bluuebunny/crossref_metadata_2025 huggingface dataset:
Special Considerations for Drilling the Granite Heat Source of an EGS Well
Authors: Holland Brian E
Published: February 2011

A procedure was developed to allow manged temperature drilling of the granite heat source of an enhanced geothermal well. It was shown that the procedure created economies due to the removal of the MPD equipment, the requirement to stage-in and the need to circulate chilled water. It was determined that the procedure could be deployed in any well provided that it was considered at the outset. It is indicated that time spent on drilling the heat source can be reduced. The procedure involved the installation an additional casing called a parasite string. The installation of the parasite string allowed for the installation of temperature sensing equipment that is able to provide an accurate down hole temperature gradient. The installation of the parasite string also allowed for the automation of the temperature control. The installation of the parasite string made operations safer because super heated water was never allowed to the surface. It was shown that the installation of an additional string of casing did not interfere with the final hole diameter and that it was possible to drill into the hot dry rock with an 8 ½" bit and 7" production tubing for the hot water. It was shown that the heat source could be drilled with plain water resulting in significant savings in preparation and maintenance of a drilling fluid. The use of the parasite string resulted in a reduction in the area required for cooling ponds and in an area where cooling ponds may not be acceptable a refrigerated water chiller would be all that was required. It was determined that after the well was drilled and completed an insulating gel material could be installed in the two annuli created by the parasite string. The insulation would enhance the life of well by conserving the heat in the production tubing.
Pressure Buildup Analysis in Karstified Carbonate Reservoir
Authors: Djatmiko W. , Hansamuit V.
Published: February 2011

This paper describes techniques to identify vugs in a real pressure buildup data. The reservoir under study is an undersaturated carbonate reservoir dominated by vugs and karst. We analyse the 80 hours of pressure buildup following a 100 hour of pressure drawdown. We observe the pressure derivative behavior cannot be described using current naturally fracture reservoir models such as dual porosity and triple porosity models. This is because some pressure derivatives are obscured by reservoir boundaries and the matrix-to-fracture fluid transfer does not behave as it were in a multiple porosity reservoir. In this heterogeneous reservoir, we believe this corresponds to the number of matrix interporosity flow parameter, and thus degree of reservoir heterogeneity. If we force the data using dual porosity or triple porosity models, the error will be high (>15%), because the pressure derivative cannot follow all the transition periods.

We use combined analytical and numerical methods to tackle this problem. First the dual porosity analytical solution is invoked to estimate the reservoir parameter (ω, λ and k). Next, a numerical triple porosity model is set up to represent the reservoir. The reservoir parameters initially follow analytical results as initial guesses. History matching procedures are performed to compare DST data with the calculated bottom-hole pressure. When these agree, reservoir flow capacity and storage capacity can be determined for fracture, matrix and vug respectively. We found volumes of vug cannot be ignored in a triple porosity system.

This technique can be used to quantify vugs or karst from well testing when analytical dual porosity or triple porosity model are unable to handle all matrix-to-fracture interporosity flow due to reservoir heterogeneity. Using this technique, we believe not all well test data in carbonate reservoirs (especially for high k.h) can be analyzed using current analytical models. Ignoring this, the estimated permeability is significantly different from the actual.
New Corrosion Inhibitor Reduces Overboard Oil in Water and Maintains Asset Integrity
Authors: Dunsmore B. , Charlesworth M. , Dunn R. , Licari C. , Ashiedu R.
Published: February 2011

A new corrosion inhibitor that can reduce oil in water (OIW) was selected for use in a field offshore on Australia’s North West Shelf. The selected product has allowed the achievement of the new stewardship OIW target of 17.5 ppm, enabling improvements in overall environmental impact. Laboratory tests showed that the selected product had similar corrosion inhibitor performance to the incumbent field product. Meanwhile, laboratory OIW measurements showed that 50 ppm of the selected product generated significantly less OIW (17 ppm OIW compared to 159 ppm OIW with 50 ppm of incumbent product). On-site tests were then performed with fresh produced fluids, demonstrating again that the selected product resulted in lower OIW (a 42%, 43% and 73% OIW reduction compared to incumbent product, at 20, 30 & 40 ppm of corrosion inhibitor, respectively). A full-field trial immediately demonstrated a decrease in OIW results corresponding to a decrease in overboard OIW from a daily average of 20.0 ppm to 8.8 ppm during the trial period, with no adverse impact on corrosion probe readings. The new product has now been in use on this facility for 10 months. Corrosion monitoring continues to show good inhibition while the OIW levels remain below 16 ppm average, and concurrently is allowing a reduction in the use of associated water treatment chemicals, further benefiting the environment.
Determining Production Casing and Tubing Size by Satisfying Completion: Stimulation and Production Requirements for Tight Gas Sand Reservoirs
Authors: Wei Y. , Cheng K. , Jin X. , Wu B. , Holditch S. A.
Published: February 2011

