bluuebunny/crossref_metadata_2025 huggingface dataset:
Injection and Remote Real-Time Monitoring: Slurry Injection Case Study, Onshore USA
Authors: Guo Y. , Mohamed I. M. , Abou-Sayed O. , Abou-Sayed A.
Published: October 2017

Remote life monitoring of field operations, such as injection, has been very restricted although real-time data is often collected at field sites. The difficulties lie in the data access and limitations to obtain computing resources for data analysis, which restricts the engineers' abilities to provide useful and timely remote assessment and assurance to the operations. Cloud computing combined with web-based apps, however, makes it much easier and cheaper to remotely monitor field operations and parameters in real-time from anywhere around world.

The current work provides our first attempt to apply the cloud computing and web-powered apps to monitor slurry injection at one injection site in Texas, USA. The site provides real-time injection data including flow rate and surface treating pressure, as it is recorded and stored automatically in a cloud database. The data can then be accessed and analyzed through a web-based app from any web-enabled device. Monitored injection pressure and rate, provide the basis for pressure fall off analysis to evaluate injection formation pressure and stress change, estimate fracture skin, and determine injection-induced fracture geometry at the end of each slurry injection batch. If the fall off analysis yields an unanticipated fracture geometry, advanced fracture simulations would be conducted to model fracture growth in three-dimensions under real injection conditions in order to gain a better understanding of the effects of a specific injection on fracture geometry.

The real-time monitoring of the slurry injection is a critical component for the long-term assurance of fracture containment and injection well integrity. The results of remote real-time data analysis set up early warnings to alert both onsite and offsite staff ahead of operational upsets. The analyses are also critical to optimize injection parameters, maximize injectivity, extend well life and minimize risks of creating unexpected fractures.

Compared to traditional desktop applications and isolated local data servers, cloud computing and web-based apps provide a more convenient and cost-effective way to monitor field operations in real-time. The technique and workflow presented here may be also applicable to monitor other field operations, such as drilling, water injection and production.
Gas Injection for GOM Deepwater Wilcox Trend Fields Development: Challenges and Recovery Potential
Authors: Oghena Andrew , Zhou Dengen , Fitzmorris Robert , Chawathe Adwait , Colina Julio De , Orribo Jose , Gentry Michael
Published: October 2017

Huge oil resources have been discovered in the Wilcox Trend fields of Deepwater Gulf of Mexico (GOM). The Wilcox Trend fields are ultra-high pressure and high temperature, highly undersaturated, low permeability reservoirs typically with moderate to high oil viscosities. As a result of the unfavorable rock and fluid properties coupled with anticipated large well spacing due to high well cost, the estimated primary recovery factor with artificial lift is on the order of 10 – 15%. Incremental recovery factors from water injection are forecast from 2 – 5% due to anticipated limited injectivity increasing the total oil recovery factor (primary plus secondary) to 12 – 20%. Miscible gas was thoroughly studied to determine if it could significantly increase the oil recovery factors forecast for secondary recovery.

We have carried out detailed miscible gas injection studies for six Wilcox Trend fields. Results from these field case studies demonstrate that miscible gas injection has the potential to increase the total oil recovery factor to 15 – 25% or 5 – 10% incremental above that forecast for primary depletion with artificial lift. The increase in the oil recovery from gas injection is from the improved reservoir processing rates and high local recovery efficiency of miscible displacement processes. In addition, the increase in oil recovery is due to higher oil production rates because of gas injection supporting reservoir pressure and providing natural gas lift. The GOM Wilcox field gas injection displacement process will be implemented as a secondary recovery process (before waterflood) rather than tertiary method (after waterflood).

This paper will report a new systematic workflow for integrating ultra-high pressure laboratory PVT and slim tube data and high resolution mega static earth-models into compositional reservoir simulation models for assessing gas injection displacement processes in these reservoirs. Wilcox reservoir simulation performance results will be presented for primary depletion with artificial lift, water flooding, gas injection, and gas followed by water injection and vice versa. The major uncertainties and their effect on incremental oil recovery from gas injection, resolutions to barriers to Deepwater gas injection projects, and key enabling technology developments for the ultra-high pressure miscible gas injection process will be discussed. We will end our presentation with a description of future plans for a number of GOM Deepwater Wilcox trend fields under consideration for gas injection development.
Production Optimization of Shenzi Field in the Deepwater Gulf of Mexico
Authors: Ashton P. , Cooper D. , Akajagbor C. , Politte J. , Lo S.
Published: October 2017

A 20% increase in production rate was achieved through a production optimization program in the Shenzi field in the deepwater Gulf of Mexico at little to no cost. The Shenzi Field lies approximately 120 miles from the Louisiana coast in the Gulf of Mexico. It was discovered in 2002 and first oil was produced in 2009 from the Shenzi TLP.

