bluuebunny/crossref_metadata_2025 huggingface dataset:
Applying Systems Approach to Wells Process Safety Management for Hse Goal Zero Sustainbility
Authors: Dedenuola Adetola , Ogbuji Ikenna , Obanya Phillip , Ogedegbe Okurerie , Akhideno Mathias
Published: October 2017

This abstract highlights the strategic importance of Process Safety Management (PSM) to organizations, and introduces an innovative approach for assessing the robustness of a Process Safety Management System (PSMS), and for reengineering it as necessary to enhance and support sustainable performance in HSE Goal Zero (GZ).

Because process safety incidents occur mostly in operational activities, there is obvious temptation to treat Process Safety as an operational issue. But the huge loss (>USD 60 billion fines/penalties and ~50% reduction of shareholder value) suffered by BP in the immediate aftermath of the Macondo Well Control Incident (WCI) revealed the strategic dimension of Wells Process Safety Incidents (WPSI), and their potential to precipitate corporate collapse if not properly mitigated against. Evidently, Wells Process Safety Management (WPSM) transcends operational level of organizational management and is quintessentially strategic due to the existential threats that failures in this area could pose to business survivability.

Consequently, it is imperative for organizations whose operations might involve Process Safety related Major Accident Hazards (MAH) to have a high-quality PSMS that is properly harmonized with their corporate strategic intent, goals and aspirations. However, the success or otherwise of this depends in no small measure on the robustness of the approach and methodology employed in developing the management system and testing its effectiveness on an ongoing basis.
A Semi-Analytical Model for Pressure Transient Analysis of Fractured Wells in Unconventional Plays with Arbitrarily Distributed Fracture Networks
Authors: Chen Zhiming , Liao Xinwei , Sepehrnoori Kamy , Yu Wei , Zhao Xiaoliang
Published: October 2017

In this paper, we present an efficiently semianalytical model for pressure transient analysis in fractured wells by considering arbitrarily distributed fracture networks. The semianalytical model included three domains: (1) matrix, (2) hydraulic fracture networks, and (3) discrete natural fractures. Using line source function, we developed the diffusivity equation for fluid flow in matrix. By applying the nodal analysis technique, we eliminated the flow interplay at fracture intersections and established the diffusivity equations for fluid flow in hydraulic fracture networks and isolated natural fractures. The pressure transient solution of these diffusivity equations was obtained by using Laplace transforms and Stehfest numerical inversion.

Results showed that with the discrete natural fractures, a "V-shaped" pressure derivative --the classical dual-porosity feature of naturally fractured reservoirs--emerged. With the hydraulic fracture networks, the reservoir system would exhibit pressure behaviors like "pseudo-boundary dominated flow", "fracture-interference flow", and "fluid-feed flow", etc. All these pressure characteristics were depending on the properties and geometries of natural/hydraulic fractures. In addition, through synthetic field application, we found that different (natural/hydraulic) fracture distributions and geometries had distinct behaviors of pressure derivatives, which may provide an effective tool to identify the properties of randomly distributed natural fractures as well as complex hydraulic fractures in unconventional plays.
Non-Equilibrium Solvent Injection Simulation via Pore Scale Heat Conduction and Dispersion
Authors: Bayestehparvin Bita , Ali S. M. , Abedi Jalal
Published: October 2017

In the mathematical treatment and numerical simulation of hybrid recovery processes, specifically SAGD (Steam-Assisted Gravity Drainage) with solvents, instantaneous phase equilibrium is assumed. Previous studies by the authors, and others, show that this is not the case. Experimental work and the lack of success in the field corroborate this view. In the present work, a non-equilibrium model is developed involving the solution of mass and heat transfer equations. The state of equilibrium is based on diffusion and dispersion at the pore scale.

First, a new model is developed for oil mobilization by solvent and heat based on diffusion and dispersion mechanisms for different solvents. The concentration distribution is used to calculate the partition coefficients in a gridblock based on temperature, pressure, composition, and apparent time. The latter is different from simulation time and is an indicator of gridblock interaction with the solvent. By defining new parameters viz. apparent time, a gridblock has a memory of how long it was in contact with the solvent.