Producing natural gas from Tight Gas Sand (TGS) reservoirs will be of increasing importance to the global energy industry in the coming decades. One of the basic decisions concerning the development of TGS reservoirs is to determine the size of the production casing and tubing. Because of low permeability, virtually all of the wells completed in TGS reservoirs must be stimulated to achieve the desired production goals. Therefore, the casing and tubing size must be designed to satisfy the stimulation requirements. Because many TGS wells are completed in reservoirs that have many distinct layers that can contribute to production if adequately treated, it is important to select the optimal diversion techniques in completing these multilayered reservoirs. The casing and tubing size must be designed to allow the selected diversion technique to be used successfully. In addition, during the production period, it is important to continuously remove the liquids from the wellbore. Therefore, the casing and tubing size must also be designed to satisfy the production requirement. In summary, the casing and tubing size must be designed to satisfy the completion, stimulation and production requirements. In this paper, we will provide a methodology we have developed to select the appropriate casing and tubing size for the development of TGS reservoirs.

This work has been part of our effort to build software that we call TGS Advisor. TGS Advisor can be used to provide advice/best practices to engineers developing TGS reservoirs. The user enters the known reservoir data and the program provides advice on how to drill, complete and stimulate the reservoir. We have combined knowledge from the petroleum literature and interviews with experts with detailed calculations to build the TGS Advisor. We evaluated the results of the TGS Advisor with published case histories in the petroleum literature. Currently, the methodology of choosing casing and tubing size for TGS reservoirs has been programmed and incorporated into the TGS Advisor system. Finally, an example of using TGS Advisor to select the appropriate casing and tubing size in TGS reservoir is presented.
A Unique Framework for Developing and Mentoring the Next Generation of Reservoir Navigation Engineers
Authors: Bacon R. , Hearn F. , Skillings J.
Published: February 2011

In this day and age of rapidly evolving technologies coupled with a dynamic workforce environment, in terms of age, experience, and geographic diversity, it is becoming increasingly challenging to ensure quality personnel are available to meet the ever-increasing technical demands of the oilfield. With the growing trend toward precision wellbore placement in horizontal, highly-deviated and multilateral wellbores, advanced geosteering services are critical to a project’s success. Reservoir navigation has become a fundamental part of the modern field development program where simple geometric well targets do not capture the capabilities and value of today’s technologies.

Reservoir navigation refers to those activities designed to place the wellbore in a predetermined location and maintain it within a desired location within the reservoir. Proper geosteering optimizes wellbore placement in the productive reservoir, maximising both drilling efficiency and hydrocarbon production. It involves real-time interpretation and decisions while drilling to properly and accurately place the wellbore in the most productive zone in the reservoir. The process can be complex and requires a high level of expertise.

Historically, the industry has relied on field engineers with years of field experience and a geosciences background as a talent pool for reservoir navigation engineers. It can then take several months of classroom, on-the-job training, guidance, and mentoring before a reservoir navigation engineer can break out on his/her own.

A growing demand for these complex, precision wellbore placement applications are out-pacing our ability to fully develop the required competencies of reservoir navigation engineers using traditional training methods. The challenge is to decrease competency development time without compromising the technical proficiency of the individual (Hearn, et al., 2008). That is, how do you develop engineers to work with, and eventually step into the shoes of, existing experts? How is knowledge transferred, and how do we ensure the next generation of engineers can supply the same level of service with the same fundamental knowledge in this fast-paced world of answers while drilling?

While experience is always the best teacher, proper mentoring and a clearly defined framework of skills and processes for acquiring those skills is required. This paper maps out such a framework and explores the results of two years of development of several new reservoir navigation engineers.
Using High-Resolution LWD Resistivity Images for Carbonate Facies Identification and Steering
Authors: Bacon Robert , Morris Stephen , Fernandes Warren , Mahiout Said
Published: February 2011

Experience to date shows that the drilling environment offers a good platform for high-definition electrical borehole imaging. At the time of drilling, invasion and borehole wall rugosity are often minimal and electrical images generated by sensors that rotate with the drillstring provide full coverage of the borehole. It also provides an opportunity for realtime geological analysis while drilling and the decision-making that is unavailable with wireline. Detailed analyses of images reveal discrete sedimentological and textural features aiding facies recognition in carbonate reservoirs. These facies can be up-scaled to facies associations and eventually used for depositional environment interpretation. This leads to wider prospect delineation and confirmation of the local geological model. The study also demonstrates the strength of early geological information in high resolution for reducing geological uncertainty at an early development drilling program.