In 2012, the production engineering, surface engineering and operations teams initiated a production optimization program to maximize the production from existing well stock. Production optimization was achieved through a number of key activities including: advances in asphaltene management, gas lift and well configuration optimization, minimum bottom hole pressure reduction and deferral reduction.

Using integrated production modelling as the primary evaluation tool, each opportunity was evaluated technically and economically. Asphaltene management was improved through real time detection of asphaltene deposition, which allowed adjustment on inhibitor rates to reduce cost and timely treatments. Automatic well configuration modelling allowed for optimized production scenarios and gaslift injection rates. Validating completion limits ensured drawdown on wells were maximized. Development of more efficient well test programs ensured accurate well data while reducing deferrals. Field production was increased by 20% by executing these activities for minimal additional cost.

This paper summarizes a novel use of integrated production modelling techniques in real time in order to evaluate and implement key optimization activities. A variety of data will be presented including the identification of opportunities using modelling outcomes, optimization process and production improvement realized.
Design and Operational Experience with Horizontal Steam Injectors in Kern River Field, California, USA
Authors: Buell R. S. , Gurton R. , Sims J. , Wells M. , Adnyana G. P. , Shirdel M. , Muharam C. , Gorham T. , Riege E. , Dulac G. B.
Published: October 2017

A horizontal steam injection pilot project has been underway for the last four years in the Kern River heavy oil field located in the southern San Joaquin Valley of California. This pilot project was designed to address the following four prioritized learning objectives for horizontal steam injection in a mobile heavy oil reservoir, which were:What is the mechanical reliability and operability of horizontal steam injectors?Can acceptable steam conformance control along the horizontal section be achieved?Can steam conformance along the horizontal section be quantified with surveillance?What is the reservoir response and longer-term operability with horizontal steam injection?

The 12-acre pilot area on the northwest flank of section 24 of the Kern River field was equipped with two horizontal steam injectors and nine vertical producing wells. The pilot area also had 12 vertical temperature observation wells (TOW) to understand steam conformance around each of the injectors and in the far-field reservoir. The TOWs were logged frequently to establish temperature trends. Based upon temperature trends steam identification and saturation logs were also acquired periodically.

Five injector completions of increasing complexity were installed to understand the injectors' mechanical integrity, recovery of flow control devices, performance of isolation packers and fiber optic surveillance systems. A history-matched reservoir simulation model with coupled wellbore hydraulics was used for forecasting throughout the project life to conduct operational sensitivity analysis and to improve reservoir characterization. Fiber optic flow profiling methods were developed in the injectors that were validated with the observation wells and reservoir models. During each workover torque and drag measurements were acquired which were analyzed with both soft and stiff string analysis to understand wellbore mechanical conditions in the horizontal section. After each workover, all available reservoir and workover surveillance data, TOW logs and production and injection well information were used in a multidisciplinary review to understand progress against the four prioritized learning objectives. The performance of offsetting traditional, vertical steamflood developments were also evaluated.
Chemical Flooding in Low Permeability Carbonate Rocks
Authors: Ghosh Pinaki , Sharma Himanshu , Mohanty Kishore K.
Published: October 2017

Waterflood in low permeability carbonate reservoirs (<50 mD) leaves behind a substantial amount of oil. Alkali-surfactant-polymer (ASP) floods can improve oil recovery from these reservoirs by lowering the interfacial tension (IFT); however, there are several challenges such as polymer injectivity, divalent ions, geochemical interactions, pore-scale heterogeneity, and oil-/mixed-wettability. This paper addresses the first two challenges: polymer transport in low permeability carbonate cores and surfactant interaction with formation brine during ASP floods. Since polymer injection in low permeability carbonate cores is challenging, polymer transport in low permeability carbonate cores was studied. Shearing of high molecular weight polymers and successive filtration treatment were performed to reduce the polymer size distribution. Single phase polymer corefloods were performed to study the transport of treated polymers and identify the optimum pretreatment. Phase behavior experiments and aqueous stability experiments were performed to develop ultralow IFT surfactant formulations with a reservoir crude oil. ASP corefloods were performed in oil-wet low permeability limestone rocks. The oil recovery, pressure drop, effluent ionic composition, effluent viscosity and effluent surfactant concentrations were measured. Polymer hydrodynamic radius must be much smaller than the pore throat radii for the polymers to be transported. Mercury porosimetry data should be studied before polymer selection. Shearing and successive filtration can be used to reduce the hydrodynamic radii of polymers. This preprocessing worked with the HPAM polymer used in this study for the Edwards Yellow Limestone, but not for Texas Cream Limestone. An ultralow IFT ASP formulation can be developed with a formation brine with a significant amount of divalent ions by using a chelating agent. Tertiary ASP injection increased the cumulative oil production to 77% in a field core and 87% in an outcrop core. The adsorption of the anionic surfactants was limited to 0.4 mg/gm of rock in the core floods. UTCHEM simulations showed good agreement with lab coreflood experiments.
Eliminate Decision Bias in Facilities Planning
Authors: Cristea Z. , Cristea T.
Published: October 2017

The paper asserts that traditional Facilities planning methodologies, heavily based on Design Basis documents and biased towards the ‘most conservative conditions’, fail to recognize the entirety of operational conditions throughout the oilfield lifecycle, leading to significant residual risk and the wastage of resources in the Operations stage. An integrated stochastic approach is proposed, accounting for both subsurface and surface uncertainties and their interrelations throughout the field life. A practical example is also provided.