The analytical model developed in the first phase of this work confirmed the need for a non-equilibrium model for reservoir simulation. The non-equilibrium partition coefficient developed for vapor solvents of methane, propane, and butane using compressible assumption for the vapor phase. The oil production appears to improve using a solvent if instantaneous equilibrium is assumed. In this study, the nonequilibrium approach developed for heated solvent showed the cumulative oil production decreased as a result of the inability of the solvent to reduce viscosity.

The present study is the first of its type in the development of a non-equilibrium pore-scale simulator. The outcome of this study is considered to be novel in reservoir simulation that can improve predictions significantly.
Impact of Pore Confinement on Production Behavior and GOR Profiles of Unconventional Reservoirs
Authors: Calisgan T. , Ozkan E. , Firincioglu T. , Sarak H. , Ozgen C.
Published: October 2017

This paper extends the discussion of the impact of pore-size distribution and connectivity on the productivity and GOR behavior of wells in unconventional reservoirs to more complex petrophysical heterogeneities and layered and compartmentalized systems. Two well congurations are considered: four vertical wells located at the corners of the grid and one horizontal well located in the middle layer of a three-layer system. A black-oil simulator, which includes the effects of capillary-pressure on phase behavior and gravity, is used in the study. Several simulation models are considered to investigate the impact of single-, dual-, and n-porosity formulations on oil and gas production profiles for different capillary-pressure distributions varying by layers or regions. Results accentuate the earlier conclusions that pore-size distribution and other petrophysical heterogeneities have a stronger effect than the magnitudes of the pore sizes on the productivity and GOR of unconventional wells.
Leak off Test LOT Modeling for Inclined and Horizontal Wells
Authors: Sun Kewen , Wu Lingyun , Bui Nghia , Samuel Robello
Published: October 2017

Considerable efforts have been devoted to the modeling of the results for the Leak-off Tests (LOT) in the past. Over the last decade, there are two major focuses in this field of research: the extended application of LOT models to horizontal wells and the theory of the fluid leakage during LOT.

In the present study, an improved model has been proposed based on the original Altun's model: 1) the initial system volume is corrected after considering thermal and pressure effects as well as the geometry of the well path; 2) the casing expansion during LOT test is extended to directional wells with respect to pressure change; 3) a new leak volume model is developed to analyze the different flow behavior of fluid before and after the fracture initiation pressure (FIP). The data from a field example is used to validate the model. The predicted results demonstrate the improvement and accuracy of the model for the estimation of LOT values for horizontal wells.
From Face Detection to Fractured Reservoir Characterization: Big Data Analytics for Restimulation Candidate Selection
Authors: Udegbe Egbadon , Morgan Eugene , Srinivasan Sanjay
Published: October 2017

In recent years, there has been a proliferation of massive subsurface data from instrumented wells. This places significant challenges on traditional production data analysis methods for extracting useful information, in support of reservoir management and decision-making. Additionally, with increased exploration interest in unconventional shale gas reservoirs, there is a heightened need for improved techniques and technologies to enhance understanding of induced and natural fracture characteristics in the subsurface, as well as their associated impacts on fluid flow and transport.

The above challenges have the potential to be addressed by developing Big Data analytic tools that focus on uncovering masked trends related to fracture properties from large volumes of subsurface data, through the application of pattern recognition techniques. We present a new framework for fast and robust production data classification, which is adapted from a real-time face detection algorithm. This is achieved by generalizing production data as vectorized 1-D images with pixel values indicating rate magnitudes. Using simulated shale gas production data, we train a boosted binary classification algorithm which is capable of providing probabilistic predictions. We demonstrate the viability of this approach for identifying hydraulically fractured wells which have the potential to benefit from restimulation treatment. The results show significant improvements over existing type-curve based approaches for recognizing favorable candidate wells, using solely gas rate profiles.
Fully Dissolvable Fracturing Plug for Low-Temperature Wellbores
Authors: Fripp Michael , Walton Zachary , Norman Tyler
Published: October 2017

Dissolvable fracturing plugs are used for hydraulic fracturing applications. However, most new dissolvable materials have slow or no degradation in low-temperature formations. A new low-temperature dissolvable fracturing plug was developed for low-temperature formations. This new dissolvable fracturing plug is composed of a high-strength metal with elastomeric seals that dissolves completely in lower-temperature wellbore fluids.

