bluuebunny/crossref_metadata_2025 huggingface dataset:
Cost Effective Deepwater Well Construction— A Case for Managed Pressure Drilling With Casing
Authors: Oyeneyin M. B.
Published: December 2009

Engineers now face increasing challenge of drilling in Ultra Deepwater environments which form the cornerstone of future field developments. The deepwater environments are characterised by complex temperature profiles and geological features such as High Pressure-High Temperature (HP-HT) with very narrow pore pressure-fracture pressure window; Shallow unconsolidated reservoirs with very high overburden; Combination of ‘'flexible" lithologies. In these environments the use of overbalanced drilling techniques becomes difficult as the tolerance between formation pressure, wellbore pressure and the pressure at which the formation will fracture becomes very small. This can lead to severe drilling problems with attendant increase in drilling costs to possible loss of well control itself. These deepwater environments can benefit from Managed Pressure Drilling (MPD) when effectively combined with casing drilling technique but its uptake has been rather slow.

For the industry to develop a managed pressure drilling capability that will allow today's generation of complex wells to be drilled safely with casing, it is necessary to develop models that will accurately simulate the MPD process and to embed these models within an easy to use, intuitive well design package for pre-planning and as a real time tool to monitor, diagnose and optimise downhole operations and provide forward simulations based on rig and downhole data.

This paper presents the unique algorithms developed to simulate the MPD process and to analyse the effects of soft issues on the wellbore flow and pressure regimes and impact on torque/drag.

The algorithms developed have been validated with live well data including pump rates, fluid properties and especially PWD and pump pressure data. The predictions and actual data have been found to be in very close agreement.

The results of algorithm validation are presented to illustrate how the simulator can be utilised for real time design as well as process optimisation especially for casing drilling versus standard drillstring scenario. Highlights of the effects of the complex relationships between eccentricity, rotation and fluid rheology at bottom hole and riser conditions are also presented to illustrate the drilling process optimisation. The paper is concluded with guidelines on MPD operating windows for different scenarios and a brief description of the system architecture of the MPD Simulator – The MPDEEP.
Implementation of Integrated Network Optimization Model for the Mumbai High Field—Crucial to Field-Wide Optimization
Authors: Jha Anand Kumar , Barua Santanu , Agrawal Vikas , Agarwal Gunja , Kumar Ravi , Moitra S. K. , Negi G. S.
Published: December 2009

The giant ONGC Mumbai-High offshore field produces about 250,000 bopd (60% water-cut) from 700+ wells through 110+ unmanned production platforms. The production platforms are connected by subsea flow lines to 6 processing platforms where the oil, water and gas are separated. More than 80% of the wells in the field are on gas-lift.

This paper discusses an integrated-network-modeling-and-optimization approach to overcome known drawbacks of single well gas-lift optimization. The new higher fidelity model captured the interactions between wells, flow-lines and platforms, field-wide. Using this approach, previously hidden opportunities for significant production improvement were identified. The model indicated a possibility of significant production increase (2 to 4%) and production efficiency improvement (significant reduction in lift gas requirement), which could be achieved by better allocation of lift gas and repair and redesign of the sub-optimal gas-lift wells. The latest available field implementation results are also presented.

Currently, in the absence of full-loop control-automation of the gas-injection rates/pressures, logistical challenges made it impractical to simultaneously implement the calculated optimum settings field-wide. The network interactions are highest at the production-platform level between adjacent wells and connecting shared flow-lines. So, from practical implementation considerations, optimum gas-injection rates were calculated and simultaneously implemented at the production-platform level, one (or a group of few connected) production platform at a time, with little or no compromise on the quality of the solution or on the validity of the approach.

To date, actual optimization implementation changes in 14 of the 110+ platforms (160 of the 700+ wells) indicated immediate production increase of over 2000 bopd and significant reduction in lift gas requirement. Based on these early indications, it is envisaged that the field-wide oil production gain can possibly be as high as 6%.

Additionally, this paper discusses the challenges and recommended approaches with regards to sustainable model maintenance, solution implementation and workflow. Status of control automation and on-line modeling plans (planned for implementation in future) are also discussed.
Optimised Completion of a Produced Water Re-injection Infill Well
Authors: Mason John , MacLeod Innis
Published: December 2009

A produced water re-injection (PWRI) well, PWRI-3, was drilled and completed from the Eastern Trough Area Project (ETAP) North Sea platform in 2008. Two previous wells, PWRI-1 and PWRI-2, were drilled early in field development to inject all produced water into a Palaeocene sandstone aquifer at 2800mTVDss, 125degC and 4100-4500psig reservoir pressure.

As the fields have matured, increasing volumes of produced water need to be injected as expected. At the same time, declining injection rates into the two disposal wells has resulted in the fields becoming limited on water disposal. Oil production constraints due to produced water disposal have developed since about 2005. As a result, planning for a third PWRI well was kicked-off in 2006.