The proposed methodology employs Big Data algorithms to quantify subsurface and surface uncertainties and produce Probability Distribution Functions (PDF) for all relevant variables. Data sources are diverse, normally available in a project team, and may include geological and reservoir models and production forecasts, PVT reports, nodal and network analyses, and environmental databases. The relevant variables are expected to change throughout field life with different levels of uncertainty, due to planned and unplanned events such as condensate banking, lean gas injection for pressure maintenance, water breakthrough, etc. Stochastic algorithms (e.g. Monte Carlo method) are then applied on the deterministic model, randomly sampling from the previously defined probability distributions. Results are summarized as Tornado charts and spider or scatter plots, which are then used to analyze the most relevant variables and correlations affecting the objective function.

The provided example results indicate the risk is still present in 9% of cases for the original, deterministic design. Furthermore, resources are wasted in 76% of cases. In the integrated stochastic design the risks and wastage are reduced down to a range of 0 to 1%. The associated OPEX components are reduced from USD 3 mln to USD 1 mln (-66%), expressed in Present Value terms. An unquantified increase in system availability is also noted.

The paper demonstrates the utility of integrated, stochastic approach in Facilities planning, accounting for both subsurface and surface uncertainties and their interrelations throughout the field’s life. This approach eliminates the Design Basis induced bias and enables superior decisions at Project and Asset levels. The proposed approach is scalable, transferable to other oilfield challenges, and it is suited to multidisciplinary work environments.
Multiscale Modeling of Shale Apparent Permeability: An Integrated Study of Molecular Dynamics and Pore Network Model
Authors: Wang Sen , Feng Qihong , Javadpour Farzam , Zha Ming , Cui Ronghao
Published: October 2017

The physics of gas transport through shale systems is still ambiguous, even though several theoretical and experimental works have been reported. Most of the existing studies only concentrate on the permeability of shale kerogen. However, shales are composed of various amounts of organic matter and inorganic minerals (e.g., calcite, clay, and etc.). Inorganic pores could be larger than organic pores, hence, affect apparent permeability.

To accurately predict shale apparent permeability, we couple molecular dynamics (MD) and a pore network model (PNM) to develop a multiscale framework for gas flow through shales. First, we use non-equilibrium MD to study the pressure-driven flow behavior of methane through organic, calcite, and clay (montmorillonite) nanopores under subsurface conditions, from which we build modified Hagen-Poiseuille equations to characterize the overall conductivity of each pore. Then we incorporate these formulations into a shale pore network model, in which the impact of shale composition and bimodal pore size distribution (PSD) are taken into account.

Molecular dynamics simulations show that the streaming velocity of supercritical methane in an organic nanopore exceeds the prediction of Hagen-Poiseuille equation by orders of magnitude. However, methane exhibits a slightly enhanced flow in comparison to Hagen-Poiseuille equation in inorganic pores, which can even be ignored if the diameter of inorganic pore is larger than 10 nm. On the basis of these simulation results, we modify Hagen-Poiseuille equation to estimate hydraulic conductivity of methane through nanopores with different material types. We construct the multiscale pore network model conditioned to total organic carbon (TOC) and mineralogical composition. The pore/throat size ranging from nanometer to micrometer scales are assigned according to the pore size distributions in organic matter and inorganic matrix separated from nitrogen adsorption results. We validate our PNM model results with experimental data published in literature. We conclude that the pores located within inorganic matrix show a more pronounced effect on the shale apparent permeability than those associated with kerogen. We further examine the influence of TOC, pore network connectivity, mean pore size, and etc.

Using molecular dynamics and pore network model, this work presents a multiscale framework that accounts for distinct pore size distributions and fluid transport properties in organic matter and inorganic matrix. In comparison with previous methods, our proposed model highlights the effect of inorganic matrix owing to their greater pore sizes. This work provides an efficient tool to better understand gas transport through shale systems at both molecular scale and pore scale.
Combining Passive and Autonomous Inflow Control Devices in a Tri-Lateral Horizontal Well in the Alvheim Field
Authors: Langaas Kåre , Jeurissen Emile , Hailu Kebede Abay
Published: October 2017

This paper describes the analysis, test and design work to deliver an optimum lower completion for a tri-lateral well, by integrating autonomous and passive inflow control devices (ICD), in the Alvheim field offshore Norway. Chemical tracers, permanently installed in the completion, enabled the evaluation of inflow performance in each lateral. This continues to give valuable information to assess whether the tri-lateral completion is performing as predicted, improves reservoir characterisation and guides reservoir management decisions.