Traditional fracturing plugs are constructed from composite materials and nondissolving elastomers. These nondissolving fracturing plugs obstruct production and need to be milled out after fracturing is completed. Dissolvable fracturing plugs dissolve in wellbore fluid, eliminating the need for a separate mill run intervention into the wellbore. However, the dissolution process slows in lower-temperature shale formations and the elastomer often ceases degradation at these lower temperatures. Therefore, a new metal and elastomer was developed that allows for the complete dissolution of the fracturing plug in lower-temperature formations.

The new low-temperature fracturing plug is optimized for use with the fluids used and temperatures experienced in the Marcellus and Permian basins. Comprehensive laboratory testing was conducted on the dissolvable metal alloy and dissolvable elastomer for the new low-temperature dissolvable fracturing plug. The dissolvable metal alloy is a metallic alloy that is combined with a dopant. Metallographic analysis illustrates the effect of the dopant on the dissolution of the metallic alloy and the accelerated dissolution needed for lower-temperature formations. The dissolvable elastomer uses a hydrolytic degradation reaction that is accelerated for low-temperature fluids. The result is a high-strength fracturing plug that can be set anywhere within the wellbore and will dissolve completely at formation temperatures between 120 and 180°F. The high-strength dissolvable materials allow dissolution in water-based wellbore fluid, formation fluid, or production fluid.

The novel fracturing plug is designed for low-temperature plug-and-perf applications and is composed of a new high-strength engineered metal and elastomer. Complete dissolution of the fracturing plug eliminates the need for a separate mill run intervention into the wellbore, which helps reduce costs, operation time, and risks to personnel. This paper discusses the development of the dissolvable metal, the development of the dissolvable elastomer, and the tested behavior of the low-temperature dissolvable fracturing plug.
Stop, Drop and Circulate; An Engineered Approach to Coiled Tubing Drillouts
Authors: Pope Charles , Charlton Alistair , Inscore Josh , Epperson Ryan , Sumner Blaine
Published: October 2017

In 2015, Devon Energy spent $60 million on post-stimulation drillouts. The average cost of a drillout was $250,000 when no issues were encountered. However, drillouts with significant issues cost an average of $1.7 million. In November 2015, the Drillout Group (DOGs) was formed to study and find solutions for issues associated with coiled tubing drillouts. The team consisted of 15 completions and drilling engineers directly involved in coiled tubing drillouts. The team met for eight months and invested more than 1,000 hours of engineering time. The DOGs visited with more than a dozen vendors, took three field trips and conducted laboratory experiments on various fluid systems.

This paper examines the history of coiled tubing drillouts at the operator and how stuck events were considered to be a normal aspect of operations. The DOGs team was tasked with engineering a solution to coiled tubing drillouts and formulating a Best Practice (BP) to apply companywide to minimize "train wrecks." The primary focus of the DOG team was to create standards for coiled tubing jobs including the target Reynolds numbers, annular velocity, chemicals, viscosities, torque and drag, early warning signs and corrective actions to prevent stuck pipe.

The paper evaluates the implementation of a real-time monitoring station and the results from 50 wells drilled out following the DOG best practice. The new best practice and live monitoring station resulted in average savings of $100,000 and average drillout time of 21 hours per well with zero stuck or sticky events recorded.
New Variable Compliance Method for Estimating In-Situ Stress and Leak-Off from DFIT Data
Authors: Wang HanYi , Sharma Mukul M.
Published: October 2017

Over the past two decades, Diagnostic Fracture Injection Tests (DFIT) or Injection-Fall-off Fracture Calibration Tests have evolved into a commonly used and reliable technique to evaluate reservoir properties, fracturing parameters and obtain in-situ stresses. Since the introduction of DFIT analysis based on G-function and its derivative, this method has become standard practice for quantifying minimum in-situ stress and leak-off coefficient. However, the pressure decline model that underlies the G-function plot makes two distinct and important assumptions: (1) leak-off is not pressure-dependent and, (2) fracture stiffness (or compliance) is assumed to be constant during fracture closure. Fracture closure is a gradual process that starts when asperities at the fracture tip first come into contact with each other. As pressure declines due to leak-off, more and more of the fracture wall comes into contact. It is important to model this process quantitatively to obtain good estimates of in-situ stresses and leak-off. In this paper, we present a model that accounts for changes in fracture stiffness/compliance as the fracture closes, with leak-off that is dependent on fracture pressure. The model is, therefore, capable of analyzing DFIT data from the end of pumping to days or even weeks after shut-in.