This paper details the design, installation and initial performance of PWRI-3, focussing on the well completion. As a single infill well requiring mobilisation of a heavy-duty jack-up, the requirement for PWRI-3 was to deliver a high quality, high integrity, high rate, long life water injector. The multiple sources of produced water from the ETAP fields create a complex chemical cocktail, requiring the completion to cope with varying levels of CO2, H2S, chloride, sulphate, barium and production chemicals. A cemented 7" 13%Cr liner, fibreglass-lined 7" injection tubing, alloy 718 completion jewellery and a fully clad 7" tree were selected. Specific measures were taken to minimise risk of wireline damage when running perforating guns through the injection tubing. Concerns about managing increasing pressures in the Palaeocene led to the installation of a downhole gauge, to help maintain high injection rates within the limits of caprock fracturing pressures.

To understand injection fracturing and to maximise injectivity, a specific sequence of perforating and bullheading was used. To reduce the environmental footprint of the rig activity, over 2500bbl of contaminated seawater (containing residual oil based mud from the mud-to-brine wellbore displacement) was bullheaded into PWRI-3 during this rig injection testing.
Mitigation of Vapor Cloud Explosion Effects by Inhibitors
Authors: Hoorelbeke Pol , Mukharror Darmawan Ahmad
Published: December 2009

Devastating vapor cloud explosions have occurred all over the world since decades. Avoiding this type of major accidents is a real challenge for the oil industry. Total performed theoretical and experimental research in the potential to mitigate the effects of vapor cloud explosions with inhibitors. Experimental results in 50 m3 module at Sotra (Norway) showed that overpressure reduction up to 90% could be obtained.
New Single-Trip, TAML Level 4, Multilateral Junction Technology Reduces Well Costs in Norwegian Sea Subsea Well—A Case History
Authors: Balstad Olle , Glaser Mark , Heng Tage
Published: December 2009

The installation of the first single-trip Technology Advancement for Multilaterals (TAML) Level 4 multilateral (ML) junction system was completed in a subsea, gas-injection well. It was drilled to support oil production from the Tilje and Ile formations in the Smørbukk Sør field in the Norwegian Sea, approximately 193 km offshore in 300 m water depth.

After injecting for ten years, the well will be converted to a gas producer from the same formations. Because of the Norwegian Sea's environment, the multilateral system had to be low risk and simple to install, with the capacity to minimize pipe trips and withstand the heaving seas. The casing exit had to be long enough to accommodate running a rotary steerable system through the window to drill the lateral to TD. This window had to be milled in a single trip in 13%Cr 110 casing followed by milling into the Garn 4 hard-impermeable sandstone with possible quartz stringers.

Hollow-whipstock technology has been employed for more than ten years in the North Sea, but a new system, designed to be installed in a single trip—-a savings of two pipe trips—-was selected for this project. The hollow whipstock was perforated through after the liner was installed in the lateral to regain hydraulic access to the main bore below the junction. The hollow whipstock was used for the milling and production/injection phases and was not retrieved, saving an additional pipe trip. The well completion used several cementing and completion products and services, including liners with screens and swell packers. Stage cementing was performed to isolate permeable formations between the junction and the reservoir.

The well was successfully completed and gas injection began with increases in production being noted from the adjacent producing wells. Although it was unusual to use a multilateral well for gas injection, the technology proved that it can be applicable to any multilateral well requiring a Level 4 junction.
Successful Practices and Development of Polymer Flooding in Daqing Oilfield
Authors: He Liu , Jinling Li , Jidong Yan , Wenjun Wang , Yongchun Zhang , Liqun Zhao
Published: December 2009

Basing on improving volumetric sweep efficiency and reducing channeling and breakthrough, polymer flooding can yield a significant increase in oil recovery when compared with water flooding. Polymer flooding has been conducted successfully in 13 field tests since 1989 and has been commercially used in the following years. Field tests show that the recovery improving with increasing of concentration and injection volume. By applying polymer flooding, the main formation recovery of Daqing oilfield has reached more than 50%. It is 10% ~ 15% higher compared with the other oilfields. In the 20 years' practices of polymer flooding, Daqing Oilfield has developed a complete series of techniques covering reservoir, production, facilities engineering and produced liquid treatment. Polymer flooding has gradually become an important technique to maintain the high and stable production capability of Daqing Oilfield. Daqing oilfield, being the largest polymer flooding field in the world, has 37 polymer flooding areas which contain nearly 9000 wells by the end of 2005. Now, polymer flood production has achieved 1×109t/a in Daqing Oilfield. In this paper, the reservoir condition, pilot test, solution production and injection, production technology and produced liquid treatment technology are described.
CO2-ECBM/Storage Activities at the San Juan Basin's Pump Canyon Test Site
Authors: Koperna George J. , Oudinot Anne Y. , McColpin Glenn R. , Liu Ning , Heath Jason E. , Wells Arthur , Young Genevieve B.
Published: December 2009