We show case studies from several carbonate reservoirs in which high-resolution electrical images have been acquired in conjunction with reservoir navigation. From post-well analysis, we can define the key criteria that help in recognition of reservoir position: correlatable sedimentary surfaces and image facies/patterns. We test the distribution of facies and sedimentological features that can be recognised in horizontal boreholes by comparison to vertical offset wells, in addition to automated facies recognition from image log responses. The development of a sedimentary or carbonate facies steering technique using high-resolution images with a predictive and real-time interface will reduce uncertainties related to and better aid geosteering within the desired "sweet-spot" of a variety of clastic and carbonate reservoirs.
The Development of a Complete System to Allow Continuous Downhole Chemical Injection Without Affecting the Subsurface and Surface Safety Systems
Authors: Klompsma D. , Lugtmeier B. , Lacy R. , Hearn W. , Dennistoun S. , Calzoncinth E. , Jacob J. L.
Published: February 2011

As gas wells mature, the problem of liquid loading and the resultant intermittent flow can reduce production to rates below the anticipated decline curve. It has been demonstrated that the introduction of surfactants such as foamers can mitigate the problems caused by liquid loading, and experience has shown that the introduction of these production enhancing chemicals in a continuous stream at the perforations can significantly reduce critical velocity and extend the productive life of gas wells. At the same time, especially in offshore wells, Operators must maintain a fully functional safety system including the downhole safety valve and the surface master valves and actuators which are controlled by an operating panel and are an integral part of the emergency shutdown system. This is especially true for operators in the North Sea who must adhere to some of the most rigid safety requirements in the industry. Clearly a new system was needed to allow the continuous injection of production enhancing chemicals through the safety systems in the well while maintaining their full integrity.

This paper will detail the conception and development of a new downhole safety valve and wellhead penetration system, incorporating a capillary string, to allow an operator to inject production enhancing chemicals through the safety valve while maintaining full control of the surface and subsurface safety equipment. The new system, the deployment of which is also detailed in this paper, is installed by means of slick line and capillary string using a combination of proven intervention methods thus eliminating the need for a major rig operation and saving the operator substantial workover cost.
Successful KCl-Free, Highly Inhibitive and Cost-Effective Water-Based Application, Offshore East Kalimantan, Indonesia
Authors: Huadi F. , Aldea C. , Mackereth B. , Mukhlis T.
Published: February 2011

Historically Total E&P Indonesie, operating offshore East Kalimantan (Indonesia), has used a 12 to 14% KCl/polymer water-based drilling fluid to drill the intermediate hole section. Excessive hole washouts requiring significant cement volumes to properly cement the casing have been noted. Another drawback to the standard KCl/polymer system is that general hole conditions related to torque/drag and excessive time tripping in and out have affected overall efficiency. Additionally, with the necessity to maintain mud density not greater than 1.15 SG (9.6 lb/gal) for this intermediate section, significantly large dilution rates have been required while drilling with the KCl/polymer system. There was a need to improve the drilling fluid which led to the successful introduction of a novel polyamine clay hydration suppressant as a KCl alternative in this area.

Novel polyamine at 2 vol% has been used as alternative to 12 to 14 wt% of KCl. The polyamine significantly improved the clay/shale inhibition with a noticeable improvement in cuttings integrity observed across the shale shakers. Seawater with 5 to 8 wt% of sodium chloride (NaCl) was used as the base fluid for the system. The system was easy to engineer and easy to maintain at rigsite. A combination of xanthan gum and polyanionic cellulose (PAC) was used to provide the required rheology and fluid loss control in the system. There was no specific addition and handling of mixing facilities for this system.

After initial trials on 3 wells, the decision was made to replace the KCl/polymer system with this new inhibitive system as the “fluid of choice” for water-based drilling fluid sections. The system has now been selected as an alternative to KCl in offshore operations East Kalimantan, Indonesia.

To date, a total of 15 surface and intermediate sections of 12 wells have been drilled, cased and cemented successfully in Offshore East Kalimantan, Indonesia using this novel polyamine system. Dilution rates were significantly reduced by about ⅔ as compared to dilutions rates using the KCl/polymer system.
Reservoir Souring in a Field With Sulphate Removal: A Case Study
Authors: Robinson Keith , Ginty William , Samuelsen Eivind , Lundgaard Thomas , Skovhus Torben Lund
Published: February 2011

This paper presents the results of a reservoir souring study in Hess' South Arne field (North Sea, Denmark). The field produces from a 115°C chalk reservoir and utilizes sulphate rejection membrane (SRM) technology to generate low-sulphate seawater (LSSW) for water injection.

