bluuebunny/crossref_metadata_2025 huggingface dataset:
Low Impact Testing of Oil Field Access Roads: Reducing Environmental Impacts in Desert Ecosystems
Authors: Platt Frank Martin , Burnett David B
Published: October 2014

This project presents results from one part of the Disappearing Roads (DR), a multi-year project to design, test and evaluate multiple temporary and permanent road materials for use in harsh environmentally sensitive areas. DR is a critical component of the joint industry project Environmentally Friendly Drilling Program (EFD).

The DR project included a nationwide University competition sponsored by Halliburton to come up with potential designs as well as actual field trials of commercially available products, while the goal of the RPSEA sponsored portion of the project was to field test some of the products and designs identified in this competition.

The specific objectives of the RPSEA Project are: Identify new technology that can reduce or eliminate the impact of drilling operations on environmentally sensitive areas. Design an EFD system using most promising technology Include environmental stakeholders in the designs

After drilling operations are completed or suspended, roads are often remediated. This removal is intended to allow the recovery of the lands to a pre-use condition so as to minimize additional access. Experience has shown that such efforts pose difficulty, highlighting the complexity of potential long-term consequences of oil and gas operations. New systems have been tested to avoid this expense.

Tests have been performed in a desert environment in West Texas as well as a second test located in a moderate climate with significantly more rain to determine the optimum operational conditions for the materials used. The project evolved to include roads made from recycled well cutting, plastic composite mats and mats made from waste materials. As in all projects the viability of any method is measured by the cost and benefit relationship. If the road material reduces cost either for construction or in the case of remediation and disposal of cuttings it could be considered a success.
Composite Plug Milling Efficiency Improvement through Rheology Control - Lessons Learned from the Horizontal Completions in the Duvernay Shale
Authors: Huynh Darren , Medvedev Oleg , Hamid Saad , Anas Yossi
Published: October 2014

The Duvernay Formation in North Western Alberta holds an estimated 443 trillion cubic feet of gas and 61.7 billion barrels of oil. Horizontal wells are drilled and completed with multiple fractures to maximize the reservoir contact. The most common technique used for hydraulic fracturing in these wells is the plug n' perf method. Once the fracturing operation is completed, the plugs must be milled out using coiled tubing to restore wellbore access, as well as to put the well into production. While much emphasis is placed on improving fracture design and proppant placement in order to yield maximum production, optimizing the milling process typically focuses on mill bits, motors, and plug designs. Mill bit design and motor life have considerably improved as a result of intensive research and development in this field. New plug designs promise quick disintegration during milling. However, little attention has been directed toward understanding solids transportation and movement in the well bore. Rules of thumb are still commonly used to pump gel sweeps or determine the number of wiper trips needed when milling plugs or cleaning a well bore. As a result, current milling practices leave a significant amount of debris in the well bore, and pipe sometimes sticks due to cuttings or plug debris not transported to surface as a result of inadequate rheology. These risks not only jeopardize the safety of operations but incur extra completion costs.

In an effort to improve plug milling efficiency, a new technique was introduced during a well completion project in the Duvernay shale. The objective of this technique was to optimize the entire milling process while focusing on fluid rheology. This paper describes case histories comparing the results before and after the implementation of this innovative concept. It also outlines the benefits realized in terms of savings and the impact on project economics. The lessons learned and best practices developed during this process are shared to improve the understanding of milling process.
Deepwater Development Non-Technical Risks - Identification and Management
Authors: Reid David , Dekker Martijn , Paardekam Albert , Lewis Keith
Published: October 2014

This paper discusses the identification and management of non-technical risks for early phase, pre-sanction, deepwater oil and gas development projects. Supported by insights from global deepwater projects, the paper describes key "non-technical" issues that deepwater projects often face throughout their lifecycle, and provides a framework and process for building a deeper understanding of these non-technical issues such that they can be successfully integrated into ongoing venture management from start-up through final project sanction and beyond.

As the oil and gas industry pushes into deeper water, more complex environments and frontier unproduced plays/areas, the technical and non-technical risks related to appraisal and development of deepwater projects are likely to continue to increase substantially. While the technical challenges related to deepwater developments are significant, perhaps more significant and critical to the venture success are that the non-technical aspects of managing a new development in a frontier area are understood and incorporated at the onset.

The non-technical aspects of any deepwater venture cover and influence a vast spectrum ranging from internal organizational issues within and outside of the direct control of the project, to more broadly the external business environment which is often in flux. These wide ranging issues play critical roles is defining and affecting the stability of the project as it evolves over the typical industry 10 year+ project maturation cycle. Effective identification and management requires the venture team to:

Build a deep and robust understanding of the internal and external context for the project (technical and non-technical), Integrate all of these aspects into a credible framework within which the project can be safely and competitively delivered, Understand the interplay between project schedule and "stability" of the internal/external non-technical aspects of the venture, and, Develop appropriate risk mitigation and opportunity capture strategies for the highest impact non-technical aspects identified and play these out over the maturation of the project concept.