The Southwest Regional Partnership on Carbon Sequestration (SWP) is one of seven regional partnerships sponsored by the U.S. Department of Energy (DOE) that collectively includes more than 350 organizations spanning 40 states, three Indian nations, and four Canadian provinces. The objectives are to determine the most suitable technologies, regulations and infrastructure requirements for carbon capture, storage and sequestration in different areas of the country. In Phase I of the partnership program, significant sources of greenhouse gas emissions were inventoried, potential geological sequestration sinks identified, and small-scale sequestration demonstration opportunities developed. Many of these small-scale pilot demonstrations are currently being implemented as part of the Phase II program. One of the three geo-sequestration pilots for the SWP involves CO2 injection into a deep, unmineable coalbed at the Pump Canyon site located in the San Juan Basin of northern New Mexico.

At the demonstration site, a new CO2 injection well was drilled into the late-Cretaceous Fruitland coals within an existing pattern of coalbed methane production wells. CO2 is currently being injected into the coal at pressures not to exceed the permitted injection pressure, and a variety of monitoring, verification and accounting (MVA) methods are employed to track the movement of the CO2. Some of the MVA methods include continuous measurement of injection volumes, pressures and temperatures within the injection well, coalbed methane production rates, pressures and compositions at the offset producer wells, tracers in the injected CO2, time-lapse vertical seismic profiling, surface tiltmeter arrays, a series of shallow monitoring wells with a regular fluid sampling program, and surface measurements of soil compositions, CO2 fluxes, tracers, etc. In addition, a detailed geologic characterization and reservoir modeling has been implemented in order to reproduce and understand the behavior of the reservoir. To date, the injection is still on-going and no CO2 breakthrough has occurred.

This paper provides a description of the Pump Canyon CO2-ECBM (enhanced coalbed methane) and sequestration demonstration field activities with particular emphasis on the lessons being learned.
The Use of LWD Data for the Prediction and Determination of Formation Pore Pressure
Authors: Greenwood Jeremy , Russell Rick , Dautel Mike
Published: December 2009

The ability to predict and determine formation pressure has been an important issue since the beginning of the industry. This issue has become of increasing importance in deepwater environments where the relationships between increasing pore pressures, formation fracture gradients, and ultimately wellbore stability becomes of critical importance and can determine whether or not a well can be successfully drilled to total depth (TD).

Pre-drill modeling using seismic, structural, and geological data can be used to attempt to predict pore-pressure regimes. Traditional methods of monitoring pore pressure while drilling have relied on methods, such the use of drilling exponents, and other indirect methods, including the monitoring of connection gases and observations of cuttings shapes. These methods are often imprecise, and their success depends on the actual pore pressure generation mechanism.

The development of new logging-while-drilling (LWD) technologies in recent years has added powerful new tools for the accurate determination of pore pressures and wellbore stability. LWD resistivity and sonic measurements can indicate overpressure in shale sequences. Measurements in hole sizes as large as 30 in. make it possible to establish compaction trends in deepwater wells from near the seabed. Direct measurements of formation pressure can now be made with LWD formation pressure tester tools, which can accurately measure formation pressures directly while drilling and, when used with pressure-while-drilling (PWD) measurements, can precisely manage effective mud weights in narrow mud weight window environments.

Advanced LWD imaging technology can now be used to evaluate wellbore stress fields, which can enhance the understanding of hole stability and overpressure generation mechanisms. This paper reviews the use of LWD sensors for pore pressure analysis and uses case histories to demonstrate their application and value.
Contacting the Reservoir—Benefits of Horizontal Open-Hole Completions
Authors: Yakeley Sean , Wood Ed , Knebel Mark
Published: December 2009

Due to the ever-increasing demand for oil and gas, it is becoming more evident that getting the most out of the reservoir is crucial. For years, wells were drilled vertical or deviated, but horizontal and extended-reach trajectories are gaining more prominence. While the objective is to gain more access to the reserves, often the past methods of completions simply were not viable. In deviated wellbores, cased and cemented liner applications are difficult to obtain a good cement bond with the formation, and the inherent near-wellbore damage associated with cementing can lead to costly workover and stimulation treatments. Thus, open-hole completions are becoming more acceptable as the primary completion of choice.

