bluuebunny/crossref_metadata_2025 huggingface dataset:
Kinetic Modeling of the In-Situ Combustion Process for Athabasca Oil Sands
Authors: Chen X. , Chen Z. , Moore R. G. , Mehta S. A. , Ursenbach M. G. , Harding T. G.
Published: June 2014

In-situ combustion (ISC) is an effective thermal recovery method that provides an important alternative to steam injection, but it has yet to be widely applied due to the complexity of the process. The modeling of ISC requires an understanding of the behavior of different physical phenomena including phase change, heat and mass transfer, and chemical reactions. Properly conducted ramped temperature oxidation (RTO) tests on crude oil provide critical parameters for modeling. In this study, the focus is to model appropriate kinetics and improve reaction models for ISC.

Different chemical reactions occur during ISC in different temperature ranges. For heavy oils and oil sands low temperature oxidation (LTO) dominates below 260°C, yielding partially oxygenated compounds and increasing the viscosity of oil, and as a result, limiting the success of the ISC process. The so-called middle temperature oxidation (MTO) region is a combination of the negative temperature gradient region (NTGR) as well as the onset of thermal decomposition and pyrolysis/cracking of the hydrocarbon phase, some or all of which may have been previously oxidized. Above 350°C, high temperature oxidation (HTO) dominates, representing the more commonly known traditional combustion region. Most of the current reaction kinetics models for ISC only focus on specific conditions such as HTO and are not able to represent the wide range of reactions that occur over a larger temperature range.

The objective of this study was to develop reaction kinetic models that can be used to describe the reactions of hydrocarbon fractions at various temperature conditions during the ISC of Athabasca bitumen. In this work, a set of improved kinetic models including LTO, MTO, and HTO reactions based on Saturates, Aromatics, Resins, and Asphaltenes (SARA) fractions in the crude oil are established. These kinetic models are used to reproduce the RTO experimental results through numerical simulation. This research will contribute to the development of more reliable numerical models that can predict ISC performance in different temperature scenarios with greater accuracy and reliability.
Development of a Microfluidic Device for Rapid Assessment of EOR Additives
Authors: Lele P. , Fadaei H. , Guerrero U. , Sinton D.
Published: June 2014

Microfluidics permits small scale economically controllable testing/analysis environments, and has been leveraged in biochemistry and the life sciences to access previously unavailable efficiencies, most notably in DNA sequencing, protein analysis, and soft material (e.g. tissues, emulsions) synthesis. Recently, these techniques have been applied to petroleum science and the results show promise. Methods have been reported in the literature for studying CO2 diffusion, investigating reservoir fluid phase behaviour, and asphaltene content measurement. These methods drastically reduce sample volume (from litres to nanolitres) and measurement time (from several hours or days to 30 minutes or less) requirements, while maintaining or increasing accuracy offered by traditional methods. In the present study, we used microfluidics to simulate the situation where emulsions form in the SAGD process in two situations; pure steam injection and steam + additives injection. Emulsions were generated in pore-scale geometries (~ 100 µm) without and with an alkaline additive. It was found that alkaline solutions produced finer emulsions (by up to nn%). A weak dependence of mean emulsion diameter on additive concentration was also observed. In addition to informing improvements to EOR, the platform may be adapted for use in studying emulsions formed during oil and gas processing as well (e.g. in valves, pumps).
Chemical Reaction Mechanisms That Govern Oxidation Rates During In-Situ Combustion and High-Pressure Air Injection
Authors: Freitag N. P.
Published: June 2014

The lack of an accurate reaction model for petroleum oxidation rates is a serious hindrance to the simulation of oil-recovery processes that involve air injection. However, the chemical literature on hydrocarbon oxidation contains many examples of possible reaction mechanisms that could serve as guides. These mechanisms were screened to identify generally accepted reaction paths that could help reveal how oxidation occurs in petroleum reservoirs.

It was found that there are at least seven groups of fundamental reactions that can seriously affect oxidation rates of crude oils. These seven reactions are as follows: two that lead to hydroperoxide formation; "branching" by hydroperoxides; two reactions governing the negative temperature coefficient region; oxidation inhibition; and at least one rate-controlling reaction at very high temperatures. Each of these groups exerts an influence within a separate, identifiable range of conditions. These reactions, and the conditions under which they become important, are outlined in this paper.

Various oxidation behaviours that have been reported for both light and heavy crude oils were then compared and aligned with the seven identified reactions. The result was a framework for selecting pseudoreactions that can facilitate the prediction of the oxidation kinetics under a wide range of oilfield conditions. Some of these pseudoreactions involve the direct representation of free radicals or other chemical intermediates, which is a departure from conventional practice for in-situ combustion simulation.