In 2015, both passive and autonomous inflow control devices (AICD) were tested in the laboratory with Alvheim fluids at reservoir conditions. The experimental flow testing, reported in this paper, demonstrated that the AICD chokes gas more efficiently than the passive ICD, but also that the strength of the AICD were lower than expected a priori. The experimental results were used to model the AICD correctly and establish a lower completion strategy as follows: where the well was close to the overlying gas cap, AICDs should be used, while passive ICDs with variable strength were to be used elsewhere to optimise the inflow.

Steady-state inflow modelling was performed before the drilling operation and updated accordingly with the as drilled information. The lower completion design for each branch focused to get what was estimated to be an optimal inflow based on oil volume in place. A key uncertainty in the design work was whether shaly zones along the wellbore would creep/collapse with time and act effectively as packers or not. The lower completion covered around 7 km of reservoir penetration in the three branches, and 15 unique oil tracers were installed to evaluate the clean-up and the inflow profile along the well. The well started producing in May 2016 and downhole flow control valves enabled a successful clean-up, as confirmed by oil tracer responses. In addition, a restart tracer sampling campaign was done after a 12-day shut-in, in August 2016, and this formed the basis for a "chemical production log". The tracer based inflow interpretation is compared quantitatively with the model predicted inflow and qualitatively to the tracer responses seen during the clean-up. This gives valuable feedback to the completion design, and assist in understanding the various degrees of pressure support and if the shaly reservoir sections have creeped/collapsed or not.

The well has exceeded pre-drill production expectations, with an average oil rate of 3375 Sm3/d (21240 stb/d) during the first production year. This is a consequence of higher than expected NTG, but is also partly a result of the lower completion design, where the focus has been to optimize the lower completion such that the whole well contributes, from the heel to all toes. To the knowledge of the authors, this is the first well in the world with a lower completion integrated with AICDs, ICDs and chemical tracers.
Solid and Soluble Products of Engineered Water/Rock Interactions in Eagle Ford Group Chemofacies
Authors: Zhang Lifu , Tice Mike , Marcantonio Franco , Hascakir Berna
Published: October 2017

Interactions between reservoir rocks and engineering fluids during hydraulic fracturing have potential for modification of pores and flow paths by mineral transformation and precipitation and contamination of production fluids by metals and other salts. In order to infer how these interactions affect hydraulic fracturing performance, this study investigates interactions between engineering water and reservoir rocks from different chemofacies in Lower Eagle Ford Group under relevant temperature and pressure conditions. Rock samples were selected from five chemofacies in Lower Eagle Ford Group, which were divided by variations in different element concentrations and total organic carbon (TOC). Static and dynamic experiments were conducted at different condition. In static experiments, crushed reservoir rock samples were exposed to deionized water for three weeks at room condition. In the dynamic experiment, deionized water was continuously injected to the experimental system for three hours at reservoir condition. Rock samples were characterized by XRF before experiments to estimate major and trace elemental concentrations. Water samples after experiments were analyzed for ion contents, total dissolved solids (TDS), particle size and zeta potential. ANOVA single factor analysis using Tukey HSD and principal component analysis (PCA) were used to assess the similarity and difference in interactions between chemofacies. Water parameters were used to determine the tendency of suspensions to precipitate and potential to modify flow pathway during hydraulic fracturing.

This study provides information on interactions likely forming between water and Eagle Ford reservoir rocks and key geochemical tracers indicative of the effective surface areas where interactions occur. The information enhances the understanding of water-rock interaction mechanisms and distribution of fracture networks.
Enhanced Oil Recovery - Polymer Flooding: Surface Transfer Facility Design, Graphical Approach for Hydraulics and Tackle Induced Vibrations
Authors: Jain Shagun , Parekh Bharat
Published: October 2017

Cairn Oil & Gas, vertical of Vedanta Limited, has implemented one of the largest Enhanced Oil Recovery Process (Polymer flood) for its Mangala field (in Rajesthan block) to accelerate and increase the oil recoveries. The Mangala EOR project is a project of national strategic importance which is expected to produce an incremental 74 million barrels till 2040, a six per cent growth over the existing ultimate recovery projection. Based on the positive response of the EOR in the Mangala field, Cairn plans to extent EOR - polymer flooding process to other fields. The reservoir quality, drive mechanism, oil properties make these fields ideal for the application of chemical flooding EOR methods. Due to high viscosity contrast between oil and water, the injected water is unable to displace the oil very efficiently, resulting in some bypassed oil under a conventional water flooding scheme. By adding polymers, the injected water attains a viscosity close to that of the oil, which improves the displacement and overall sweep.