This paper will discuss the benefits of gaining as much contact with the reservoir as possible to create maximum drainage. It also will cover completion solutions (turnkey) that have been deployed around the world to better optimize recovery. Case histories will be provided that include multi-stage fracturing with swellable packers, inflow control devices with mechanical-set packers, geothermal hook-ups with openhole anchor, and multilateral completions with sand control and zonal isolation.
Computational Mechanics Based Workflow and Toolkit to Manage Deformable Reservoir Developments
Authors: Kristiansen T. G.
Published: December 2009

The standard workflows for predicting field performance in the oil and gas industry is not effective when dealing with highly deforming reservoirs. The definition of highly deforming reservoirs with high risk is not well defined, but these fields typically produce development surprises like casing deformations, drilling problems, well failures and in some cases reservoir performance prediction challenges. In cases like this, production from wells can cease although the upfront reservoir flow models have predicted many years of production and revenue. When the deformation is substantial enough, it will also result in surface subsidence that could impact surface facilities, platforms, pipelines and environmental sensitive areas. This paper presents a more robust workflow and toolkit for these challenging reservoirs than the traditional industry workflows used most often today. The workflow is expanding the traditional workflow to also include computational geomechanics as a critical part of the field performance prediction and management. The workflow and toolkit is illustrated by a field case, the Valhall field, where substantial cost savings already have been experienced from implementation of the workflow and toolkit.
Environmental Risk Management Capability: Advice on Minimising the Impact of Both Sonar and Seismic Offshore Operations on Marine Mammals
Authors: Mollett A. , Schofield C. , Miller I. , Harwood J. , Harris C. , Donovan C.
Published: December 2009

There is growing concern about the effect of noise pollution from Offshore Operations on whales, dolphins, porpoises and other marine fauna both in the scientific and political communities. The general public, media and key decision makers are becoming more aware of the potential impact of such operations and this is increasing the pressure on organisations to manage their acoustic impact on the marine environment.

The Environmental Risk Management Capability (ERMC - a software package developed by BAE Systems in collaboration with the Sea Mammal Research Unit (SMRU) and the Centre for Research into Ecological and Environmental Modelling (CREEM) at the University of St Andrews) is the first system to provide a quantitative, robust and repeatable risk assessment method of the potential impact of sonar on both human divers and marine fauna. To assist in the effective management of this impact, ERMC can provide the user with recommendations of potential mitigation measures, and more importantly supports a basis from which the user can continue to use active sonar whilst complying with their operating policies and legislative obligations to protect the environment.

This paper will discuss how ERMC can be employed to provide a risk assessment for both sonar and seismic offshore operations which introduce sound into the marine environment. It will also discuss whether such an approach would provide a more flexible and reliable outcome to methods commonly in use today.
Slug Control With Large Valve Opening to Maximise Oil Production
Authors: Ogazi A. I. , Cao Y. , Yeung H. , Lao L.
Published: December 2009

Severe slugging in an offshore riser pipeline imposes a major challenge to production and flow assurance in the oil and gas industry. Riser top valve choking has shown effectiveness in eliminating severe slugging. However, most manual choking and active control techniques were tuned by trial and error resulting in operation at a smaller than required valve position. This imposes unnecessarily high back pressure on the riser-pipeline which leads to reduction in production. One way to overcome this problem is to design the active control system to operate at a large valve position. However, at such an operating point, the riser pipeline system is naturally open-loop unstable associated with severe slugging flows.

In this work, an approach to tune a robust PID slug controller at an open-loop unstable condition is proposed. Firstly, at an open-loop unstable operating condition, a reliable linear model is derived from the nonlinear simplified riser-separator model (SRSM) developed in previous work. Then, a robust stabilizing PID controller is designed based on the linearised model.

The controller was successfully applied to a 2" laboratory riser at Cranfield University and a 8" generic industrial riser system modeled in the commercial simulator, OLGA. OLGA simulation on the industrial riser system shows that the proposed approaches not only can eliminate severe slugging but can also increase oil production. It also shows that the percentage improvement in oil production compared with manual choking will increase as the well pressure declines. This means that even more can be gained by adopting active slug control for mature oil fields than for relatively new fields.

The result is very significant for mature fields which are susceptible to severe slugging and low oil production due to declining reservoir pressure.
Reelwell Drilling Method—A Unique Combination of MPD and Liner Drilling
Authors: Vestavik Ola , Kerr Scott , Brown Stuart
Published: December 2009

The Reelwell Drilling Method is developed to improve the capability to drill wells through difficult pressure zones, to solve hole cleaning problems and to increase the ERD horizontal displacement. The method uses a concentric drill string and new downhole tools for improved downhole pressure control. The method was recently used for deepening of a well at Ullrigg in Stavanger, Norway. Here the 8 ½" hole section was drilled with a downhole motor and MWD to verify the capability for directional drilling and for downhole pressure control.

The results from the drilling operation show that the Reelwell Drilling Method has successfully verified all the pilot well drilling objectives:

– Excellent interaction with conventional mud pulse MWD. – Full directional drilling control. – Precise downhole pressure control, including the capability for downhole pressure isolation.