Based on experience, and with the help of examples, this paper discusses the criticality of non-technical issue identification and management in the formative stages of a project with the key goal of stabilizing the project and laying a solid foundation for future project decisions on route to project sanction.
Lithofacies Classification of Thin Layered Reservoirs Through the Integration of Core Data and Dielectric Dispersion Log Measurements
Authors: Pirrone M. , Battigelli A. , Ruvo L.
Published: October 2014

Distal turbidites consist of thin laminations (inch-scale) usually ranging from fine sand to clay-rich deposits and may represent major hydrocarbon reservoirs: conventionally, they are studied by means of a log-based binary modeling that discriminates productive and non-productive layers. Nevertheless, the binary model represents a major drawback when dealing with laminations in the silt grain-size range, as their allotment to either end-member can be extremely problematic.

This paper deals with a novel lithological facies classification approach that integrates core data and a high-resolution dielectric dispersion wireline log: its 1-inch vertical resolution and a related fit-for-purpose petrophysical model make the log tool's response suitable to describe the lithological heterogeneity of these reservoirs.

The approach is presented by means of a study performed on the cored section of a well drilled into a laminated gas-bearing Pleistocene reservoir in the Adriatic Basin. A core-based classification was first carried out using sedimentological descriptions, mineralogical analyses, cation exchange capacity measurements, routine and special core analyses, and a statistical investigation of grain-size distributions: this allowed the identification of four litho-facies ranging from hemipelagite to coarse silt. Next, a log-based classification was carried out with a multivariate statistical numerical technique (cluster analysis) run on the dielectric dispersion model output curves along the cored section of the well. In the end, a four-facies log-based classification was obtained that matches the core-based classification with an overall agreement in excess of 93%.

When compared to the conventional methodology, the presented approach shows the added value of identifying intermediate lithologies, thus leading to a more accurate quantification of the thickness of the potentially hydrocarbon-bearing net reservoir.
Developing an Integrated Sand Management Strategy for Kinabalu Field, Offshore Malaysia
Authors: McPhee Colin , Webster Craig , Daniels Gillian , Reed Chistopher , Mulders Frans , Howat Craig , Britton Alan
Published: October 2014

The Kinabalu oilfield is currently producing 14,000 bopd from a peak of 40,000 bopd in 1998. Present field rejuvenation plans include drilling and completing new infill and development wells from both an existing and a new platform. Most platform wells are currently producing sand and none have been completed with sand control. Sand production has caused erosion issues and lost production due to the need for regular separator clean outs, and is a key risk factor for both existing well integrity and new well completion design. A multi-disciplinary team was tasked with determining the causes of sand production, and to develop a fit for purpose sand management strategy for this mature, brownfield redevelopment.

A coupled geomechanical/sand failure model was employed to assess sand failure, and to evaluate alternatives to sand exclusion completions. The model was calibrated using existing well sand production data, then run for the proposed new wells to assess the potential for sand production over the remaining field life. The model confirmed that sand production is closely linked to reservoir depth, completion type, well inclination and, most importantly, depletion level.

An objective screening process was developed to rank sand control options. This considers existing and proposed well completion architecture, facilities design/limitations, and recognises inherent data uncertainties. The systematic sand management methodology allows a consistent, objective and transparent view of benefits and risks across the different system aspects. Key selection criteria were utilised rather than arbitrary decisions based on limited and often unaudited data. The process ensured a best practice, fit for purpose, and structured sand management solution.

In light of the currently low levels of sand production and the challenges associated with remedial or retro-fitting sand control, optimised surface sand management will continue to be the preferred solution for all existing wells.

Predicted sand production in most new wells is manageable. Some wells targeting shallower or weaker sands would normally be sand control candidates, but re-thinking the completion design, optimising surface sand management procedures, managing drawdown and BHFP levels, and taking advantage of favourable stress vectors through oriented perforation can extend the sand free well operating envelopes over life of well production and depletion conditions, reducing or deferring the need for sand control in all but the highest sanding risk reservoirs.
Increasing Oil Recovery from Long Horizontal Wells Using Advanced Lower Completion Systems
Authors: Joseph P. , Galimzyanov A. , Nazarenko P.
Published: October 2014

Horizontal openhole wells are becoming common in current field developments. The main advantage of horizontal wells is that they increase drainage area, resulting in improved recovery. However, horizontal wells produce some challenges. Frictional pressure drop from toe to heel and breakthrough anywhere in the well due to permeability variation along the horizontal section lead to water or gas coning toward the heel of the well. To manage and overcome these challenges in horizontal wells, the industry developed advanced lower completion systems.