In addition to achieving the primary objective of barium sulfate scaling control, eight years of historical data show that the injection of LSSW also significantly reduced the severity of reservoir souring to levels acceptable for continued use of the existing wells and facilities from a corrosion and gas handling point of view.

This case study is especially important information for deep sea oilfields where high-strength steel risers, which are susceptible to sulphide stress corrosion cracking, are utilized and where installation of SRM units can be a significant part of a viable souring mitigation strategy.

In November 2008, an innovative and successful water shut-off operation was performed for oil producer Well-L and production was commenced after a 2 year shut-in. Three weeks later, an unexpected H2S alert was experienced during oil export to a tanker. A follow up H2S survey indicated up to 15 ppm in the bulk gas and in excess of 35 ppm in gas from Well-L. A comprehensive study was therefore initiated to fully understand the causes of souring and to develop a new H2S management strategy to deal with the issue.

Analysis of produced water and H2S concentrations in oil, water and gas was used to generate mass balances of sulphate and sulphide for the reservoir and production system. Analysis of the sulphur isotopes in H2S was made together with a review of the historical H2S scavenger usage and pre-water injection well-test H2S measurements. This showed that reservoir souring was the dominant H2S source and that a significant proportion of the sulphate introduced to the reservoir by the injection water was converted to H2S.

Molecular microbiological methods (MMM) showed high concentrations of sulphate-reducing archaea (a group of thermophilic microbes producing H2S, but genetically very different to sulphate-reducing bacteria) in produced fluids, while traditional most probable number (MPN) techniques gave zero readings.

Microbiological sulphate reduction may minimize the field's barium sulphate scaling risk by reducing sulphate concentrations in the injection water below those achievable by South Arne's SRM equipment alone.
Equipment Design Change Improves Cementing Operations from MODUs Operating in Rough Sea Environment: Case Histories for Two North Sea Jobs
Authors: Romstad T. H. , Rogers H. E. , Saetre T.
Published: February 2011

During the well-construction phase in the oil and gas industry, cementing materials are used to provide annular isolation between the casing and the wellbore. The methods and equipment used to place cementitious fluids in the annulus have evolved significantly over the last several decades. One specific area where significant changes in placement methods and equipment have occurred is in the offshore environment; specifically, cementing operations from mobile offshore drilling units (MODUs). The benefits of traditional inner-string cementing (ISC) methods have not been available to operations in rough seas from floating platforms where the ocean swells exceed the capabilities of the compensators on the rig. As such, new equipment designs are needed to enable use of the inner-string cementing method from MODUs operating in rough seas.

This paper details the problems encountered when attempting inner-string cementing operations from floaters operating in the North Atlantic and newly designed equipment that enables MODU operators to benefit from the successful use of inner-string cementing methods in rough seas. Three case histories are presented that validate the successful use of the newly designed extended-length ISC equipment from a mobile platform operating in rough seas.
The Evolution of the Role of Openhole Packers in Advanced Horizontal Completions: from Optional Accessory to Critical Key of Success
Authors: Gavioli Paolo , Vicario Roberto
Published: February 2011

Openhole packers have been proven to be very effective in many different applications, including curing losses, controlling high-permeability zones and fractures, improving equalization in passive and active inflow control device (ICD) completions, and, most importantly, controlling water and gas production. The usage of these tools increased exponentially in the last few years and will continue to grow. This paper summarizes the most important findings and lessons learned about the role of zonal isolation in advanced horizontal completions.

More than 12 years of experience using reservoir-optimized completions, including passive or active ICDs and openhole packers, has led to the accumulation of best practices and rules of thumb. The approach for openhole packers has changed markedly with time, along with the industry learning about the importance of these tools in advanced horizontal completions.

Important considerations have been generated to design horizontal completions under different fluid properties, reservoir uncertainties, and optimum operational considerations allowing for equalization of flow along the entire length of the horizontal section. These best practices came from extensive run history and lessons learned and it has been found that openhole packers often play the most critical role for a completion’s success. In addition, the availability of a wide range of new zonal isolation tools on the market makes it easier for operators to obtain the best and most cost-effective solution for each application.

Openhole packers for compartmentalization are key for success in many applications and offer benefits for inflow and annulus flow control. An extremely important consequence is the ability to control gas and/or water after breakthrough. This has been proven from analyzing a significant amount of production logs post-installation. Actual well performance data and simulations will be shown to support the discussion and illustrate concepts and findings.
Simulation of Dragon Wells in Thin Oil Rim Reservoirs Using a Segmented Inflow Approach
Authors: Montero Jacobo , Nwankwo Cosmas
Published: February 2011

A study was carried out to establish the performance of a dragon well, or a well that dramatically changes inclination, in a thin oil rim reservoir. A well was simulated using commercial nodal analysis software by segmenting the inflow in multiple sections in order to incorporate the changes in trajectory and intersections with various reservoir layers. This simulation considered the pressure losses along the well bore for the varying trajectory, calculated for individual well sections, layers and combined commingle productivity and pressure profile; and was used to evaluate the well performance for a range of reservoir conditions (depletion, gas-oil ratio and water cut changes). This paper describes the approach used and key observations obtained from the results.