We first review Nolte's original G-function model and examine the assumptions inherent in the model. We then present a new global pressure transient model for pressure decline after shut-in which not only preserves the physics of unsteady-state reservoir flow behavior, elastic fracture mechanics and material balance, but also incorporates the gradual changes of fracture stiffness/compliance due to the contact of rough fracture walls during closure. This global model allows us to analyze the whole spectrum of DFIT data by bridging before closure and after closure data seamlessly. Analysis of synthetic cases, along with field data are presented to demonstrate how the coupled effects of fracture geometry, fracture surface asperities, formation properties, pore pressure and wellbore storage can impact fracturing pressure decline and the estimation of minimum in-situ stress.

It is shown that so-called "normal leak-off" behavior that is modeled using Carter leak-off is an oversimplification that leads to significant errors in the interpretation of the data. All the before closure analysis conducted under a "normal leak-off" assumption should be reexamined cautiously. Most importantly, this article reveals that previous methods of estimating minimum in-situ stress often lead to significant over or underestimates, because of their failure to account for changes in fracture stiffness/compliance correctly as the fracture closes progressively from the edge to the center. Based on our modeling and simulation results, we propose a much more accurate and reliable method to estimate the minimum in-situ stress, fracture pressure dependent leak-off rate and evaluate the compliance of the un-propped fracture.
A Machine Learning Approach to Optimize Shale Gas Supply Chain Networks
Authors: Asala H. I. , Chebeir J. , Zhu W. , Gupta I. , Taleghani A. Dahi , Romagnoli J.
Published: October 2017

The unsteady recovery of oil and gas prices in early 2017 led to an increase in drilling and hydraulic fracturing operations in North America liquid-rich shale plays. The increasing number of producing wells, in addition to re-fractured wells, impose the need for optimizing field development strategies and shale gas supply chain networks that maximize profitability. Moreover, operators must account for undulating natural gas demands both locally and externally in a persistently low oil price environment. In this paper, we adopt supervised machine learning approaches to forecast local natural gas demand as well as guide well re-frac candidature. Both serve as critical inputs for maximizing the net present value of any shale gas field development project. An optimized water management structure is also incorporated in the proposed framework to account for associated produced-water recycling.

Considering a shale gas network in the Marcellus play, supply chain optimization was achieved using a mixed integer non-linear programming formulation. The Strategic Planning model relies on at least 4 major efforts including reservoir simulation, which in turn relies on output from a feed forward Neural Network (NN) algorithm. The trained NN algorithm was deemed suitable for recommending re-frac candidates, necessary decision variables for multiphase reservoir simulation. Finally, NPV optimization relied on a four-layer Long Short-Term Memory (LSTM) recurrent neural network, developed for forecasting local shale gas demand. Both neural network algorithms were scripted using python.

17 non-redundant parameters were mined for 250 wells in the case study. The t-Distributed Stochastic Neighbor Embedding technique was used to visualize related low dimensional manifolds within the high-dimensional data set, and a NN algorithm was used to obtain probabilities of misclassification. The well-pads in the case study superstructure are modeled using compositional reservoir simulation. Each reservoir model is tuned by history matching production and pressure data for designated producing wells. Alternative field development strategies (including re-fracturing) are then simulated for a 10-year planning horizon to generate gas and water rate decline profiles. Using the LSTM developed, local gas demand is forecasted using data sets created from multivariate time-dependent local and global variables affecting shale gas demand. The LSTM algorithm is derived by convolving some features from the raw data set, with fined-tuned weights, with the objective of minimizing a pre-defined demand error function. The results obtained show that application of this integrated approach can give operators a calculated advantage, preventing erroneous feedback of project profitability but allowing early time decision-making that maximizes shale asset NPV.
Increased Asphaltenes Surface Aids Fuel Formation with the Presence of Clays during In-Situ Combustion
Authors: Ismail Norasyikin B. , Hascakir Berna
Published: October 2017

Increased surface area of reservoir rock due to the presence of clays and the catalytic impact of clays are known to enhance the in-situ combustion (ISC) performance. But the basics behind these mechanisms are still not known. In this study, we investigated the role of clays on ISC in microscopic scale.