The new reaction framework is expected to serve as a reliable guide to the construction of predictive reaction models and, consequently, improved simulation of both in-situ combustion and high-pressure air injection processes.
Feasibility Study of Using Polymer to Improve SAGD Performance in Oil Sands with Top Water
Authors: Zhou Xiang , Zeng Fanhua
Published: June 2014

In western Canada, there are significant amounts of oil sands reserves that have little or no cap rock with a top water zone (Alturiki et al. 2011); because of huge heat loss, conventional SAGD process is uneconomical when it is directly applied in this type of reserves.

In this study, it is proposed that high temperature polymer can be injected into the bottom of the top water zone to establish a stable high viscosity layer in order to prevent steam from leaking to the top water zone. Lab tests were first conducted to screen the polymers. In order to select a proper polymer which was able to have stable viscosity under high temperature, viscosities of different polymers at different temperatures were measured; and concentration of the selected polymer was optimized. Then numerical simulations were performed to evaluate the feasibility of using the selected polymer to improve SAGD performance in oil sands with top water. The numerical simulation model was based on Athabasca oil sands reservoir. In this formation, the top water zone was around 94 meters, while the reservoir thickness was about 30 meters. The vertical permeability was 50 mD and 1,400 mD for the top water zone and the oil zone, respectively. And the porosity was 10% for the top water zone and 30% for the oil zone. The effect of the polymer injection strategy including the polymer injection parameters, such as polymer slug size, injection rate, injection time and well distance on the performance of SAGD process was studied.

The numerical simulation results suggested that, polymer injection was able to block the heat from leaking to the top water zone. With polymer injection, the cSOR can be reduced from 8.5 m3/m3 to 4.8 m3/m3, while for the case without top water, the cSOR was 3.8 m3/m3. This indicates that polymer injection is technically feasible to improve SAGD performance in oil sands with top water.
Effects of Pressure Decline Rate on the Post-CHOPS Cyclic Solvent Injection Process
Authors: Du Zhongwei , Zeng Fanhuz , Chan Christine
Published: June 2014

Cyclic Solvent Injection (CSI) has been proposed as a follow-up process in post-CHOPS reservoirs. The oil recovery factor, which could reach over 50% in lab-scale, is mainly attributed to solution gas drive and foamy oil flow in CSI process. It has been suggested that pressure decline rate has impact on the behavior of solution gas drive and foamy oil flow in cold heavy oil production. However, the role of pressure decline rate in the post-CHOPS CSI process production has not been studied adequately. This work was intended to evaluate the effects of pressure decline rate in CSI process under post-CHOPS reservoirs' conditions.

In this study, different pressure decline rate tests were conducted in a large cylindrical sand-pack model with a length of 30.48 and a diameter of 15.24. Single well was applied and connected with a mimic wormhole. In terms of oil recovery factor, the average recovery factor of each cycle increases with the increasing pressure decline rate. But considering the running time, the tests with smaller pressure decline rates showed better total recoveries compared with the tests with larger pressure decline rates. And the residual oil saturation pictures showed that the oil far away from the wellbore could be more easily recovered when a smaller pressure decline rate is applied. In terms of oil production rate, the CSI process production can be typically divided into two phases. In Phase 1, the production rate increases and reaches to the maximum value. In Phase 2, the production rate significantly declines. It was found that the test with a larger pressure decline rate had the higher production rate in Phase 1, while the test with the smaller pressure decline rate had the longest production time in Phase 1. The production rate hardly has dependence on the pressure decline rate in Phase 2. This indicated that for an optimized CSI process the pressure decline rate should be dynamically adjusted in order to have the best performance. The results also suggested that the minimum production pressure exists, below which no oil or marginal amount of oil was produced.
Are Existing Three Phase Relative Permeability Models Adequate in Modeling Heavy Oil WAG Processes?
Authors: Saliu Olufemi W. , Sohrabi Mehran , Shaverdi Hamidreza
Published: June 2014

Three-phase relative permeability for oil water and gas are very important input to the simulating of three phase flow processes in oil reservoirs. The existing models developed through the observation of recovery mechanisms in conventional oil, use both oil-water and oil-gas two phase relative permeability functions in generating three phase relative permeability functions. But given that the existing three phase relative permeability models were developed for conventional oil which has a different recovery mechanism from heavy oil, could they still be used in simulating three phase flow processes in heavy oil?

This paper attempts to answer this question by examining the recovery mechanism in three phase flow processes in conventional oil vis-a-vis same process in heavy oil through micro-model experiments. A Water Alternate CO2 flood of a heavy oil sample in a core flood experiment was then simulated using the existing three phase relative permeability models.