A "segmented" inflow simulation approach can be used to model a dragon well. The method can be applied for modelling wells with sinusoidal trajectories in thin oil reservoirs. The results can be used to guide well and reservoir modellers in the concept assessment of this type of wells in field development studies. The model calculates the segment, layer, and total inflow and pressure profile in a complex trajectory. For the field and reservoir characteristics considered, the simulation indicated that the dragon well can produce through a wide range of conditions, including gas and water break-through. Good initial productivity can be expected from the well, but deteriorates fast with increasing GOR and water cut. As expected, the drawdown is not uniform along the trajectory; hence a drawdown stabilization strategy was addressed for the subject well through the use of a smart well completion. There is limited industry experience on sinusoidal or dragon wells modelling hence the results of the paper should be of interest to production technologists and reservoir engineers. This documented methodology can also be extended to simulation of complex horizontal or multilateral wells.
An Automated System for Determining Analog Formations for Unconventional Gas Reservoirs
Authors: Kun Cheng , Wenyan Wu , Holditch S. A. , Ayers W. B. , McVay D. A.
Published: February 2011

Today, many countries are evaluating unconventional gas resources, which are estimated to exceed 30,000 trillion cubic feet, worldwide. Owing to declining conventional gas production, the U.S. has led the world in development of unconventional gas resources (UGR) and technology over the past 3 decades. To facilitate transfer of unconventional gas technology and development internationally, we developed a software, FAST (Formation Analog Selection Tool), as a tool to objectively and rapidly identify and rank analog formations. FAST software uses an existing database (BASIN) that contains geoscience and engineering parameters for approximately 240 formations in 25 North American basins that are mature for conventional and unconventional oil and gas production. We designed a FAST report module that provides both general and detailed interpretation graphs and tables. FAST reports give an overview of analog results, and they allow insights into the quantitative details of reservoir parameter comparisons. Although the software needs further validation, preliminary testing shows consistent results. Planned and ongoing improvements to FAST include quality checking of formation parameters in the database, assessment of parameter weighting factors, validation of the analog selection performance against the literature and independent studies regarding analog formations, and linkage of FAST with a Drilling & Completion Advisory System to identify the best engineering practices to be applied in early stages of testing analogous target formations.
Sand Erosion Modelling
Authors: Wong Chong , Wu Jie , Zamberi Amir , Solnordal Chris , Graham Lachlan
Published: February 2011

Influx of sand into gas or oil pipelines is often experienced in offshore oil & gas fields. Erosion on pipelines, screens, throttle valves and other pipe fittings by sand particles is a concern to the safety and reliability of operation of the oil & gas infrastructure. To avoid potential erosion during operations, it is beneficial to optimise the design and operational parameters to minimise the erosion rate. It is therefore highly desirable to predict the erosion damage by sand particles through modelling.

Particle erosion modelling is complex and requires a good understanding of the dynamics of particles – specifically, the particle velocity and impingement angle, and its relationship to the removal of material at the equipment surface (e.g. pipe). CSIRO Australia has developed a comprehensive modelling approach utilising laboratory testing in parallel with computational fluid dynamics (CFD) simulations to determine the erosion rate for a given flow geometry, fluid-solid flow condition, material properties and erodent characteristic.

This paper presents an overview of CSIRO's laboratory modelling and testing methods for erosion damage assessment for design optimisation. A method to calibrate a CFD erosion model is presented, and a rapid laboratory visual erosion approach employing a multi-layer paint erosion modelling is also introduced.
Years of Success with Premium Expandable Screens System through Managed Applications and Installation
Authors: Ripa Giuseppe , Bowen Eddie G. , Conte Antonio
Published: February 2011

Since the inception of expandable sand screen technology in the late 1990's, it has seen its ups and downs during its inaugural and acceptance phase. Expandable premium screen technology has seen in recent years an increase in the number of applications in several oilfield typologies. From high rate gas producers to Oil production up to the most challenging gas storage application expandable screens have shown to be a reliable completion for a variety of well types.

As with any new technology there were lessons learned. This knowledge led to the fine tuning of the entire system and required adjustments to the operation procedures and design parameters in order to improve its reliability. The ultimate goal of any technology is to reduce operational cost, maximize productivity, and deliver a reliable completion for many years to come.