The new equipment and procedures have been reviewed and certified by DNV, and the plain version of the Reelwell Drilling Method is now ready for commercial applications. The liner drilling version is planned to be qualified within short time.
Controls on the Lower Cretaceous Carbonate Habitats of the South Porcupine and Goban Spur Basins, Offshore Ireland
Authors: O'Sullivan J. M. , Jones S. M. , Hardy R. J.
Published: December 2009

Exploration drilling together with 2D seismic data suggests the presence of an extensive Lower Cretaceous carbonate depositional province in the South Porcupine and Goban Spur Basins, offshore southwest of Ireland. Interpreted environments of deposition range from large scale carbonate shelf development through platform margin to isolated offshore carbonate build-ups. During the Late Jurassic to Early Cretaceous period, these basins underwent a phase of normal detachment faulting and regional subsidence associated with high degrees of lithospheric extension. This phase of tectonic activity is interpreted to have exerted a primary regional control on carbonate development in two ways: rapid development of accomodation space limited the influence of clastic sediment input in basin margin depocentres; and the rotated, up-standing footwall crests of normal fault blocks provided intra-basinal bathymetric shoals for carbonate colonisation. Locally, both eustatic and isostatic changes are interpreted to have controlled carbonate deposition, providing a linkage from macro-scale stress fields to micro-scale reservoir architecture. Trophic conditions such as paleo-latitude, ocean circulation and wind direction appear to have exerted a secondary influence on carbonate development. These Lower Cretaceous carbonate sequences can be correlated with world class petroleum reservoirs which span the northern hemisphere from the Middle East to the Gulf of Mexico. Such carbonate systems could form the basis of an important paradigm shift away from the traditional Mesozoic clastic-dominated play systems of the Atlantic Margin in the future exploration of these emerging frontier deepwater basins.
Novel Activation Fluid System
Authors: Rickman Richard , Allison Dave , McCabe Mike , Janson Jon
Published: December 2009

The success of producing gas from unconventional resources, such as shales, is often tied to maximum exposure to the reservoir. Usually this is achieved by drilling horizontal wellbores and creating fractures that originate from multiple points along the wellbore. Each fracture "stage" must be isolated from the previous stage so as to create additional unique flow paths for the gas. One mechanism to create the fracture isolation points is to use chemical swelling packers between the liner and the formation. These chemical swelling packers can be swollen using water-based fluids, hydrocarbon-based fluids, or combinations of both.

Certain shale formations, like the Lower Huron and Marcellus, are often drilled with air or foam. One reason for air drilling is that these formations have shown a propensity to incur damage from traditional drilling fluids (both hydrocarbon- and water-based). Because of this, there can be reluctance to use traditional fluid systems to activate chemical swelling packers in these formations.

This paper documents the laboratory investigation and development of a novel activation fluid system that minimizes the potential damage to the reservoir but still permits operations to take advantage of the unique characteristics of the chemical swelling packer. Included is a discussion of the operational issues encountered to "scale up" for the first field trials and the results of the first commercial applications.
Plugging and Abandoning Multilateral Horizontal CBM Wells for Safe Mine through Operations
Authors: Suhy Thomas E.
Published: December 2009

Since the first commercial sale of Coalbed Methane (CBM), the process of drilling and producing methane with multilateral horizontal wells has been a "win-win" plan for the entire coal industry in North America. It creates a revenue stream by exploiting a valuable resource while de-gassing coal and lowering safety risks ahead of mining operations. Modern CBM wells are usually drilled up dip, in a tri-lateral "Turkey Track" pattern. Each lateral extends approximately 4000’ beyond the horizontal build section.

Normal mining operations allow approximately ten years of production to produce and deplete the adsorbed gas contained in the coal. Recent increased energy demands with favorable market increases have accelerated the mining schedules and shortened the available gas production time. These factors have lead to hazardous conditions encountered when mining through the yet depleted lateral well bores where dangerous volumes of trapped methane can inundate the occupied mine work area. Currently, mine operators are forced to use water infusion and in-mine drilling and grouting operations to safely intersect the horizontal well bores. This results in costly mine production delays.

The best solution requires a stable medium that can be positively placed through the extent of the well laterals and effectively displace and fill void spaces where methane gas can accumulate. This paper will explore and evaluate the results of applying variety of products, equipment, and techniques solve this quandary.
A Novel Foaming Agent for Hydraulic Fracturing: Laboratory Investigation and Field Usage
Authors: Lin Lijun , Danican Samuel C. , Mueller Fred A.
Published: December 2009

A series of surfactants were evaluated in this study and the results were compared with conventional foaming agents used in fracture fluids. These surfactants were examined by surface tension measurements, bench-top foam height and half-life experiments, and viscosity measurements on a circulating foam rheometer. The foam rheometer allowed viscosities to be measured under conditions that are representative of those found in formations. Both nitrogen (N2) and carbon dioxide (CO2) foams were investigated. This paper presents detailed results obtained from laboratory experiments, which led to the identification of foamer A that exhibited excellent performance in the presence of nitrogen and carbon dioxide over a wide range of temperatures. Foamer A was found to be superior compared with conventional foamers, particularly at high temperatures. It is compatible with linear gels as well as crosslinked fluids commonly employed for fracturing treatments. Numerous fracturing treatments with foamer A have been successfully executed in the field.

