. We will look at changes in community audience, facilitation, and leadership along with the actions taken to ensure that the KM communities create value.
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

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

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

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

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

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

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

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

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

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

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

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

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

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.