After several years of activity, it is now possible to provide a summary of experience in several different applications. The quantity of Expandable Premium screen installations to date supply the opportunity to statistically evaluate the success of this technology but also provide significant operational experience.

The objective is to go through the data base of installations owned by operator and Service Company and provide a Best Practice handbook used not only to optimize deployment and operations but also to increase productivity and improve well longevity. Through the evaluation of several expandable premium screen applications it will describe how starting from conventional sand control techniques the operating procedures have been refined, modified and improved to meet the requirements that the new technology requires for successful execution.
Understanding the Effects of Leak-off Tests on Wellbore Strength
Authors: Wang Hong (Max) , Soliman M. Y. , Shan Zhaohui , Meng Frank , Towler Brian F.
Published: February 2011

Leak-off tests (LOT) are performed to test the "strength" or pressure containment of the shoe after a cement job to help ensure the new hole has been securely isolated from what has been cased off. A successful LOT can also be used to calibrate the least principal stress, or many times the minimum horizontal stress, for geomechanics modeling. This will require initiating a fracture at the wellbore. Due to the near-wellbore stress concentration, for the geomechanics calibration purpose, it is preferred to take the leak-off to the far-field stress region. To perform this extended LOT (XLOT) a relatively long fracture has to be created. Though an XLOT is needed for these reasons, some engineers tend to refrain from performing this test for fear that the test may damage the wellbore and consequently cause drilling problems.

This paper addresses this issue by investigating the effect of wellbore damage on wellbore "strength" or pressure containment. Various issues are discussed to help engineers determine when it may or may not be a concern. This should give practicing engineers the necessary insight into this complex rock mechanics issue. The discussions are supported with results from analytical and numerical simulations based on rock mechanics principles.
Nano-emulsions as Cement Spacer Improve the Cleaning of Casing Bore During Cementing Operations
Authors: Maserati G. , Daturi E. , Belloni A. , Del Gaudio L. , Bolzoni S. , Lazzari W. , Leo G.
Published: February 2011

Nano-emulsions are emulsions where the droplet size of internal phase is less than 500 nm. Due to their small dimensions they have a high surface area and show very peculiar properties. Solvent in water nano-emulsions combine the high efficiency of the small dimensions of solvent to a low interfacial tension, due to the presence of the surfactant mixture used to prepare nanoemulsions. Solvent in water nano-emulsions used as cement spacer formulation could allow optimizing the cleaning of the casing during the cement job with a high improvement of the performances of the spacers currently in use. This methodology, based on high efficiency system with reduced chemical dosage, could also result in a considerable optimization of product cost of cement operation. The objective of this study has been the formulation of direct nano-emulsions (o/w), with a selected solvent as internal phase, in order to improve the casing - open hole cleaning and reverse the surfaces wettabitlity to allow better adhesion of slurry between casing and hole.

Specific laboratory tests have been carried out to compare commercial spacers currently used in common drilling practice with nano-emulsions formulated in Eni Laboratories. Different nano-emulsions were performed in function of solvent content.

The nano-emulsion efficiency was evaluated throughout different methods: Metallic Grid Test, Wettability Test, Contact Angle, Shear bond test. All tests highlight good cleaning properties of nano-emulsions and their better efficiency compared with common spacers.
Impact of Fracture Conductivity and Matrix Relative Permeability on Load Recovery
Authors: Gdanski Rick , Walters Harold
Published: February 2011

The cleanup of fracturing treatments in tight-gas sands has been a subject of focus because of the disappointing performance of many treatments. A fit-for-purpose fracture-cleanup simulator was used to explore factors that might impact cleanup. The simulator includes physics of flow and chemical physics of overall complexity that cannot be effectively studied in the laboratory. Numerical simulations were conducted to study the impact of dimensionless fracture conductivity (Fcd), matrix relative-permeability quality for gas and water, and shut-in times on load recovery after a treatment. Simulation results included the impact of these various factors on gas production rates, total load-recovery volumes, and fracturing-fluid dilution profiles. Three sets of relative permeabilities (rel-perms), four Fcds, and various shut-in times were studied.

Numerical simulations demonstrated the complex interactions of fracture conductivity, matrix rel-perm quality, and shut-in on load recovery and gas productivity. The results gave insight into preferred procedures and practices for cleaning up fracturing treatments in tight-gas sands. Gas-production rates and load recoveries were strongly affected by conductivity and matrix rel-perm quality. Rel-perm sets with a crossover at 10% of rel-perm exhibited good load recovery at high Fcd and poor recovery at low Fcd, with gas-production rates dominated by Fcd alone. A crossover at 0.1% of rel-perm exhibited slow recovery of fluid and slow improvement in gas rates, with peak rates not occurring for months. Extended shut-in times reduced load recoveries for high-quality rel-perms the most. Fracturing-fluid dilution profiles were observed to be a function of both Fcd and rel-perm quality.