Six one-dimensional combustion tube experiments were conducted on three different crude oil samples. The combustion performance of each crude oil was evaluated with two combustion runs; reservoir rock prepared with sand-oil and with sand-clay-oil mixtures. Each combustion tube test was evaluated in terms of cumulative oil production, combustion front propagation, and characterization of the produced oil samples. Activation energy and heat of combustion were calculated empirically. Quality of the produced oil samples was determined through viscosity measurements. Saturates, aromatics, resins, and asphaltenes (SARA) fractions of initial and produced oil samples were compared. To better understand the fuel formation mechanism, asphaltenes surfaces were visualized by a Scanning Electron Microscope (SEM) and SARA fractions with Fourier Transform Infrared (FTIR).

Combustion tube experimental results highlight that crude oil type affects the process performance the most. Clay presence in the rock expedited the combustion front velocity by increasing the oxygen utilization rate. Activation energy was reduced drastically with the presence of clays, however, the heat of combustion has not changed. Thus, the generated heat has been consumed more effectively with the presence of clays. Produced oil quality has been increased significantly in terms of viscosity, more viscosity reduction was observed with the presence of clays. Since saturates acts like an ignitor during ISC, the amount of saturates fraction was decreased in produced oil when compared to initial oil. While the amount of aromatics fraction was increased significantly, the asphaltenes fraction is decreased with the presence of clays when compared to the aromatics and asphaltenes fractions of the initial oil. The reduction in viscosity is mainly due to increased aromatics content of produced oil with high solvent power. With the SEM images taken on asphaltenes surface, the role of clays has been observed clearly on fuel formation. With the presence of clays, the asphaltenes surface have created cribriform structures. Without clays, asphaltenes surfaces were observed as smooth surface. Those holes should increase the surface area on asphaltenes surfaces and increase the effective transformation of asphaltenes into fuel.
Case Studies of Optimizing the Artificial Lift Strategy for Reactivating Abandoned Wells in a Mature Field
Authors: Patron Katherine Escobar , Villarreal Paola Martinez , Leon Jorge Luis
Published: October 2017

At a time when oilfield economics preclude new drilling, one way to achieve economic goals is to strategically reopen abandoned wells. Choosing the artificial lift strategy that best suits the economic constraints for the reactivation of abandoned wells is a challenge. This paper uses real-world field data examples to introduce a new methodology that replaces opinion and guesswork with objective and quantifiable comparisons to drive strategic decisions that balance technical and economic concerns. A new method to simplify and quantify the development of that strategy can have wide-ranging impact for mature fields around the world. The study uses a sample of 10 wells initially completed with electrical submersible pumps (ESPs) with different production characteristics and well profiles from a mature field in South America.

Reactivating abandoned wells is particularly challenging because the reasons for abandonment are complex; production challenges ranging from deep installations, low production rates as well as flow assurance related problems lead to premature equipment failures and final well abandonment. As economic conditions change and new technology is developed, the abandoned wells' value potential may also change. This paper uses the sample wells to demonstrate a new method of selecting optimal artificial lift systems for highly complex projects.