The paper identifies and covers several facets, crucial while designing surface facility for implementing EOR-polymer flooding in a field. The objective of the paper is to Validate and assess theories on pressure and temperature drop estimation for Non-Newtonian fluid with field observations.Present novel models for catering out hydraulics of the Non-Newtonian Polymer Solution. These models have been specifically developed to meet the requirements for plant design while taking into account uncertainities related to actual EOR projects.Present challenges faced in piping system post commissioning of one of the world’s largest full field polymer flood implementation. Root cause analysis of the problem and lessons learned for designing piping systems.
Lean System Aids in the Selection of an Engineered Elastomer/Stator Configuration Leading to Improved Downhole Performance and Field Economics
Authors: Gauthier J. , Grimes M. , Rebellon J. E. , Brown A.
Published: October 2017

Today's demanding market conditions require a higher level of performance in drilling operations to maximize return on investment. This case study outlines how an Operator utilizing the Lean Management System was able to capture and identify non-value added (waste) activities in the drilling process. Thus the Operator was able to single out components in the drill string which generated the largest number of incidents leading to rig non-productive time (NPT). This study led to the identification of a product in the marketplace that helped substantially reduce NPT (waste elimination), positively impacting operations.

Historical run data for each drill string component was tracked, allowing the engineering team to clearly identify the largest number of failed components and root cause for each incident. Data covering a 6-month span indicated 48% of downhole mud motor failures were attributed to power sections. In conjunction with the Lean System, the application of Hierarchy of Controls enabled the Operator to systematically find a corrective action through substitution and engineering controls.

In US shale plays like the Eagle Ford, Haynesville, and Bakken, there is a demand for improved product performance due to challenging drilling applications where bottom-hole temperatures push the limits of existing downhole mud motors. To address these concerns, a new power section with an elastomer capable of withstanding these harsh environments was identified. This paper will compare 100 Eagle Ford shale wells drilled with and without this new elastomer. Designed with a new chemical composition, the trial elastomer led to enhanced performance, including a 65% improvement in success rate and an increase in overall ROP of 21%. The close collaboration between the engineering teams incorporating de-rating performance tables and operational recommendations led to immediate results in the field. This step change in drilling performance led to substantial economic benefits for the Operator.
Identification of Optimum Closure Relationships for a Mechanistic Model Using a Data Set From a Low-Liquid Loading Subsea Pipeline
Authors: Roullier David , Shippen Mack , Adames Pablo , Pereyra Eduardo , Sarica Cem
Published: October 2017

Multiphase flow mechanistic models are macroscopic conservation equations (mass and momentum) supported by several empirical closure relations. There are several empirical corelationsavailable for each closure relationship. The success of mechanistic models largely depends on the employed closure relationships. Although, ideally, the closure relationships are desired to be applicable for all operating conditions and fluids;however, in reality, it is difficult to find such universal closures due to empiricism involved in the development of the closureships. Until the development of universal closure relationships, another viable approach is to find different set of closure relationships for identifiably different flow conditions such as low liquid loading flow or high viscosity liquids.

In this study, we present a procedure to test the performance of multiple closure relationships against available databases. As an initial application of the procedure, we have tested different combination of closure relationships in the Unified Model (Zhang et al., 2003) and identified the combinations of closures that produce the best model performance for low liquid loading conditions using the field data set consisting of the nineteen field measurements from Frigg to St. Fergus gas and condensates export line. The results of the 37,620 simulations were analyzed. The results showed that the original set of closure relationships used in Zhang et al. (2003) was not optimal for this particular set of data. Instead, a different set of closure relationships is proposed to improve the model's performance for these specific field cases. Total absolute average pressure drop deviation was reduced form 11% to 10%. Total absolute average liquid content deviation was reduced from 66% to 1%. Using the proposed procedure, with the availability of additional large-scale field data, the set of closure relationships can be further refined, and even the elusive goal of finding universal closure laws would be possible.
Change Culture, Compete On Costs & Deliver: A Success Story On Adapting A Worldwide International Oil Company Organization To A Challenging Low Oil Price Environment
Authors: Saintpere Stéphane , Hannaford Kevin , Ludosan Simona , Ndiaye Adoulaye , Baldy Edouard , Cousin Frank
Published: October 2017

In March 2014, when the oil price was still above 100 dollars per barrel, the management of TOTAL recognized that the profitability and return on investment were too low and decided to launch an E&P cost culture initiative in response to a decade of excessive cost inflation experienced within the industry. The objective was to embed a cost culture at each level of the organization, designed to reduce significantly operating costsand projects development costs.