Existing completion technologies used in these long wells are typically passive systems. These systems, which include inflow control devices (ICD) designed with torturous paths or orifices, have limited ability to manage water breakthrough that leads to lower ultimate recovery. Hydraulic systems use inflow control valves (ICV) that can be actuated from the surface. The number of available wellhead penetrations limits the number of ICVs that can be deployed within the completion string. Electric systems with multiple active flow control devices (AFCD) on a single tubing encased conductor (TEC) can address the water breakthrough issue economically in extended-reach wells. The single TEC line requires only one penetration at the tubing hanger.

This paper evaluates and compares the cumulative oil production for ICD, ICV and AFCD devices. Input data from multiple wells was used to compare the oil production of systems incorporating these devices over a period of a few years. Near-wellbore simulations and data analysis clearly show the increased oil recovery potential of using completion systems with AFCDs. This system on a single TEC can be installed to compartmentalize a long horizontal well into more than 20 isolation zones. The compartment is created by an openhole packer, and each zone typically has at least one AFCD. Each AFCD can achieve ON and OFF positions and various intermediate choking positions. Choke settings can be customized to specifications. Each AFCD can be selectively actuated to a choke position remotely from the surface to control water-producing zones.

Completion systems with AFCDs are poised to give the industry the ability to remotely control water breakthrough and optimize production in long horizontal wells. This paper shows how different types of completion technologies can help accomplish real-time wellbore equalization that leads to increased oil recovery. An intelligent completion system with these active flow control devices provides our industry complete control of a field through proactive and reactive reservoir management, increasing the ultimate recovery rates.
Effective Practices in the Abandonment of Canada's Deep Sour Gas Wells
Authors: Wilkie Arugha , Baldree Dusty , Pratt Heidi
Published: October 2014

To meet rising global energy demand, the oil and gas industry is growing at an unprecedented rate. As mature oil and gas fields reach end-of-life, safe and cost effective abandonment techniques are now and will continue to be a critical part of the industry. Ineffective abandonment methods are a serious economic and environmental liability to an operator, particularly one having wells with surface casing vent flows.

The operator's Foothills fields, located in central Alberta, Canada, are home to some of the harshest downhole producing environments in the country. Foothills wells are deep (>3500 m true vertical depth), sour (5% to 90% H2S) and mature (1947 to present) with average well reserves of over 80 million standard cubic meters of gas. They experience sulfur, iron sulfide, calcium carbonate and sodium chloride deposition. Saline water influx causes corrosion of the production tubing strings. Most of the wells have low casing cement tops leaving multiple porous geologic formations uncemented. These factors present many challenges during well abandonment operations.

A well abandonment campaign for these fields began in 2011 and will continue for many years. To date over 40 wells have been abandoned. This paper will describe best practices learned, as well as "game changing" strategies that have led to significant cost savings and reduced operational risk. These include bullheading foamed cement to abandon the producing zone prior to moving in a service rig. This is followed by a "one-trip" abandonment utilizing through-tubing perforating and bradenhead cement squeezes with high pressure, slow-rate pumpers.

The percentage of total well abandonment cost savings will be presented for each strategy. The principles for choosing cement squeeze intervals for the isolation of porous zones, and the success rates of surface casing vent flow shutoff will be discussed. This paper will also present data from cement plug drillouts which show that cement platforms are not required beneath a balanced cement plug in near vertical wellbores. These practical applications will reduce costs, lower risk exposure and lead to improved results in downhole abandonments.
Use of the DREAM Model for Control and Prediction of Concentrations and Environmental Risks Associated with Regular Discharges to Sea: Experiences and Challenges.
Authors: Rye H. , Brönner U. , Ditlevsen M. K. , Frost T. K. , Furuholt E. , Kjeilen-Eilertsen G. , Nepstad R. , Page P. , Paulsen J. E. , Ramos R. , Rønningen P. , Sørstrøm S. E.
Published: October 2014

A numerical model has been developed and applied to serve the offshore industry to predict and report environmental risks associated with offshore discharges. The development has taken place over a time period of about 20 years, and is fully financed by the offshore operators. The model is fully four-dimensional (time and 3D space variations included) and covers the water column and sediment compartments.

The model was first developed and applied to produced water discharges. Later, drilling discharges and coastal discharges (terminal releases) were included. At present, the "DREAM Charter" project focuses on revisions of the risk approach according to recent literature, validation of the numerical model by comparing with laboratory and field data, and also addresses the uncertainties in the predictions. Present participants are BP, ConocoPhillips, Det Norske, ENI, Statoil and Total.