A comparison of the simulation and the core flood results shows that the existing three phase relative permeability models are inadequate in simulating three phase processes in heavy oil production. An alternative approach using an in-house three phase flow simulator was used in generating a three phase relative permeability curves was used. There is also a proposal of a new three phase relative permeability model for heavy oil. Experimental works have proved that the Water alternate Gas (WAG) flooding process is an effective enhanced oil recovery method for heavy oil production. The residual oil in a core/reservoir after a water flooding can be further reduced through a gas flooding or vice versa. A simulation of this process is very necessary for its optimization. Hence there is a need to have a robust three phase flow simulator for heavy oil.
Stochastic Life Cycle Approach to Assess Wellbore Integrity for CO2 Geological Storage
Authors: Nabih Ahmad , Chalaturnyk Richard
Published: June 2014

Storage sites associated with depleted oil and gas reservoirs may contain many abandoned wellbores in addition to potentially unidentified wellbores. These wellbores have historically variable quality and quantity of cement that will have undergone ranging degrees of degradation. Wellbore performance in a single wellbore is dependent on the wellbore events (i.e. pressure and temperature changes) that occur within the life of the wellbore (Fourmaintraux et al., 2005; Gray et al., 2007).

There is significant uncertainty surrounding the integrity of existing wellbores due to a lack of data. Successful implementation of carbon capture and storage (CCS) will depend on solving the small-scale leakage problem associated with localized flow along wellbores. Our knowledge of oil wellbore performance under different life stages of a well is still weak. Consequently, each wellbore is unique and general conclusions about well integrity are difficult to ascertain from analyzing only a single well. Each wellbore is considered as a risk and robust tools are needed to allow for the assessment of the performance for wellbores and investigate wellbore leakage mechanism.

In this paper, a full lifecycle methodology is proposed to assess wellbore integrity as a measure of the risk of leakage. The methodology identifies the key elements to model the wellbore element and incorporates the use of a statistical approach to better understand the uncertainty in the risk estimation and interaction between various parameters controlling the model.
Could VES be a part of a Hybrid Option to Recover Heavy oil in Complex Heavy oil Reservoirs
Authors: Azad M. S. , Sultan A. S. , Nuaim S. A. , Mahmoud M. A. , Hussein I. A
Published: June 2014

Heavy oil reserves accounts for more than 8 trillion barrels of the total reserve. Thermal methods such as steam flooding (SF) and its variants have been applied extensively to develop the reserves. Complex heavy oil reservoirs possess certain properties that make the steam flooding ineffective. The properties include low thickness, deeper depth and formation nature (naturally fractured carbonates). Heat losses, gravity override and channeling are the common problems associated with it. Polymer flooding (PF) is one of the major non-thermal methods employed to recover heavy oil. Higher Salinity and divalency in carbonate reservoirs restricts polymer flooding applications. Higher oil viscosity also limits its application.

In this work, we investigated the potential of viscoelastic surfactant (VES) in recovering heavy oil in complex reservoirs where steam-flooding and polymer flooding fail. VES exhibits certain unique properties which are ascertained individually. The properties include IFT reduction, viscosity, elasticity, emulsification, salinity resistance, compatibility, and thermal stability. The properties of VES extend its applicability in complex reservoirs and hybrid technique that combined the synergism of VES, P, and hot water has been investigated.

Reservoir simulation studies with 5-spot pattern have been conducted to compare the performance of Steam flood, polymer flood, and hybrid VES flooding in thin heavy oil reservoirs. Results indicated that VES could be an ideal hybrid option along with hot water to recover high viscous heavy oil in thin reservoirs.
A Domain Splitting-Based Analytical Model for Rapid Assessment of Hydro-thermo-geomechanical Responses of Large Scale Heavy Oil Reservoirs: A Steamflood Application
Authors: Koohmareh Hosseini Behrooz , Chalaturnyk Rick
Published: June 2014

For stress-sensitive heavy oil reservoirs, geomechanical responses of the reservoir are taken into account as they play an important role in the accurate simulation of all thermal recovery techniques, such as SAGD, or steamflood. However full- field numerical simulations of multi-physics processes by any coupling strategies are technically impossible with current computer CPUs. Under these conditions, analytical methods can be used as approximate techniques instead of numerical simulators, as they are much faster and yet are useful tools for preliminary forecasting and sensitivity studies. In analytical models, inclusions of all flow variables impacts into geomechanics frameworks make the equations so complex and almost impossible to solve. This paper provides a flow-based domain decomposition workflow for performing different analytical coupling schemes in different reservoir compartments.

Since the intensity and complexity of reservoir geomechanics vary over reservoir domain, one can divide the reservoir to some sub-domains and assess different geomechanical responses separately in each sub-domain. The presented analytical proxy, suggest decomposition of the whole domain in into two parts of "heated zone" and "wetted zone", for rapid assessment of geomechanics. The heat flow equation was combined with mass and momentum convective transport equations to obtain an exact approach that correlates the saturation front of injected hot water to temperature front. The frontal velocities are dynamic interfaces for compartmentalization of the domain. In the heated zone, the total induced stresses, were considered due to both temperature and pressure increase, and in the wetted (saturated) zone beyond the temperature front, at each instance the total stress induced is only a function of pressure increase, and accordingly stress and strain induced are due to isotropic unloading. This technique provides a rapid estimate of geomechanical responses (stress and strain profile) in each part of the reservoir (near field and far field).