It is emphasized in the paper that the type of foamer used in fracturing treatments has a great impact on the resulting foam stability and viscosity. In addition, bench-top foam height and half-life experiments can give an indication of the performance of a specific surfactant, but its behavior under downhole conditions cannot necessarily be inferred accordingly.
Viscoelastic Surfactant-Based Systems in the Niagaran Formation
Authors: Kreh Kristopher A.
Published: December 2009

The Niagaran formation in the Michigan basin is comprised of Silurian Pinnacle reefs. It is a heterogeneous carbonate formation with the majority being dolomite. There are two Niagaran plays in Michigan, the Northern Play and the Southern Play. Past stimulation treatments on the Niagaran have consisted of mainly hydrochloric acid at concentrations of 15-28%. Most treatments were kept to matrix conditions due to water zones in close proximity. These treatments usually yield marginal results due to the acid being spent mostly near well bore. Gelled, crosslinked or emulsified acid are good solutions for this problem but can also leave some damage behind. Acid gelled with surfactants can yield similar results and be easier to clean up.

This paper will provide some background on the Niagaran formation and historical treatments. The paper will explain the chemistry behind viscoelastic surfactant-based acid systems and will provide detailed descriptions of the benefits of these types of systems. Production data from a well treated with both conventional acid and a viscoelastic acid system will be discussed. The paper will then conclude with a few words on the economics behind viscoelastic systems.
Production Forecast of Fractured Well in Tight Gas Reservoir, Accounting for 3D Fracture Geometry and Variable Fracture Conductivity
Authors: Jin X. , Wei Y.
Published: December 2009

Producing natural gas from Tight Gas Sand (TGS) reservoirs is currently very important to the industry in North America and will be of increasing importance to the global energy industry in the coming decades. Productivity index (PI) is an important indicator of a well’s production capacity. For conventional reservoirs, well productivity is usually calculated using the pressure response of the reservoir in its pseudo-steady state period. However, for TGS reservoir, the period of transient flow covers a larger part of the well lifetime and the pseudo-steady state productivity calculations become less applicable in prediction of the reservoir’s production behavior. The Distributed Volumetric Sources (DVS) method can fill this gap. The DVS method can be used to predict the productivity index of a general well completion scheme for both transient flow period and pseudo-steady state flow period. In the paper, we will generally describe the DVS method and the model we have build to predict the PI of TGS reservoir using DVS method.

In this study, we focus on a typical well completion scheme — vertical well intersected by a vertical fracture of finite conductivity. Parametric study is performed by varying the proppant pack permeability with a linear distribution, varying fracture width with an elliptical distribution and varying fracture height with an elliptical distribution. The details of hydraulic fracture are integrated into the calculation of well productivity. By combining the well productivity with gas material balance, production forecasting of the hydraulically fractured wells could be easily obtained. The result of production forecasting could be used to aid in decision making of choosing the best stimulation treatment. Field examples are presented to illustrate the application of this technology for production modeling the complicated reservoir cases involving fracture stimulation.
A Practical Approach to Initial Production (IP) Rate Estimation for Infill Oil Wells
Authors: Eruvbetine Obor , Odusote Olufemi , Aitokhuehi Inegbenose , Imogu Moses , Ekeng Oyie
Published: December 2009

Asset development teams have the responsibility of identifying, evaluating and executing infill well opportunities. In maturing these projects, realistic forecasts are needed. An intrinsic part of these forecasts is the initial rate of production, which influences the economic viability of the opportunity and the producing life of subsequent facilities. It is every team's desire to come up with a range of producible rates given reservoir, wellbore and surface constraints. This would serve as the basis for the decisions regarding rates of production. Inflow-outflow modelling (nodal analysis) is generally the accepted method for rate prediction. However, data and time constraints such as unreliable well tests, BHP surveys and questionable PVT data can make rate determination very challenging.

This paper details a methodology to overcome these obstacles through the application of a two-dimensional approach to deriving a range of production rates using both integrated modelling and analog comparisons. The 2-step approach involves building an integrated production model that includes wellbore models connected to a surface production network (could be built to varying levels of complexity). The results from the network model are tuned using an acceptable set of well test data from analog reservoirs. The end result is a more realistic range of IP rates that are representative of the opportunity under evaluation.

The workflows detailed in this paper were used to derive forecasts for infill oil wells in the offshore Niger Delta. A few of these have been drilled and many are currently being evaluated, some of the challenges, lessons learned and results are also shared in this paper.
Risk Identification Report and Employee Motivation - Strategy for Capacity Development in the Nigeria Energy Sector.
Authors: Tubosun Fagbe
Published: December 2009

The study sought to identify the positive effect of prompt report of identifiable risks and hazards in the Nigeria Energy sector by her workforce and other parties involved in Oil and Gas business. Two broad types of data, the secondary and primary data were used in the study. Interviews and personal observation within an Oil Exploration Company was also used for the purpose of establishing role of employee motivation on Risk Identification report.