The E&P branch named its program "4C&Deliver: Change Culture, Compete on Costs and Deliver" (4C&D), with two key objectives: –Deploy a strong cost and performance culture within the E&P organization–Sustainably reduce costs in order to be able to sanction new projects.

All affiliates and head office divisions were requested to contribute to a 3-year cost reduction plan, addressing all manageable costs (Opex, Capex and Exploration Costs) with quantified savings targets.

This was supported by a change management plan in order to lastingly shift the cost culture, while keeping the HSE performance at its highest, considering that improving the operating mode and efficiency would improve control over the day-to-day on-site works.

During the early phases of deployment of this program, one of the main drivers was to generate the cost optimization initiatives from the employees themselves everywhere in the world, aiming at rethinking the working methods from inside (bottom up approach).

The dissemination of good practices, the integration of the continuous improvement philosophy (LEAN) combined with digital transformation and innovations were keys to success.

The program, that was animated at headquarter level relied on a strong network deployed in affiliates, led to outstanding results as OPEX saving targets were exceeded both in 2015 & 2016, making the Total group one of the best performing IOC's.

This paper will describe: –the main aspects of the methodology, and in particular the "bottom-up" approach in the initial deployment that generated a strong adhesion in the program by the employees,–the governance and animation, based on more than 200 program correspondents worldwide and a small central team,–the main initiative types and associated costs savings, illustrated by concrete examples from various entities (logistics, drilling, production, maintenance, support,…),–the transition to a continuous improvement process towards operational excellence.

With 2,300 costs reductions initiatives at the end of 2016, more than 4 billion dollars cumulated savings on operating costs anticipated over 3 years, and highly committed teams, the operating costs have already been reduced by 40 % from an average 10 dollars per barrel in 2014 to 6 dollars per barrel in 2016. This cost optimization program was a first step in the empowerment of all levels in the company towards sustainable value creation.
Generalized Multiscale Coupling of Triple-Continuum Model and Discrete Fracture Network for Carbonate Reservoir Simulation
Authors: Wang Min , Wei Chenji , Song Hongqing , Efendiev Yalchin , Wang Yuhe
Published: October 2017

In this paper, we couple Discrete Fracture Network (DFM) and multi-continuum model with Generalized Multiscale Finite Element Method (GMsFEM) for simulating flow in fractured and vuggy reservoir. Various scales of fractures are treated hierarchically. Fractures that have global effect are modeled by continua while the local ones are embedded as discrete fracture network based on the geologic observation. For independent vugs, a continuum is used to represent their effects with specific configuration that there's no intra-flow of this continua. GMsFEM enables us to systematically develop an approximation space that contains prominent sub-grid scale heterogeneous background information based on the multi-continuum and DFM model. Conforming unstructured mesh is used to surrender the application of random discrete fracture networks. This paper targets on the improvement of the flow simulation performance in complex high-contrast domain by extending the ability of multiscale method to modeling arbitrary discrete fracture network. This advancement by GMsFEM is motivated by the limited capability of Multiscale Finite Element Method (MsFEM) on modeling discrete fractures when multiple fracture networks present in same coarse block. Multiple numerical results are shown to validate the efficiency of our coupled method.
Designing Subsea Production Systems for Efficient Startup to Mitigate Costly Topside Downtime
Authors: Chidiac Cedric , Sauvé Robert , Kunz Sarah
Published: October 2017

Starting up a subsea production system for large offshore developments is a time-consuming task that can take multiple hours or days. The startup is particularly inefficient during an unplanned shutdown, where the operator may have a threshold time (e.g., 4–6 hours) to fix the problem and startup the production system, before having to preserve the field.

The workflow discussed in this paper aims to determine and reduce the startup time of a subsea production system (SPS). At the center of the workflow, a dynamic integrated model is used to accurately assess and effectively adjust scheduled startup time of the SPS. The integrated model evaluates the dynamic simulation response of a large field startup by integrating a reservoir and gathering network model. The overall workflow incorporates subsurface simulation model, equipment design, field layout design, control systems, and system constraints to create a complete field architecture capable of handling quick, efficient field startups throughout the field life.

The integrated workflow presented in this paper captures a full dynamic response, from the reservoir to the topside. Among other things, a full reservoir model has been integrated with a full dynamic network model that allows for startup evaluation and adjustment to be performed at different points throughout the field life.
Hydrate Induced Vibration in an Offshore Pipeline
Authors: Jujuly M. M. , Rahman M. A. , Maynard A. , Addy Matthew
Published: October 2017

Gas hydrate plugging is considered a very challenging issue in offshore petroleum production and transportation. The phenomenon of hydrate plug formation involves low temperature and high pressure condition. Hydrates can damage equipment of petroleum transport system. In this study, a computational fluid dynamics (CFD) model is proposed to analyze the effect of hydrate flow in pipelines using ANSYS FLUENT multiphase flow modeling techniques.