A numerical model was built and implemented in CMG-STARS for steam-flood case to show the robustness and applicability range of the model. The results were analyzed for synthetic case single-domain model and the model sensitivity on some reservoir parameters were checked, and at the same time geomechanical responses were not neglected anywhere (near-filed and far field) in the reservoir.
Beyond Behaviour Based Safety
Authors: Bowen Mathew
Published: June 2014

Traditional Behavioural Based safety systems have been implemented in organizations and industries across the globe, with some success. Yet across organizations safety performance has reached a plateau and in many cases incidents and injuries are again on the rise. A key part of the reason is that a purely behavioural approach to safety is based on an incomplete understanding of human psychology. To truly influence people and impact on the way people behave and engage with safety processes requires a deeper understanding of the motivations that drive our behaviour and more than that, an understanding of how to influence individuals and groups toward safety.

This paper explores how current literature and research in the areas of cognitive psychology, social psychology, the psychology of change and neuroscience can add greatly to refining how we apply psychology to our safety systems, and go beyond the simple reward and punishment paradigm of behavioural based approaches. The presentation will shed light on what these theories mean for behavioural safety systems and provide safety leaders with insights to build an intrinsically motivated workforce who value safety.

The use of psychological theories and concepts can provide a wealth of opportunity for improving safety performance and culture, if we move past a purely behavioural approach to one that embraces a more broad understanding of individual and group psychology.
Exploration and Production in An Environmentally Sensitive Area - How Do We Protect the Rift Valley from Environmental Degradation and Protect Tourism?'
Authors: Ogunkoya Anthony Kunle
Published: June 2014

With oil discovery in the rift valley of East Africa, we must do everything possible to protect one of the most beautiful areas of Africa.

The rift valley apart from being a tourist mecca, it is the bread basket of East Africa.

East Africa generates more that 90% of its GDP from Tourism and Agriculture today and with oil finds in Uganda, Kenya and Tanzania, there must be regulatory frame work in place to protect the environment and make sure the farmers continue to reap the fruit of their labour and tourism continues to contribute more to the GDP of the East African Countries.

We must make sure the that exploration operations expecially seismic activities and drilling operations and design of Rigs, Production platform design, Production Infrastructures and operations must be different from business as usual.

There must be zero tolerance for pollution, flaring must be prohibited right from inception of field development, production flowlines and pipelines must be buried underground.

Hefty fines to discourage non-compliance must be included in the legal frame work.

Social responsibility and sustainability must be part of field development plan.
Gas Flaring in Nigeria; Impacts and Remedies
Authors: Abdulhakeem Salaudeen Olayinka , Chinevu Amadi
Published: June 2014

Nigeria is a country rich in oil reserve yet richer in natural gas deposits. A great percentage of this gas deposit occurs as associate gas; this raises the probability of huge quantities of associate gas being produced during oil exploration. Despite the enormous advantages of associate gas, Nigeria still flares a substantial amount of this valuable natural resources.

This paper examines the reasons behind gas flaring in Nigeria. It takes a holistic approach while discussing impacts of gas flaring. It uses a ten year gas flaring estimate by Nigeria National Petroleum Corporation to examine the impacts of gas flaring using this approach, the negative impacts of gas flaring to the environment; on infrastructure, food chain, flora and fauna, relation to global warming is examined.

While considering the economic loss due to gas flaring which includes loss in jobs at various stages of gas capture and utilization and also loss in standard of living to gas consumers, in addition negative health impacts to the oil producing communities and facility workers are examined. Finally, various options for gas utilization are considered, their feasibility (technical and economic viability), bearing in mind the peculiarity of the Nigeria oil and gas industry.
Capital Project Development in Angola – Bridging from Planning to Execution
Authors: Guimaraes Luiz , Russo Vladimir , Tosse Grete , Bosco Joao
Published: June 2014

Health, safety, environment and community (HSEC) issues affect business performance across project development. Delaying the incorporation of HSEC dialogue in the planning stages of a capital project increases the likelihood such risks will be introduced, overlooked or mismanaged. These risks, often discussed but poorly understood, can impact overall schedule and shift the project value curve.

Senior executives are increasingly vocal about the impact of environmental and social issues on their business. CEOs presenting at the last three CERAWeek conferences on insights into the energy future (and other industry events) have highlighted that maintaining a license to grow is among their top three concerns. Numerous industry studies suggest that as many as 70 per cent of major capital projects are being delayed, costing investors billions of dollars through improper allocation of capital. Recent work by Merrow1, which derives from a performance review of 130 mega oil and gas projects, indicates that only 1 in 5 projects can be deemed a success.

In advancing projects through internal stage gates, some developers in Angola are identifying, managing and mitigating environmental and social impacts as early as possible in the lifecycle of a target asset. These developers are beginning to break down siloes in technical functions (i.e., engineering, drilling, commercial, regulatory, social responsibility, legal and supply chain) as a means to embed HSEC considerations into operational routines and corporate processes.