Furthermore, factors impeding the effective and efficient risk reporting were identified, wrong attitudes and perceptions of people about safety issues that contributed to rising rate of accident most especially the fire outbreak in Nigeria was also highlighted. It is disheartening to note that majority of Nigerians did not have basic safety training in the colleges, homes and at work. Therefore this paper will be useful in creating awareness to the teeming Nigerians especially the locals that are engaged in Seismic and other associated Oil and Gas operation on timely Risks identification and reporting.

In addition, findings revealed that monthly reward of Safety conscious employee reduces the probable accident rate in the Oil Sector. It was recommended that all staff and stakeholders in the Oil and Gas Companies should be given adequate training on Risk Identification, reporting and preventive management technique along with standardized recognition of diligent workers through awards, promotion and further training.
A Hybrid Approach To Assess Decommissioning Options for Offshore Installations
Authors: Andrawus Jesse A , Steel John A , Watson John F
Published: December 2009

Decommissioning of offshore installations is increasingly becoming a crucial issue to the Oil and Gas industry as most assets within the sector are approaching the end of their economic life. Common decommissioning options include complete removal, partial removal and re-use. Inappropriate selection of a decommissioning option can have severe financial, environmental, health and safety consequences. The best available option is usually determined by taking into account technical feasibility, economic viability, consumption of natural resources and, health, safety and environmental impact.

Net Present Value (NPV) analysis is often used to assess the economics of decommissioning options. However, an economic analysis based on purely financial criteria is not in itself adequate for valid decision making. Non-financial factors which are not reducible to monetary values should be identified and incorporated into the overall economic analysis. Weighted Evaluation (WE) is a technique used to assess the feasibility of non-financial factors. In this paper, a hybrid of NPV analysis and WE technique has been developed to assess the economic and technical viability of decommissioning options. The hybrid technique is used in a case study to assess and compare the impact of different decommissioning options on a selected Oil and Gas platform. An appropriate decommissioning option with minimum combined financial, environmental, health and safety impact is determined.
Multidisciplinary Approach to Optimising Hydrocarbon Recovery From Conventional Offshore Nigeria: OML100 Case Study
Authors: Faseemo O. , Massot J. , Essien N. , Healy W. , Owah E.
Published: December 2009

Optimisation of hydrocarbon recovery from mature fields has always been very attractive in the petroleum industry. This will increasingly be of great importance going by the complexity of making new commercially viable hydrocarbon discoveries, and the high cost and long delays of bringing new discoveries into production.

OML100 is a conventional offshore block located 80 km south-east of the Nigerian coast and operated by Total E&P Nigeria in partnership with the Nigerian National Petroleum Corporation (NNPC). It comprises four producing fields, namely: Afia, Edikan, Ime and Odudu; and two other fields which are currently being studied for subsequent development.

Field development started in 1993 with oil production reaching a plateau of 70 MBD between 1995 and 1998. Due to sound reservoir management practices and collaboration with other entities, 39% hydrocarbon recovery has been achieved in the 16 years of production. Today the block faces series of challenges militating against the realisation of more than 50% recovery which is our base case objective. These challenges include: ageing surface facilities, increasing gas and water handling challenges, sand production, loss of wells, insufficient well activation, limited reservoir pressure maintenance, by-passed oil and remaining reservoir uncertainties.

This paper highlights practical multi-disciplinary approaches that are being employed in order to maximise oil production, at minimum cost, from the four fields located in a challenging offshore environment. Reference is made to standard definitions of conventional offshore and mature oil fields. This is followed by a review of the development history, status and challenges of the fields. Methods towards continual optimal reservoir surveillance and exploitation are discussed as a case study and these include: seismic data reprocessing and reinterpretation, review of geological models, update of reservoir synthesis and models, infill development proposals, sand bailing and zone change operations, improved well activation project, surface facilities integrity project, dedicated pressure maintenance and polymer-surfactant injection projects.
The Impact of Oxidative and Carbonyl Stress on Cell Function: Functional Consequences for Macrophages
Authors: Kirkham Paul
Published: December 2009

There is a growing body of evidence demonstrating that products of oxidative stress,
namely carbonyl adducts, play a major role in chronic inflammation as well as age-related
diseases. Their involvement crosses a broad spectrum of medical conditions encompassing
airway diseases, such as asthma and COPD (chronic obstructive pulmonary disease) [1],
neurodegenerative disorders like alzheimers [2], the cardiovascular disease atherosclerosis [3],
and the arthritic diseases rheumatoid arthritis [4] and osteoarthritis [5]. Several good reviews
exist highlighting the importance of carbonyl adducts in disease [6-8]. Not only do carbonyl
adducts act as simple markers of tissue damage by oxidative stress, but they are able to
participate in disease pathogenesis. This is accomplished through post-translational
modification of protein, be it intra- or extra-cellular, the net effect being to alter cell function
with the eventual tissue damage that follows [9-12].
Discrete Calculus
Authors: Izadi F. A.
Published: December 2009