The model tool has been applied to predict and report environmental risks associated with discharges to sea (mostly produced water and drilling discharges). A parameter, EIF (Environmental Impact Factor), has been developed and used as a measure for size of potential environmental impact. This parameter has also been used as a basis for selection of chemicals used, and to give priority to the most cost efficient measures to reduce environmental impact.

The model tool makes it possible to select the best option to reduce environmental impact in a cost efficient manner, weighting reduction of the size of the EIF against costs. The introduction of new OSPAR regulations (OSPAR, 2012) allows for an alternative approach (Whole Effluent Approach) which is discussed as well.
Completion Optimization of an Unconventional Shale Play: Implementation of a Successful Completion Design Optimization Plan and the Results
Authors: Jaripatke Omkar , Samandarli Orkhan , McDonald Beth , Richmond Perry
Published: October 2014

Success of any unconventional shale development depends heavily on the effectiveness of the completion design. Geology, lithology, and production mechanism are the key drivers that determine how prolific a shale play can be. Identification of the geological and reservoir characteristics of the shale play needs to be performed prior to optimizing the completion design. A comprehensive completion design optimization plan is then needed to effectively harness the resource-in-place. The plan needs to account for the variations in the geology, hydrocarbon types, yield, true vertical depths, etc. within the asset. An optimum completion design will be different for rocks with various geologic and reservoir properties. It is equally important to realize that different completion parameters have varying effect on the well performance and the well economics. It is a challenge for an asset team to develop an optimized completion plan by testing different completion parameters in different geological regions within an asset. Rigorous reservoir modeling and economic analysis are needed to determine the actual effect of a completion parameter on well performance. A change of a completion parameter may result in better well performance, but the net incremental cost associated with making that change might not be the best economic decision.

This paper presents the workflow, the analysis, the results and implementation of the Eagle Ford shale completion design optimization plan. It also includes the details of the reservoir and economic analysis associated with each completion parameter test. Information presented in this paper will help completion engineers and asset teams design a workflow for selecting appropriate completion design solutions of an unconventional shale reservoir.
Closed-Loop Feedback Control of Smart Wells for Production Optimization Using Downhole Measurements of Self-Potential
Authors: Ijioma Amadi , Jackson Matthew
Published: October 2014

We present a new closed-loop feedback inflow control strategy, based on downhole measurements of self-potential (SP), and quantify the benefit of this approach in preventing or minimizing water production. Previous studies have demonstrated that downhole measurements of SP in production wells, using permanently installed electrodes, can be used to monitor and image encroaching waterfronts that are tens to hundreds of meters away from an instrumented well; field trials have demonstrated that SP data acquisition is technically feasible. However, no previous studies have investigated the use of SP measurements for closed-loop inflow control of smart wells. SP signals arise naturally during production to preserve electrical neutrality when charge separation occurs due to gradients in pressure, temperature and composition (salinity) of the formation or injected brine. We use numerical modelling as a cheap alternative to field experiments, to develop a closed-loop feedback control strategy triggered by downhole measurements of SP at a production well and compare the performance with feedback inflow control strategies based on downhole watercut measurements. Inflow control is facilitated by ‘variable’ ICVs. Our results show that closed-loop, feedback control using downhole SP measurements can yield gains in well NPV when compared to inflow control based on conventional in-well data in a single smart horizontal well. Moreover, SP-based feedback control can be used to improve well NPV over uncontrolled well production when the reservoir does not behave as predicted. Gains in NPV are close to optimal. These results are significant because they suggest a new reservoir technology that can provide a simple but effective approach to production optimization using smart wells.
Designing Downhole Chemical Injection Systems
Authors: Guerra L. A. , Oliveira G. H.
Published: October 2014

The growing demand for downhole chemical injection, in addition to deeper offshore wells, brings new challenges in controlling chemical injection flow rates. The best way of facing these challenges and avoiding the known problems that spoil the efficiency of chemical injection is a proper design of injection systems.

A good design requires the modelling of the fluids physical properties, a fair estimate of the fluid temperature profile, the assessment of equipment performance and the evaluation of transient effects. Tubing pressure oscillations (caused by well production instability or natural production fluctuations) are the cause of variability in the chemical flow rate delivered downhole. On top of that, column separation, which is liquid-vapor interface established inside the chemical injection line due to very low pressures, cannot be always avoided. This phenomenon intensifies flow rate oscillations and requires additional precautions during the design phase.