This manuscript illustrates the parallel processing inherent in successfully embedding HSEC in risk management. Case studies features prioritization of potential HSEC liabilities to frame decisions that minimize development constraints. These prioritization and aligment strategies support decision making and management across the capital value chain. The case studies focus on two themes: An integration theme: value is created when core competencies (modelling, emergency response, stakeholder engagement and regulatory planning) align and content developed for one stream informs and calibrates risk management for the overall program (Statoil Angola);A bridging theme: an EPC sets the tone for sustainability by accounting for HSEC challenges in developing an environmental management framework for the operational phase of an energy project (Odebrecht Infrastructure – AH Cambambe, Angola).
Impact of ISO 14001 Certification in the Transformation of HSE Management in Oil and Gas Industry in Africa
Authors: Mustapha Adetoun , Ezenwaka Israel , Amadi Amadi
Published: June 2014

The 1992 United Nations Conference on Environment and Development (the Earth Summit) recognized the need for businesses to invest in environmental stewardship beyond regulatory requirements. In response to this, the International Standard Organization (ISO) a non-governmental organization that formulates technical and management standards, introduced the ISO 14001 environmental standards in 1995. As at 2013, ISO had 164 members, each representing a country with about 22% from Africa. The ISO 14001 standard requires participants to establish Environmental Management System (EMS) that is verifiable externally. Participants are required to pass an initial certification audit and subsequent annual recertification audits conducted by approved and accredited third-party organizations.

In 1996, Shell committed to external certification of its EMS, initially with EC EMAS (Eco-Management and Audit Scheme) and later with ISO 14001 EMS. Shell in Nigeria developed a phased approach to ISO 14001 certification of its operations, starting with the Alakiri Gas and Oil production facilities in 1997, with the goal to maintain transparency, demonstrate visibility and leadership commitment to continuous improvement in environmental performance.

This paper reviews the value added and lessons learnt from ISO 14001 implementation in Shell Nigeria. It assesses the company environmental performance prior to certification and 15years after, and the overall impact on Health Safety and Environment (HSE) management. Also, it takes a look at how ISO 14001 impacts management of HSE across the industry in Africa and discusses the challenges and opportunities offered by voluntary environmental governance vis-à-vis effectiveness of traditional style of government regulation and compliance driven approach.
Educating Youth in the Fight against HIV/AIDS: A Case Study from Africa
Authors: Muogbo Uche Yvonne , Barnier Muriel , Okorocha Uche , Stott ML
Published: June 2014

The World Health Organization reports that young people account for 40% of all new infections with the human immunodeficiency virus (HIV), that globally an estimated 4.6 million youth are living with HIV, and that 69% of all people living with HIV are in Sub-Saharan Africa. Educating youth and raising awareness is an effective way to combat the spread of this disease.

In 2008, an oilfield services company launched HSE for Youth, an initiative that reaches out to young people to inform and empower them to make responsible decisions about health, safety, and environmental (HSE) topics. A key health-related topic of the initiative is raising HIV/AIDS awareness.

HSE for Youth has implemented educational workshops on HIV/AIDS in Africa. The workshops are led by trained volunteers using age-specific materials. Awareness on this health issue is raised through interaction at the workshops and the young people in attendance are encouraged to share what they learn with their peers and families. Several thousand youth have participated in the workshops throughout the region since the program's inception.
Nonempirical Apparent Permeability of Shale
Authors: Singh H. , Javadpour F. , Ettehadtavakkol A. , Darabi H.
Published: June 2014

Physics of fluid flow in shale reservoirs cannot be predicted from standard flow or mass-transfer models because of the presence of nanopores, ranging in size from one to hundreds of nanometers, in shales. Conventional continuum-flow equations, such as Darcy's law, greatly underestimate the fluid-flow rate when applied to nanopore-bearing shale reservoirs. As a result of the existence of nanopores in shales, the molecular mean free path becomes comparable with the characteristic geometric scale, and we hypothesize that under this condition, Knudsen diffusion, in addition to correction for the slip boundary condition, becomes the dominant mechanism. Recently, a few models have been developed that use various empirical parameters to account for these modifications (Javadpour 2009; Civan 2010; Darabi et al. 2012). This paper aims to provide a different approach to modeling apparent permeability in shale reservoirs. The proposed model is analytical, free of any empirical coefficients, and has been derived without invoking the assumption of slip flow at the pore wall. Our model of apparent permeability represented by a single analytical equation, depends only on pore size, pore geometry, temperature, gas properties, and average reservoir pressure. The proposed model is valid for Knudsen numbers less than unity and it stands up under the complete operating conditions of a shale reservoir. Our model reasonably predicts results as reported by other models. Finally, the model shows that pore-surface roughness and mineralogy have a negligible influence on gas-flow rate, whereas pore geometry and pore size play a significant role in the proportion of diffusion in total flow rate. Our study shows that a combination of Darcy flow and Knudsen flow—ignoring the Klinkenberg effect—can describe gas flow for a range of Knudsen flow applicable to a shale-gas system.
Improving Driving Safety: Case Study of a Dedicated Journey Management Center for the Sub-Saharan Africa Region
Authors: Etendi Daniel Abuy , Zidan Ahmed
Published: June 2014

The Oil and Gas Producers Association (OGP) reports that driving-related incidents are the highest cause of fatalities in its member company operations and the members have indicated that lack of compliance to international driving standards is one of the most common factors contributing to road traffic incidents.