Firstly, we define the discrete differentiation and integration of functions and their arithmetic
properties. By using these properties, we can easily calculate many important summation formulas in
particular a closed formula for the sum of kth powers of the first n consecutive positive integers, an
expression for the discrete gamma function, as well as a formula for the number of regions in which x
hyperspaces in general position, divide the n-dimensional space Rn. It turns out that this number can
be given as a function of x expressible as a Taylor expansion at the origin. Secondly, by introducing an
analog of the exponential function, we treat the difference equations as a discrete differential equations.
For example, we solve the arithmetic progression as a first order and Fibonacci sequence as a second
order Cauchy discrete differential equation problems. Finally, in the remaining three sections, we deal
with the methods of the variation of parameters, the solution of the Cauchy problem for non-homogeneous
differential equations, as well as the boundary value problem both for homogeneous and non-homogeneous
differential equations of second order in discrete cases.
Lymphadenoma: Case Report of a Rare Salivary Gland Tumor in Childhood
Authors: Chang Kenneth T.E. , Chadha Neil K. , Leung Richard , Shago Mary , Phillips M. James , Thorner Paul S.
Published: December 2009

Lymphadenoma of the salivary gland is a rare benign tumor with only 11 reported cases in the English language literature, most of which have occurred in adults. We report a case of a lymphadenoma occurring in the parotid gland of a 15-year-old girl. The tumor was composed of variably sized cystic cavities within abundant reactive lymphoid tissue. The cystic spaces were filled with eosinophilic secretions with occasional histiocytes. Many of these features were also apparent on cytologic preparations. The cysts were lined by epithelium lacking atypia and showed luminal and abluminal differentiation both by immunohistochemistry and by electron microscopy. Tumor cells were not cycling as determined by MIB1 immunostaining, and the tumor karyotype was normal. This is only the second case to be reported in the pediatric age group. Ultrastructural features and karyotype analysis are reported for the first time. Although this tumor is rarely encountered by pediatric pathologists, awareness of its existence is important to distinguish it from possible malignant mimics, such as lymphoepithelial carcinoma and metastatic mucoepidermoid carcinoma in a lymph node.
Simultaneous determination of retinol, retinyl palmitate and β-carotene in rat serum treated with 7,12-dimethylbenz[a]anthracene and Hypericum Perforatum L. by high-performance liquid chromatography with diode-array detection
Authors: Levent Abdulkadir , Ekin Suat , Oto Gökhan
Published: December 2009

A new and simple high-performance liquid chromatography method was developed and validated for the simultaneous determination of retinol, retinyl palmitate and β-carotene in rat serum treated with Hypericum Perforatum L. and 7,12-dimethylbenz[a]anthracene. Furthermore, vitamin C was determined spectrophotometrically. High-performance liquid chromatography analysis was performed utilizing an Inertsil ODS3 reversed phase column with methanol-acetonitrile-tetrahydrofuran (65:30:5, v/v/v) as mobile phase, at a flow rate of 1.5 mL min−1 and 40°C. Diode-array detection was conducted at 325 and 450 nm for retinol and retinyl palmitate, and β-carotene, respectively with a running time of 26 min. The high-performance liquid chromatography assay and extraction procedure proposed are simple, rapid, sensitive and accurate. This method was then applied to determine the amounts of retinol, retinyl palmitate and β-carotene in rat serum. Results of this study demonstrated that at 60th day in the 7,12-dimethylbenz[a]anthracene-treated group there was a significant decrease (pa] anthracene + Hypericum Perforatum L. treated group compared to the control group..
Design of an amperometric xanthine biosensor based on a graphite transducer patterned with noble metal microparticles
Authors: Dodevska Totka , Horozova Elena , Dimcheva Nina
Published: December 2009

A mesoporous graphite material micro-structured with palladium-platinum deposits (mixed in the ratio of 70:30% Pd:Pt) has been used as a cost-effective electrode material for designing an amperometric biosensor for xanthine. The here reported biosensor shows significantly improved operational parameters as compared to previously published results. At a constant applied potential of −0.05 V (vs. Ag/AgCl) it is distinguished with enhanced selectivity of the determination: at the working potential the current from the electrochemical transformation of various electrochemically active substances usually attending biological fluids (incl. uric acid, L-ascorbic acid, glutathione and paracetamol) has been eliminated. The effect of both the temperature and buffer composition on the analytical performance of the sensor has been investigated. Under optimal operational conditions (25°C, −0.05 V vs. Ag/AgCl, phosphate buffer, pH 8.4), the following have been defined for the biosensor: sensitivity 0.39 µA µM−1, strict linearity of the response up to xanthine concentration 70 µM, detection limit of 1.5 µM (S/N=3) and a response time of at most 60 s.