This study has been carried out with a joint industrial collaboration with GRi simulations, Canada. Two case studies have been investigated. The first one is with a pipeline with a dimension specified by an existing literature (Balakin et al., 2010a) for validating the simulation results. The other one is with a more complex geometry of M-shaped jumper including six elbows. Eulerian-Eulerian method was used to model the multiphase hydrate flow. Moreover, the population balance method (PBM) was used to model the hydrate agglomeration and breaking up mechanism. A parametric study of stress analysis due to the flow-induced vibration on pipelines was also investigated.

This study helps to identify the regions where the maximum stress and deformation due to various flow conditions. The overall objective is to integrate the ANSYS FLUENT model with GRi simulation's IDEA-FDK platform. Petroleum industry can effectively use the proposed tool to prevent the risky operating conditions in offshore structures. The results from the analysis will help to identify the cause of the pipeline failure, regions of the maximum stress occurred in the pipeline and the plastic deformation of the pipeline due to hydrate flow in pipeline.
Delivering Better Business Outcomes with Soft Skills
Authors: Howes C. Susan , Dalrymple Lori , Nelson Jon , Solomon Greg
Published: October 2017

It has often been said that "Technical skills get you hired, and soft skills get you promoted." Whether they are called "soft skills," "nontechnical skills," or "professional skills," the incorporation of soft skills into the development of technical professionals is evolving and becoming more critical to both employers and technical professionals. Because of the "Big Crew Change," new supervisors and technical leaders will take on new responsibilities, which will require them to rely upon their soft skills. Ensuring that soft skills training is embedded with technical training prepares future leaders.

The quality of the technical contribution increases when individuals work more collaboratively. Soft skills help to improve personal effectiveness, providing a vehicle with which to deliver business results. Soft skills enhance expected business outcomes of the technical professional's work product. A variety of methods are utilized in professional development to disseminate best practices in soft skills to technical professionals. In addition to SPE, several other professional and technical societies are placing an increasing emphasis on soft skills development.

There are several ways to measure the impact, both qualitatively and quantitatively, of incorporating soft skills into professional development for engineers. One way of measuring the impact includes surveying participants and their supervisors according to Kirkpatrick's levels of evaluation. It is challenging to incorporate soft skills development into existing rigorous engineering degree curricula or corporate onboarding programs without sacrificing the emphasis on development of technical competency.

Increasingly, it is becoming more apparent that the value of the effort to incorporate soft skills, pays off in multiple ways to both the corporation in achieving their strategic objectives and to the working professional in realizing their career development goals. Common themes from case studies, surveys and benchmarking with other professional technical societies will illustrate how to deliver better business outcomes with soft skills.
Real-Time Formation Evaluation and Contamination Prediction Through Inversion of Downhole Fluid Sampling Measurements
Authors: Kristensen Morten , Chugunov Nikita , Gisolf Adriaan , Biagi Mario , Dubost Francois
Published: October 2017

Acquisition of fluid samples using wireline formation testers (WFT) is an integral part of reservoir evaluation and fluid characterization. Recent developments in formation tester hardware have enabled wireline-based fluid sampling in a wide range of downhole conditions. However, accurate quantification of oil-based mud (OBM) filtrate contamination using data from downhole fluid analysis (DFA) sensors alone remains challenging, especially in difficult sampling environments and for advanced sampling tools which have complex inflow geometries and active guarding of filtrate flows. Such tools and conditions lead to contamination behaviors that do not follow simple power-law models which are commonly assumed in OBM contamination monitoring (OCM) algorithms.

In this paper, we introduce a new OCM algorithm based on inversion of DFA data using a full 3D numerical flow model of the contamination cleanup process. Based on formation and fluid properties and operational tool settings, the model predicts the evolution of filtrate contamination as a function of time and pumped volume and can thus be used to forward-model the DFA sensor responses. Sensor data are then inverted in real time to provide contamination predictions. Real-time computation is enabled through fast, high-fidelity proxy models for the cleanup process. The proxy models are trained on and thoroughly vetted against a large number of full-scale numerical simulations. Compared to existing algorithms, the new OCM method is now applicable for all types of sampling hardware and a wider set of operating conditions. By directly relying on a model of the cleanup process, the physical properties of the formation and fluids (such as porosity, permeability, viscosity, and depth of filtrate invasion) are estimated during the inversion, thus providing additional valuable information for formation evaluation.