To address this concern, an oilfield service company has established a global journey management center (GJMC) covering its key operational regions.

Journey management had been part of the company's driving safety program since 1998, with local journey management centers (JMCs) established in countries worldwide. The new centralized approach consolidated local centers, helping to improve driving safety through improved compliance verification, real-time tracking, and data analysis services.

The GJMC approach employs trained operators in a central office to ensure that every trip is in full compliance to the company's journey management standards throughout the driver's entire journey—with higher-risk driving locations having more strict controls and standards. Site-specific journey management procedures are defined, and the GJMC team monitors drivers' adherence to the journey management plan and intervenes in real-time, as required, to improve driving behavior.

This paper describes how the company developed a GJMC for the Sub-Saharan Africa region. It serves 14 countries in this region in 5 languages; interacts with more than 1, 200 drivers; and controls an average of 350 field trips per day.

The paper discusses how the centralized approach across the Sub-Saharan Africa region has proven effective in increasing drivers' compliance to the company's journey standards. In addition, data analysis by a dedicated team allows for detailed insight into driving safety trends. By defining, measuring, and shaping driving behaviors, the GJMC for the Sub-Saharan Africa region plays a key role to continuously improve drivers' performance and safety.
Water - Chemical Treatment and Management
Authors: Wiggett Adrian J.
Published: June 2014

Recycling produced water for re-use in gas and oil fields for hydraulic fracturing and re-injection to maintain reservoir pressure is becoming increasingly important due to the scarcity of this natural resource. This is especially the case when these activities are not near a readily available source of ‘free water’ such as seawater or an aquifer.

This paper considers ways to use water management to lower operational expenditures OPEX by eliminating freshwater sourcing, transportation, storage and its treatment as well as the storage, transportation, treatment and disposal of produced or flow-back water.

The water management approach enables operators to re-use produced waters in hydraulic fracturing fluids. Pretreatment testing and analysis characterizes the chemistry of the water to ensure an effective fracturing fluid design and to determine the appropriate water treatment solution for every application. By using a comprehensive water treatment suite of technologies, we demonstrate that virtually any oilfield water can be treated. Posttreatment testing confirms the water meets the customer's specific requirements.

Integrating water management service technical expertise with water chemistry and chemical treatments maximizes hydrocarbon production, minimizes reservoir damage, and reduces the costs of freshwater sourcing by as much as 90%. The techniques also offer real routes for oil operators to meet regulatory requirements, mitigating environmental impact.
Environmentally Sustainable Water Management for Mature Oil Fields: A Case Study for Karakus Field, Adiyaman - Turkey
Authors: Ergun Ender , Ercelebi Ali Emre , Sahin Mehmet Oguz
Published: June 2014

Water management is playing significant role in surface oil-water treatments as well as oil production. Sector employees are tackling with huge amount of disposal water because of producing approximately three barrels water in order to have one barrel hydrocarbon. Although process of water management has some negatively impact on environment, these detrimental effects can be reduced sharply with technically solutions.

In mature Karakus oil production field, there have been done some treatments and researches for reach most efficient water management operations to get rid of 96 percent waste water. Firstly, more than half of disposal water slightly 30,000 bbl/day is injected via free water knock outs (FWKO). By increments of pressure, better oil quality and recovery (100 bbl/month) are obtained as a field experience (SPE 164313), as a result, declines in electricity consumption (237,000 kWh/month), preventing 369,000 lb-CO2 emission then by preventing loss of oil, 900 bbl/month and not emitting 60,000 lb-CO2 equivalent to reproduce. After operating FWKO, 85 percent decrease of corrosion rate has dramatically reduce the oil spills into farms. Secondly, in the wash tank, light oil is recovered (1500 gal/month) by means of condensing unit and not emitting 2,400 lb-CO2 emission to reproduce oil. Thirdly electric motors that used in water injection pumps are replaced with highly efficient ones and 16,000 kWh/m energy is (preventing 25,000 lb-CO2 emission) saved. Not only environmentally oil water separation but also hot disposal water (~230 °F) is used with heat exchangers for heat the greenhouse. This is heated without any necessity burning fuel. Addition to emissions, instead of steel pipeline fiberglass is operated for injection line to reduce dramatically the friction loss with decreasing electricity consumption (95,760 kWh/month) so preventing to emit the 149,000 lb-CO2 equivalent and subsequently cease to be a threat to corrosion effects. Therefore, disposal water has never spilled into the farms.