Analytical models are proposed for steady-state and for transient flow of chemicals. The first, built on top of well-established models from literature, allows for an easy assessment of the fluid physical properties and the equipment design. This model highlighted a number of important points, for example, a large dependence of the fluid physical properties on pressure and temperature, in contrast to the lack of laboratory data. It has also been found that column separation may occur in more than one point, what leads to additional risk of failure. Field data have been used to illustrate the pitfalls of the injection system design and also the model accuracy. The second model allows for estimating the effects of bottom hole pressure oscillations over the chemical injection flow rate stability. It is shown that flow rate oscillations at the delivery point, if sufficiently large, may spoil all the benefits expected from chemical injection due to the alternating under and overdose.
Experimental and Numerical Studies of Reduced Fracture Conductivity due to Proppant Embedment in Shale Reservoirs
Authors: Zhang Junjing , Ouyang Liangchen , Hill A. D. , Zhu D.
Published: October 2014

Artificially created fracture networks with sufficient fracture conductivities are essential for economic production from shale reservoirs. Fracture conductivity can be significantly reduced in shale formations due to severe proppant embedment. In addition, proppant embedment induces shale flakes that migrate and clog fracture networks.

A laboratory investigation was performed to understand how excessive proppant embedment caused by the shale-water interaction impairs shale fracture conductivity. The experiments were conducted using Barnett shale samples with representative rock properties. The asperities on the fracture surface were carefully preserved. The damage process was simulated in the laboratory by flowing water through the shale fracture packed with proppants. The water used in the experiments had a similar chemical composition to flowback water in the field. The laboratory results were benchmarked with the results from an experimental study conducted with Berea sandstone samples. Post experimental analysis included microscopic imaging of the fracture surfaces and measurement of the proppant embedment depth.

A computational fluid dynamics study was conducted to quantify the conductivity loss due to proppant embedment on a theoretical basis. We developed pore-scale physical models of the proppant pack and calculated the fracture conductivity loss at different proppant embedment depths. The computation was repeated for a variety of proppant layers. The worst case assumed a 40% proppant grain volume embedment.

The experimental study showed up to 88% reduction in fracture conductivity after water flow under 4,000 psi closure stress. The conductivity loss was due to severe proppant embedment as the shale fracture face was softened after its exposure to water. Direct measurement of embedment depths indicated that for fractures that were exposed to water, the average embedment depth was about 50% of the proppant median diameter, while for fractures that were only exposed to gas, the average embedment depth was just 15% of the proppant median diameter. It was also observed that pore space of the sand grains at the outlet of the fracture was clogged by shale flakes and fragments. The computational fluid dynamics study proved that even a 10% proppant grain volume embedment can cause 45%~80% conductivity loss. With the same proppant volume loss due to embedment, the conductivity reduction was less in fractures containing multiple proppant layers than the fracture containing only one layer of proppants.
Performance Testing of a Two-stage Produced Water De-oiling System for Subsea Applications
Authors: Gul Kamran , Grave Ed , van Wingaarden Hubert , Tienhaara Mika
Published: October 2014

ExxonMobil Upstream Research Company (EMURC) conducted a comprehensive laboratory testing program of a produced water de-oiling system primarily targeted for subsea applications. The test program included performance evaluation as well as durability testing of a two-stage mixed-flow de-oiling hydrocyclone technology. The objectives of the test program were to evaluate the separation performance of two system configurations i.e. decoupled and integrated hydrocyclones stages, to understand the overall system integration effects on the performance, and to determine system sustainability to sand loading.

Subsea produced water treatment in deeper water applications requires robust, reliable and compact separation equipment. The performance testing confirmed the feasibility of a multi-stage mixed-flow hydrocyclone system for subsea applications and demonstrated that, within a given operating envelope, the system can treat challenging produced water streams with high oil-in-water (OIW) content of up to 5%, reducing it to a few hundred ppm level. In addition, the issue of turndown can be addressed by designing the de-oiling system with multiple parallel banks of liners.

The de-oiling system testing was conducted with light and heavy crude oils, of gravities of 36 °API and 19 °API respectively, to map performance characteristics of a two-stage system with the first hydrocyclone stage of bulk oil removal and the second stage of water polishing. Variations in test conditions such as the flow rate, temperature, inlet oil concentration and the reject ratios were introduced to establish optimal operating ranges for each stage as well as for the system. The performance of the decoupled and the integrated system was evaluated by determining separation efficiency break-points at different operating conditions. Accelerated sand erosion tests were performed on a dedicated sand erosion test loop to evaluate different erosion resistant coatings for hydrocyclone liners. The erosion tests helped identify a promising coating solution that can withstand continuous sand loads for long-term operations. The test program demonstrated that a two-stage mixed-flow hydrocyclone de-oiling system can meet challenging subsea produced water treatment and reinjection requirements over a wide range of operating conditions. The paper presents the key results of the overall performance tests as well as the results of sand erosion testing of the hydrocylone liners with different coatings.
Novel Processing of Electromagnetic Logging Measurements Through Metallic Casing
Authors: Gao Guozhong
Published: October 2014