The new method is demonstrated by practical application in both synthetic and field examples of oil sampling in OBM. The synthetic examples demonstrate the robustness of the algorithm and show that the true formation and fluid properties can be recovered from noise-corrupted sensor data. The field example presented demonstrates that contamination predictions are in good agreement with results from laboratory analysis, and the inverted formation properties are consistent with estimates based on openhole logs and pressure measurements.
Unconventional Completions Optimization in the Upper and the Lower Montney Formations, Canada
Authors: Mohammed Omar Q. , Kassim Rashid , Britt Larry K. , Dunn-Norman Shari
Published: October 2017

The Montney Formation which stretches from Alberta to British Columbia is one of the largest unconventional gas resources in North America. Production from the Montney Formation comes primarily from the Upper Montney and Lower Montney Formations which vary both from reservoir quality and geomechanical perspectives. Historically, completion and stimulation optimization fell into two distinct categories (1) field observation supported by reservoir and fracture simulation or (2) statistical analysis. Few, if any, statistical studies on optimizing unconventional completions and fracture stimulation combined information from the statistical analysis with that of the simulation. This paper does just that for the Montney Formation by comparing and contrasting the Upper and the Lower Montney completions and fracture stimulation statistical results with a reservoir and fracture simulation study to better understand key drivers for successful stimulation of multiple fractured horizontal wells.

Previous work (Mohammed et al. 2016) documented the statistical analysis of 296 cased-hole horizontal gas wells' completions in the Upper and the Lower Montney Formation. The study showed the effect of cased-hole completion and stimulation parameters on gas production performance in both the Upper and the Lower Montney Formations. In this paper, previous statistical results were extended by adding hydraulic fracture modeling using 3D finite element simulator. The results from the statistical analysis and hydraulic fracture modeling were compared on a set of parameters such as the effect of the number of clusters per stage (1-to-5), changes in proppant mass (50% decrease or increase) and treatment volumes. The results also show the effect of cluster spacing and proppant type on fracture dimensions and production performance within the Upper and the Lower Montney Formation.

This study investigated fracture performance to find the best fracturing practices for the Upper and the Lower Montney. This wok benefits the industry by: Providing a solid simulation study of horizontal gas wells with cased-hole completion, which compared fracture performance for the Upper and the Lower Montney Formation.Providing comparison of multiple fractured horizontal wells' performance in the Upper and the Lower Montney Formation based on the number of clusters per stage and treatment volume.Identifying factors that affect cased-hole completions and stimulation performance in the Upper and the Lower Montney Formation.By conducting fracture cluster optimization study to determine the effect of the number of clusters, cluster spacing and proppant type on fracture dimensions and well performance.
Mono & Thin Layer Performance of Small Mesh Size Proppants Placed in Horizontal Well Fracture Matrices
Authors: Herskovits Raphael , Kidd Ian , Fuss-Dezelic Tihana , Shi Jingyu , Wilcox Craig , Kaul Todd
Published: October 2017

Today unconventional completion objectives strive toward three major goals: creating large fracture networks, placing as much proppant in those networks as efficiently as possible and ensuring fracture conductivity is sufficient to allow for maximum reservoir drainage. While operators use different, and often proprietary, completion protocols to achieve these goals, market research shows a growing trend towards the use of small mesh size proppants such as 30/50, 40/80 or even 100 mesh proppants primarily utilizing slickwater fracturing fluid systems.

Fracturing of unconventional reservoirs in this manner creates a very narrow fracture environment. This creates a completion design problem as most proppant types and sizes are qualified using 2 and 4 lb/ft2 loading conditions to simulate the wider fractures of conventional sandstone reservoirs. Further complication also lies in the fact that prior to shale development, small mesh size proppants, such as 100 mesh were very rarely used or tested as a proppant.

The study compares the mechanical strength of 40/80 white sand, 40/80 clay-based economy lightweight ceramics (ELWC) and 40/80 bauxite-based intermediate strength ceramics (ISC), as well as, 35/140 bauxite-based intermediate strength ceramic (ISC) and 100 mesh sand using standard and modified API RP 19-C crush resistance tests. During testing, load cell concentrations were varied from the standardized 4 lb/ft2 to the modified concentrations of 0.5 and 0.25 lb/ft2 – concentrations more realistic for unconventional reservoirs. Mechanical failure of proppants is quantified by comparing proppant size distribution pre- and post-stress application using a Horiba CAMSIZER. Mechanical compression of proppant packs is measured during testing and compared for different proppant types. Failure mechanism of proppants is also evaluated using an in-situ high pressure CT scanning protocol enabling visualization of the proppant failure as a function of applied load, proppant type and concentration.

The study shows that mechanical performance of tested materials, measured as proppant crush, deteriorates with decrease in proppant bed height. Deterioration of performance is, however, much less pronounced for small mesh size proppants than previously studied large mesh proppants. Contrary to that, pack compression results indicate higher compression of small mesh proppants under monolayer/thin bed conditions suggesting a large decrease in proppant pack conductivity. The most extreme pack compression is measured for 100 mesh sand proppants. In-situ CT scans also confirm these results and further visualize the effect of pack compression on proppant pack conductivity.