Consequently, this study explains that how to operate environmentally oil water treatments at mature fields, with using the FWKO, condensing unit, fiberglass pipeline, water pumping system improvements. Challenges with more than 90 percent of water, Karakus Fields, are managed accomplishedly with these methods and treatments.
A Productive Technique to do Drilling Analysis and Risk Assessment
Authors: Sidaoui Ziad , Siddiqui Mohammed Abdul , Aldawood Jahad
Published: June 2014

There are always challenges associated with drilling and therefore continuous improvement of drilling programs to be in accordance with proper geological and petroleum fluids conditions is critical. Failure to do so may cause unplanned operational time also known as Non-Productive Time (NPT). Time lost during drilling in the form of NPT is a great ordeal of oil companies causes of which include equipment failure, stuck pipe or even poor decision making to mention a few. Hence, study of NPT and making risk registers for individual wells and sections drilled in a particular reservoir or field can aid in future drilling operations by lowering the severity and also reducing the probability of those NPT incidents.

The objective of this paper is to study and analyze the different drilling activities extracted from the Saudi Aramco Drilling Knowledge (SADK) database to identify the critical mistakes occurring during drilling so that they can be avoided in future drilling operations making the drilling program more enhanced and efficient. This was achieved by adopting an innovative way of benchmarking wells, creating drilling activity charts and risk registers.

The paper is supported by an actual case study from fifteen wells in Manifa field drilled during the field development plan of Manifa oilfield. Manifa field is located offshore and many problems were faced during the drilling activities and most of those problems were unexpected.

The results of analysis revealed that the major problems causing NPT are well control, stuck pipe and bottom-hole problems. The mitigation of such risks or problems is also presented in this paper.
The Caddo Oil- and Gas-Field, Louisiana
Authors: Hopper Walter E.
Published: June 2014

Location Extent

The Caddo oil-field, shown in Fig. 1, is located in Caddo parish, northwestern Louisiana. The known producing territory of oil is covered bytownships 19 N, 20 N, 21 N, 22 N, and ranges 15 and 16 W., shown in Fig. 2. Thecenter of the field may be taken as Oil City, 24 miles north of Shreveport, onthe Kansas City Southern railway. Shreveport is the second largest city in theState, and is the connecting point of five railroad-lines. Drilling at thepresent time, however, is going on all over northern Louisiana, especially inCaddo and the neigh-boring parishes. During the winter of 1908–09 I spent'four months in the Caddo field, under the direction of the LouisianaGeological Survey and the U.S. Geological Survey.

History and Development

Natural gas escaping at the surface is found at numerous places innorthwestern Louisiana. At Shreveport, the plant of the Shreveport Ice & Refrigerating Co. has been lighted by natural gas for 20 years. The well wasdrilled for water, but was abandoned on account of the gas. A test well, putdown in 1905 near the western limits of Shreveport, was driven to 1,650 ft., and encountered indications of gas and oil at various depths, but did notsucceed in finding enough to be profitable. Attention was first attracted tothe Caddo field in 1895 by indications in water-wells from 40 to 60 ft. deep, in which the pressure of natural gas was noticeable. This indication of gas ina shallow well led to the drilling of the first well in the Caddo field, theold Savage Brothers &Morricell, or the Caddo Lake Oil and Pipe Line No. 1.The rig for this well was erected in May, 1904, and drilling began in June,1904. The well was bailed Mar. 23, 1905, with a small amount of oil. It wasdeepened July, 1905, and converted into a "gasser" Jan. 3, 1906. It wasabandoned January, 1907.

In consequence of the finding of oil in the Savage well, drilling operationswere pushed with energy; and in April, 1905, four wells mere drilling. Greattrouble was experienced with gas blow-outs and several of the rigs were shutdown. Difficulty in obtaining wood for fuel during bad weather led to theabandoning, so far as oil was concerned, of the Producers' No. 1 which was thenused to supply fuel gas to the various drilling-rigs in the field.

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Water Intrusion and Methods of Prevention in California Oil Fields
Authors: Oatman Franklyn W.
Published: June 2014

In order that the conditions which obtain in an oil well may be readilyunderstood, a brief description of a typical California well and a number ofthe phenomena accompanying same will be given. That the necessity for theexclusion of water be realized, the effects of water intrusion, a descriptionof methods of prevention, and a discussion of causes of failure will bepresented, followed by a summary and recommendations.