This paper presents a novel method to remove the casing effects from electromagnetic (EM) logging measurements through metallic casing. After the removal of the casing effects, the measurements are exactly the same as those measured in the borehole without the casing. As a result, the data can be processed (or inverted) in the same manner as openhole EM logging data, such as the array induction and tri-axial induction measurements. The method converts data with casing effects to casing-free data via simple but efficient correction algorithms based on the measurements of the impedance of the transmitters and receivers, from which the casing effects around the transmitters and receivers can be determined. In addition, the method can be used to determine the magnetic and electric properties of the casing. In addition to single well logging, the method could be particular useful for crosswell EM survey between two cased holes which the industry has not been able to solve. One such benefit is that it could make it possible to see resistivity differences due to ongoing processes (i.e. water flooding) in a producing field. The algorithms and the physics underlying them are discussed in details. Both non-magnetic casing and magnetic casing are considered in the paper.
High-Resolution Mapping of the Distribution and Connectivity of Organic Matter in Shales
Authors: Curtis Mark E. , Goergen Eric. T. , Jernigen Jeremy D. , Sondergeld Carl H. , Rai Chandra S.
Published: October 2014

Organic matter is an important component of shale oil and gas resource plays and can have a profound effect on the properties of shale. Porosity in the organic matter provides potential storage for hydrocarbons, and depending on the connectivity of the organic matter, possible connected pathways for hydrocarbon flow. In addition, from a completions and seismic mapping perspective, the distribution of organic matter will affect the elastic properties of shale as well as the elastic anisotropy. Because of the heterogeneity of shales and micron to sub- micron size of the organic matter, mapping changes in organic distribution with sufficient resolution to capture a statistically meaningful sample of the organic matter has proven difficult. Previous work has used a combination of scanning electron microscopy (SEM) with scanning acoustic microscopy (SAM), x-ray computed tomography (XCT), or optical thin sections to map the distribution of organic matter. All these techniques have limitations in the sense that they either provide large area mapping at low resolution or small area mapping at high resolution but not large areas with high resolution. With the advent of large area ion beam milling and automated high-resolution SEM imaging and stitching, a seven order of magnitude size range can now be spanned allowing the distribution of organic matter over centimeter square areas to be mapped with nanometer resolution. Utilizing this technique, the distribution and connectivity of organic matter over extended contiguous sections of core from the Barnett and Wolfcamp Shales were mapped at one inch intervals. Variations in total organic content between cores and within the same core were measured in the lab, and these variations are compared to the SEM results. In addition, the shape and orientation of the organic matter was analyzed. These measurements aid in placing limits on the scale of variation in organic matter distribution in shale and represent the first crucial step in attempting to upscale SEM data to core petrophysical measurements and potentially to log-scale measurements.
The Use of a "Type Well" Concept Approach for Design, Feasibility, and Creation of a Technology Plan for Well Construction in a New Gulf of Mexico Deepwater Development
Authors: Grant Lisa , Japar Nor Janiah , Van Den Haak Arno
Published: October 2014

The deepwater Mars/Deimos field is located in the central region of the Gulf of Mexico (GoM) at ~3000′ water depth. Mars was discovered in 1989 and production began in 1996 from Mars A, a 24 slot tension leg platform (TLP). The deeper Deimos, with significant hydrocarbon volumes, was later discovered below the original Mars production intervals. After years of development, the shallow target horizons have been severely depleted, whereas new discovery is still at significantly higher virgin pressures.

Mars B Olympus DVA, a new 24 slot TLP, was justified following a holistic evaluation of the deeper discovery. This TLP represents the first brownfield development of a deepwater field in the GoM. The field life is ~50 years, with a development plan requiring +/- 80 independent completions across ~60 hydrocarbon horizons, extending from 10,500′ to 23,000′ true vertical depth (TVD). Due to the limited number of slots and required number of completions, each of the boreholes has to consider future utility (i.e., slot recoveries, slim-hole sidetracks, big-hole sidetracks and up-hole recompletions) as a fundamental design requirement.

The detailed well development concept design was kicked off in 2011, considering extreme design load scenarios due to more stringent regulatory and internal design mandates put in place. Previously used concept design was neither robust nor satisfy long term life requirements.

A representative "Type Well" design concept approach was developed to holistically evaluate existing technologies and equipment feasibility against the new design mandates and to identify gaps. The type wells were analyzed in extreme detail to ensure there were no design oversights and so design limit envelopes could be established. Subsequently, ~20 new technology developments ranging from a high-pressure NACE tieback system to a reverse cementing tool were identified as critical to project delivery, and a multitude of unintended consequences resulting from the new extreme well design were also identified in the process.