This work demonstrates that an arbitrary choice of matrix rel-perms for water and gas can result in prediction of either good or poor load recovery, depending on the quality of rel-perms chosen. In fact, variation in rel-perm quality from reservoir to reservoir might help explain contradictory observations on best practices regarding shut-in times.
Benefits Evaluation of Deepwater Intelligent Completion on Three Isolated Productive Zones Offshore Nigeria
Authors: Arena M. , Di Vincenzo S. , Rossi M.
Published: February 2011

This paper describes the experience and advantages of both the operator and service company in using Intelligent Completion (IC) technology in deepwater challenging environment. Following a feasibility and risk analysis study performed by the operator, a single well with a triple zone the IC was selected as the best completion solution compared to a dual zone or single wells cluster solutions. The increased cost of this technology was justified by the overall CAPEX project reduction, increment of expected cumulative production and anticipated reservoir's lower layers production.

While two zones IC can be completed with the flow control valves run above the gravel packed zones, the same cannot be done in triple zone IC; in this case, to allow fully independent zonal monitoring and control, two out of three of flow control valves and gauges needs to be run inside the lower zone gravel pack assemblies, bringing a complete new set of interface challenges between the upper and lower completion equipment.

Equipment and procedure's risks were addressed and mitigated through Failure Mode and Effects Criticality Analysis (FMECA) reviews and completion System Integration Test (SIT).

Flow control valve's choke design were also checked, based on the expected production profiles and downhole PVT, to cover the entire production rate and achieve the best draw down applicable.

The well was completed across November and December 2008 with no incident and lost time and the completion solution adopted proved not only to solve all the initial reservoir challenges but also to reduce the number of well interventions, workover costs and risk. The well was successfully started up in February 2009 with a NPV increment of 15% and a reservoir recovery factor increase of 6%.
Rock-Fluid Characterization Using OBM Contaminated Samples Issues, Challenges, and Solutions
Authors: Nagarajan N. R. , Honarpour M. M. , Purpich A. J. , Arasteh F.
Published: February 2011

Acquisition of representative rock and fluid data from deepwater reservoirs is challenging and costly but is critical for the successful reservoir evaluation. It is common practice to use oil based mud, OBM, for drilling, particularly in deepwater offshore environment. Without proper mud additives and under excessive overbalance, OBM often invades the reservoir and contaminates cores and fluids. Measurements conducted on contaminated samples result in non-representative rock and fluid properties. Therefore, every effort should be made to minimize contamination in the samples. In fluids, mathematical corrections are needed to remove contamination effect and ensure representative fluid properties. In rocks, measurements on samples with minimum contaminations should be validated with those on cleaned samples.

High OBM invasion in several cores showed elevated apparent in-situ water saturation as identified by visual examination, CT density mapping, residual brine analysis, and total liquid saturation calculation. Electrical resistivity measurement on "as-received" samples and simultaneous capillary pressure and resistivity measurements on cleaned samples provided correct in-situ water saturation determination.

Customized sampling procedures with reliable fluid quality monitoring helped obtain minimally contaminated samples. In addition, novel mathematical techniques allowed correcting fluid samples to calculate representative fluid properties. Field examples are provided to demonstrate the success of these techniques for improved rock and fluid characterization.

The results of this study demonstrate the need for reservoir engineers to be closely involved in fluid sampling, coring, and data acquisition stages employing rigorous QA/QC protocols. Customized sampling and coring programs were essential to obtain minimally contaminated rock and fluid samples and rigorous methodologies were critical to correct the data measured on the contaminated samples and determine representative rock and fluid properties.
Quantifying Source Rock Maturity From Logs: How To Get More Than TOC From Delta Log R
Authors: LeCompte B. , Hursan G.
Published: February 2011

Thermal maturity is the primary factor that determines whether a source rock will produce oil, gas, or condensate. Two new methods for estimating the thermal maturity of source rocks from log data have been developed. First, the delta log R equation has been re-arranged to solve for level of maturity and correlated to vitrinite reflectance. Second, a method to determine kerogen density from log and core data is presented. Examples from the Barnett and Woodford Shales of North America show how changes in kerogen density and delta log R relate to source rock maturity and predict whether the formations will produce oil, gas, or condensate.
Utilization of Rotary Steerable Technology for Field Development and Drilling Shallow-TVD Horizontal Wells
Authors: Peytchev P. , Crighton A. , Upadhyay A. , Govind B. , Malik S.D. , Suryadi H. , Saha S. , Kale S.
Published: February 2011