Fig. 1 shows a section of a typical well which illustrates the relation of oilsands to overlying strata. It indicates a deep water sand separated from theoil sand by shale, and the proper place for the final shutting off of water. Inthis well a comparatively thick stratum of compact shale protected the oil fromoverlying water so that the operation of landing the water string was a simplematter. In some wells the protecting stratum maybe only from 3 to 5 ft. thickand very careful operation is necessary in order to land the water string ofcasing properly and not puncture through to the oil sand. The cases just citedare common, but occasionally, after excluding overlying water, productive oilsands are drilled through in the expectation of finding more productiveunderlying sand, and a water-bearing stratum is tapped. In this case theproblem is the reverse of the normal; water must be prevented from ascendingrather than descending.

A discussion of well-drilling methods is not within the scope of this paper, except such operations as pertain to shutting off of water. A brief outline ofthe several conditions which may accompany drilling follows. Some or all may bepresent in any particular case. The direct relation of these to prevention ofintrusion will be discussed in detail further on.

In drilling, the hole becomes more or less irregular in shape, and rough, andas the casing follows the bit into the well it does not fit snugly against thewalls. As a result, water may descend between the casing and walls of the well.If a circulation pump is not used during drilling, the hole is simply punchedthrough and the pulverized material removed from the well by means of a bailer.If circulation is maintained there is a continual flow of water down inside thecasing and up around the outside between the pipe and the walls of hole. Thiskeeps an open space around the pipe.

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The Killing of the Burning Gas Well in the Caddo Oil Field, Louisiana
Authors: Keen C.D.
Published: June 2014

In the latter part of the summer of 1913 the Conservation Com- mission ofthe State of Louisiana, under presidency of M: L. Alexander, decided to stopthe waste of natural gas going on at the "burning gas- well," Locatedabout 2 mile southeast of Oil City, La. On several occasions, both innewspapers and in reports, comment had been made on the condition of this well, its harmful effect on the Caddo gas field, and the considerable loss, estimatedat several thousand dollars each month, caused by the escape of the valuablefuel., But nothing had been done to bring the well under control and preventfurther waste of gas until the State Conservation Commission took the matter inhand.

The gas fields of Louisiana are among the greatest in the country. So far mostof the gas has been found in the Caddo field proper, although considerabledevelopment has been done in and around the city of Shreveport and near thetown of Mansfield in DeSoto parish. To ex- tend the life of the gas fields andto prevent the quick exhaustion of the supply of the natural fuel are mattersof vital importance for this section of the country.

Four gas companies have entered the Caddo field and supply the surroundingtowns and cities with gas. The Arkansas Natural Gas Co. has pipe lines toLittle Rock, Ark., and supplies gas to the following cities and towns in thatState: Texarkana, Hope, Garland, Emmet, Prescott, Boughton, Beirne, Gurdon, Arkadelphia, Gum Springs, Malvern, Donaldson, Gifford, Perla, Beaton, Beauxite, Mabelvale, Bryant, Sheridan, Pine Bluff, Little Rock, Argenta, Pulaski Heights, and Hot Springs. The Southwestern Gas &Electric Co. transports gas toMooringsport, Blanchard, Caddo, Rodessa, Oil City, Vivian, Bloomburg, Hosston, Ida, Dixie, Belcher, and Shreveport. The Marshall Gas Co. supplies gas to thetown of Marshall, Texas. The Louisiana Co. has a line to Shreveport.

In the oil field the gas is used for drilling purposes, and the operatorseither have their own gas system or buy from the gas companies.

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Chlorides in Oil-Field Waters
Authors: Washburne C.W.
Published: June 2014

The waters of many oil fields have been regarded as buried sea water whichhas been retained in the sediments since the time of their deposition. Thepreservation of connate water through geological time has seemed improbable toonly a few geologists, but there is room for doubt that buried sea water couldremain in the strata during their periods of deformation and during the manysubsequent epochs of the circulation of meteoric ground-water. Some have evensuggested that the calcium chloride water in the deep mines of the LakeSuperior region is ancient sea water buried in the Algonkian lavas, but it ishard to understand how such water could be derived from the highly sodic andsulphatic water of the sea. It would seem more plausible to connect the calciumchloride with the highly calcic magmas of the greenstones in which it isfound.

Chemical analyses of waters associated, with oil differ widely from thecomposition of sea water, requiring extensive alteration of the latter, if theformer is truly its derivative. The first notable difference is the generalabsence of sulphates from oil-field waters, but this has been explainedsatisfactorily through reduction by hydrocarbons and organic matter. Oilreduces sulphates with the production of hydrogen sulphide (or sulphur), water, and carbonates (or carbon dioxide).

The second striking difference is in the high ratio of chlorine to sodium. Anexamination of the analyses of chloride waters from oil fields shows that theycontain a large relative excess of chlorine over that in sea water. Moreover, there is difficulty in finding chemical reactions that are probable in nature, by which sea water could be converted into anything like the chloride waters ofoil fields. In the latter a large part of the chlorine occurs as calcium andmagnesium chloride. This condition might be produced by the removal of sodiumcarbonate, which, however, cannot be precipitated in the presence of muchcalcium or magnesium.

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