The following paper describes the methodology used to create these type wells and examples of technology gaps identified. It also describes the key technologies developed and the domino effect as a result of their implementation.
Mapping and Modeling Large Viscosity and Asphaltene Variations in a Reservoir Undergoing Active Biodegradation
Authors: Jackson Richard R. , Zuo Julian Y. , Agarwal Ankit , Herold Bernd , Kumar Sanjay , Santo Ilaria De , Dumont Hadrien , Ayan Cosan , Mullins Oliver C.
Published: October 2014

Viscosity is one of the key reservoir fluid properties. It plays a central role in well productivity and displacement efficiency and has a significant impact on completion strategies. Accurately assessing areal and vertical variations of viscosity will lead to more realistic reservoir simulation and optimal field development planning. Downhole fluid analysis (DFA) has successfully been used to measure the properties of reservoir fluids downhole in real time. DFA has excellent accuracy in measuring fluid gradients which in turn enable accurate thermodynamic modeling. Integration of DFA measurements with the thermodynamic modeling has increasingly been employed for evaluating important reservoir properties such as connectivity, fluid compositional and property gradients. The thermodynamic model is the only one that has been shown to treat gradients of heavy ends in all types of crude oils and at equilibrium and disequilibrium conditions. In addition, fluid viscosity depends on concentration of heavy ends that are associated with optical density measured by DFA. Therefore, mapping viscosity and optical density (heavy end content) is a new important application of DFA technology for use as assessment of reservoir architectures and a mutual consistency check of DFA measurements. In this case study, a very large monotonic variation of heavy end content and viscosity is measured. Several different stacked sands exhibit the same profiles. The crude oil at the top of the column exhibits an equilibrium distribution of heavy ends, SARA and viscosity, while the oil at the base of the oil column exhibits a gradient that is far larger than expected for equilibrium. The fluid properties including SARA contents, viscosity and optical density vary sharply with depth towards the base of the column. The origin of this variation is shown to be due to biodegradation. GC-chromatographs of the crude oils towards the top of the column appear to be rather unaltered, while the crude oils at the base of the column are missing all n-alkanes. A new model is developed that accounts for these observations that assumes biodegradation at the oil-water contact (OWC) coupled with diffusion of alkanes to the OWC. Diffusion is a slow process in a geologic time sense accounting for the lack of impact of biodegradation at the top of the column. An overall understanding of charging timing into this reservoir and expected rates of biodegradation are consistent with this model. The overall objective or providing a 1st-principles viscosity map in these stacked sand reservoirs is achieved by this modeling. Linking DFA with thermodynamic modeling along with precepts from petroleum systems modeling provides a compelling understanding of the reservoir.
Evaluation of Gas Adsorption in Marcellus Shale
Authors: Yu Wei , Sepehrnoori Kamy , Patzek Tadeusz W.
Published: October 2014

Production from shale gas reservoirs plays an important role in natural gas supply in the United States. Horizontal drilling and multi-stage hydraulic fracturing are the two key enabling technologies for the economic development of these shale gas reservoirs. It is believed that gas in shale reservoirs is mainly composed of free gas within fractures and pores and adsorbed gas in organic matter (kerogen). It is generally assumed in the literature that the monolayer Langmuir isotherm describes gas adsorption behavior in shale gas reservoirs. However, in this work, we have analyzed several experimental measurements of methane adsorption from the Marcellus Shale core samples that deviate from the Langmuir isotherm, but obey the BET (Brunauer, Emmett and Teller) isotherm. To the best of our knowledge, it is the first time to find that gas adsorption in a shale gas reservoir behaves like multilayer adsorption. Consequently, investigation of this specific gas desorption effect is important for accurate evaluation of well performance and completion effectiveness in shale gas reservoirs based on the BET isotherm. The difference in calculating original gas in place based on both isotherms is discussed. We also perform history matching with one production well from the Marcellus Shale and evaluate the contribution of gas desorption to the well's performance. History matching shows that gas adsorption obeying the BET isotherm contributes more to overall gas recovery than gas adsorption obeying Langmuir isotherm, especially early time in production. This work provides better understanding of gas desorption in shale gas reservoirs and updates our current analytical and numerical models for simulation of shale gas production.
Understanding water soluble organics in upstream production systems
Authors: Walsh John M. , Vanjo-Carnell James , Hugonin Jarid
Published: October 2014

A mathematical model has been developed which allows correlation and prediction of chemical and phase equilibrium of dissolved organic components in produced water. The model is applied primarily to prediction of results from the EPA-1664 method of analysis. The model provides a clear understanding of the contributions of dissolved organics, dispersed oil, and the effect of pH on the so-called Water Soluble Organics. This can be applied to understand the consequences of reducing temperature and pressure that typically occurs in the production train, and the increase in pH which typically accompanies release of CO2 into the gas phase. The model does not predict the formation or resolution of oil-in-water emulsions or dispersions. Those variables, important in the application of the model, are assumed to be measured or calculated and available for input into the present model. The model is also applied to sampling and analysis, which is an important part of processing produced water containing dissolved organics.