Cairn Energy India Private Limited (CEIL) started development in Mangala field with aggressive target of drilling 60-70 wells/year (7days/well). Therefore, the focus was to reach high drilling efficiency which will ultimately reduce the well cost. Some of the challenges faced were placing wells in greatly faulted zones, high uncertainty in shallow TVD reservoir, requirement of tangent for installation of ESP, smooth hole to avoid problem running screen and collision risk due to closely spaced wells. RSS was generally used only in complex, high-cost offshore projects where the savings realized were significant. The industry has been slower to adopt the use of RSS for onshore directional drilling applications however CEIL took a step ahead by deploying RSS for Mangala field development. RSS was utilized in directional wells to optimize drilling performance and deliver smoother hole profile. Advanced LWD services such as bed boundary detection tool along with RSS have brought value in successful landing and placement of horizontal wells in the best reservoir strata. Application of near-bit gamma ray and other LWD measurements to identify the top of reservoir as early as possible has helped to avoid the requirement of drilling pilot holes. This paper discusses such application in detail and presents its benefits.

The result was a noticeable improvement in well delivery time, reduced drilling cost, and improved hole quality. This paper compares the drilling performances with PDM vs RSS in the same field and presents the lessons learnt in the process of field development. RSS delivered less tortuous hole which result in a problem-free liner or screen run. Hole cleaning was improved which allowed to drill at faster ROP without taking risk of well complication. Time versus Depth analysis clearly indicated that RSS was both technically and economically, a sound approach for drilling the wells in Mangala field. This paper showcases a case study where RSS application proven to be cost-effective solution even in low-margin onshore field development.
Flow Instability in Deepwater Flowlines and Risers - A Case Study of Subsea Oil Production from Chinguetti Field, Mauritania
Authors: Takei J. , Zainal M. Z. , Ramli R. , Matzain B. , Myrland F. , Shariff A. M.
Published: February 2011

The Chinguetti field located west of the Mauritania coastline has recently experienced a slugging condition in its flowline and riser systems. A study was undertaken in which integrated production system models of Chinguetti wells, flowlines and risers were developed using OLGA® transient multiphase flow simulator. The field is at a water depth of ∼800m and was developed with subsea wells, manifolds, 2 flexible flowlines and lazy "S" shaped risers tied back to a permanently moored turret Floating Production Storage Offloading (FPSO) located 6km away from the furthest drill centre. The main objective of the study was to assess slugging and potential methods to improve flow stability in the Chinguetti systems.

An extensive field validation and benchmarking exercise was performed by tuning the models to match field pressures and phase flowrates in the systems. The goal was to validate the models as closely imitating the conditions in the field. However, uncertainties in the field data made it difficult to reach satisfactory results in the benchmarking exercise. Simulations were then performed to examine the impact of various changes in operating conditions on flow instability. These included changes in well routings, gas lift injection rates and location of injection points, riser and wellhead choke openings. The degree of fluctuations in liquid arrival rates and the characteristics of liquid slugs (length and frequency) were used to categorize the severity of flow instabilities for a range of operating conditions.

Results from field implementation of recommended changes in operating conditions indicated improvement in flow stability. The success of this study was found to be dependent not only upon the inputs and assumptions made in the production system models but also on the outcome of the field validation exercises, and the understanding of pertinent governing factors influencing slugging behavior. The study highlights the methodology and analysis used to assess flow instability, outcome of field implementation, challenges faced and solutions proposed to minimize the flow instability of a deepwater oil field development.
Modeling World Oil Supply: Its Peak Production Rate and Time – Model Validation
Authors: Nashawi I. S. , Malallah A. , Al-Bisharah M.
Published: February 2011

Modern civilization as it is known to us heavily depends on hydrocarbon fluids and their byproducts. So far, the industrialized nations have completely presumed for granted an uninterruptable supply of cheap crude oil. Petroleum liquids are exhaustible resources; thus, a good forecasting scheme of oil supply will be crucial to all parties involved in the petroleum business such as oil companies, financial institutions, public policy planners and makers, and oil exporting and importing countries. Such a model will also help bring stability and security to the crude oil market. Over the years, accurate prediction of oil production was confronted by fluctuating ecological, economical, and political factors, which imposed many restrictions on its exploration, transportation, and supply and demand.

The objective of this paper is to illustrate the advantages of the multi-cyclic Hubbert model. We will demonstrate the effectiveness of the proposed model for the cases where the production rate fluctuates with time. We will also illustrate the effects of new discoveries or additional reserves due to innovative technology on peak oil rate and time and show how the multi-cyclic model accommodates these changes. Furthermore, we will demonstrate the flexibility of the proposed model to history match any future fluctuation in the production data. Historical production data of 47 countries around the world are used to predict the peak oil. The production rates of the last four years (2006-2009) are used to validate the accuracy of the model.