The main objective of the model is to help select better processes to remove dissolved organics, and to explain the role of sampling and analysis meeting discharge regulations. It is demonstrated that deep removal of dispersed organics can result in lowering of both total oil and grease and water soluble organics.
Impact of Polar Components on Crude Oil-Water interfacial Film Formation: A Mechanisms for Low-Salinity Waterflooding
Authors: Alvarado Vladimir , Garcia-Olvera Griselda , Hoyer Paulo , Lehmann Teresa E.
Published: October 2014

Low salinity waterflooding is a promising Improved Oil Recovery (IOR) process showing growing activity since discovery. However, incremental recovery over traditional waterflooding varies significantly. Numerous investigations have attempted to prove or disprove recovery mechanisms associated to this process. In our earlier research, we proposed that buildup of the crude oil-brine film viscoelasticity leads to suppression of trapping mechanisms during low-salinity waterflooding. We also advanced the idea that film response depends upon combined characteristics of both crude oil and water. In this paper, interfacial viscoelasticity measurements were conducted on several Wyoming crude oils as well as processed versions of the same oils with selected asphaltene content. Dual-wall ring shear rheology and pendant-drop dilational rheology were run to investigate the connection between polar content in the oil and interfacial viscoelastic response. To further investigate the connection between the interface viscoelasticity and low-salinity waterflooding mechanisms, coreflooding experiments intended to minimize geochemical events during flooding were completed using Berea sandstone. Oil recovery and pressure responses were monitored as well. Film viscoelasticity results turned out consistent with our hypothesis, namely that high content of polar components leads to high viscoelasticity of the crude oil-water interfacial film. Carefully selected coreflooding experiments were run and these results were combined with our earlier ones to unveil recovery trends. Our observations show that a good relationship exists between polar component content and interfacial viscoelasticity, and consequently with oil recovery factor, but outlying results, though favoring low-salinity waterflooding, indicate that a more complex set of interactions need to be further investigated. The conclusions of our work support an additional mechanism for low salinity waterflooding that should improve industry's ability to select candidates for this process by directing fluid-fluid characterization efforts not frequently executed at present.
Quantifying Uncertainty in Bottom-Hole Pressure Measurements Utilizing Single and Dual Gauges: A Case Study
Authors: Biswas Aakash , Al Jumah Ali , Al Joumaa Jihad , Mahdi Abdul Gaffar , Sabih Ahmed
Published: October 2014

Description

When the operator obtained the license to operate a super giant oil field, the available data was scarce and old, rendering a question on the adequacy and quality respectively. It was recognized that developing a field of this size would require an accelerated and extensive data gathering program. Thus, a campaign was started by the operator with a strong emphasis on reducing field level uncertainties. A part of the data gathered was static and flowing bottom-hole pressure surveys for all of the available wells on the field. Wireline and slick-line retrievable Quartz type single and dual pressure and temperature gauges were used to acquire numerous static and dynamic surveys at different points in time.

This data would be used for multiple purposes, including but not only limited to PPP (Pore pressure prediction), history matching of reservoir models, well modeling including inflow and outflow analysis and executing PSO (production system optimization) activities. The problem statement of this paper is to quantify uncertainty around the recoded pressure measurements. It was observed that the data recorded with those gauges are affected by some major external factors.

Significant improvements in accuracy of downhole pressure measurements over the past two decades have been made owing to the availability/introduction of high resolution, high precision gauges. However, due to the harsh environment of the wellbore that differs significantly from the laboratory's environment, a measurement difference can be noticed even when comparing two identical gauges (Kikani and Fair, 1997). Diagnostic plots of pressures recorded during RIH (run in hole) and POOH (pull out of hole) have been used to analyze the data sets available. The conclusion of the study comprises quantification of uncertainty of the pressure recordings and pressure survey recommendations to be implemented on the field during the operation. It has since been applied in the field with improvements made in enhancing data quality of pressure surveys.

Results/Conclusions

Seven surveys were evaluated to investigate the impact of these factors on the pressures recorded.. The study reveals that the resulting uncertainty is a cumulative effect of these factors and also a function of the sequence of operations whilst execution of the survey. By looking at the impact resulting out of these factors individually and cumulatively, it is possible to provide a deterministic uncertainty around the bottom-hole pressure measurements.

The significance of this uncertainty lies in the impact of this measurement differential on Well Productivity Indices, Pore pressure prediction, history matching and PSO identification. This impact varies but understanding of the same adds value in terms of understanding and predicting the field performance better.