A new method of artificial lift system selection provides a quantifiable, objective means of studying well and field economic and technical potential. The method balances economic factors with specific well application considerations to optimize performance to suit an operator's strategic plan. The data in the paper demonstrate that the method can give a solution for a challenging environment of previous abandoned wells by selecting the artificial lift method that maximizes reliability and performance under specific operating conditions. After the workflow implementation, the sample data was classified into two groups where: Group 1: Wells where the ESP systems are the best strategy—with to special design considerations and equipment configuration to manage production challenges.Group 2: Wells where hydraulic pumping units are the best solution—with special attention to rod design and downhole equipment to meet the production challenges.
An Analysis of Classroom Inversion in the Corporate Environment
Authors: Thompson Analise J , Flores Daniel V , Pauls Ralph
Published: October 2017

This paper compares instructor led training versus classroom inversion for two courses taught at Exxon Mobil Corporation ("ExxonMobil"). We discuss training elements such as total training hours, pre/post-test results, and student satisfaction surveys. The most important findings are: Student and supervisor behaviors need to change when learning is transformed from an event to an extended journeyGreater effort is required to prepare for and monitor the progress of studentsClassroom efficiencies can be realized and the quality of instruction enriched with inversionThe effectiveness of learning was comparable to that of a conventional classroom
Successful Sand Blockage Removal from Sealine Using an Innovative Plastic Coiled Tubing
Authors: Pelucchi M. , Mantica D. B. , Piemontese M. , Restuccia G. , Mackenzie H.
Published: October 2017

Sand accumulation occurs in subsea infrastructure and pipelines, also called sealines, when the fluid carrying capacity isn't sufficient. Once this situation degenerates, the maximum achievable production rate decreases till complete stop: a sand blockage is formed and production lost.

The first worldwide subsea application for a plastic coiled tubing for sand removal demonstrates the opportunity to think for alternatives and use an innovative technology to avoid expensive pipeline replacement and to restore the production in a quicker and cheaper way.

With space upon FPSO units inherently limited, a complex engineering solution involving workover rig or intervention vessel is typically required to support the removal of sand plug or line section replacement. Those options, are inherently expensive, and could shut down the production for a long period and generate additional HSE risks.

A preliminary analysis is necessary to identify the sand plug dimension and plan the proper remedial job.

In 2014, Operator decides to think for alternatives and performed a smart intervention using an innovative Plastic Coiled Tubing directly from FPSO, washing down the riser and the subsea flowline till complete sand blockage removal.

The use of a standard coiled tubing unit isn't an applicable solution for severe limitations in transport and rig/up operations; so the decision is to select and develop a customized ultra-lightweight, highly flexible pipe compared to conventional coiled tubing.

On board of the FPSO unit, a continuous improvement process is necessary to optimize equipment layout and configuration. Adjustments in operative procedures and some troubleshooting actions maintain higher the efficiency during the washing and cleaning job through riser and subsea flowline.

The final result is the complete sand blockage removal and the hydraulic continuity re-establishment inside the pipeline.

The overall process successfully validates the so performed analysis, screening and equipment selection, demonstrating that plastic coiled tubing is a valid and innovative tool for sealines washing and production restoration in a quicker way.
Quantitative Assessment of the Impact of Sparse Data and Decision Bias on Reservoir Recovery Forecasts
Authors: Meddaugh W. S. , Meddaugh W. , McCray B.
Published: October 2017

Nandurdikar and Wallace (2011) industry-wide lookback summary showed that recovery forecasts made prior to project sanction averaged about 25-50% higher than actual observed reservoir performance. This study has examined the potential quantitative impact of sparse data and "decision" bias on reservoir recovery forecasts using a synthetic data set. The approaches utilized included statistical analysis of forecasts derived from a synthetic analog data set as the number of analogs was reduced from the full set of reservoirs to as few as 25% of the available reservoirs using random as well as biased selection criteria. The latter bias experiments allowed some inference to be made as to the potentially large impact of management "decision" bias. Statistical results obtained from the synthetic and actual case histories suggest that sparse data "impact" may account for up to 10-25% of the observed optimism and that decision bias for up to 15-25% of the observed optimism. Although not investigated in detail in this study, prior work (Meddaugh, 2015) suggested that other sources of potential bias such as stochastic geological model parameters (e.g. the semivariogram model) and upscaling are generally small with the possible exception of static/dynamic model grid parameters (particularly dynamic model cell size) and well location optimization workflows. Improved quantitative understanding of the potential impact of sparse data and decision bias on reservoir forecasts will enable the industry to reduce the forecast optimism noted by Nandurdikar and Wallace (2011) and will likely improve capital efficiency in the industry.
New Development of Multi-Detector Pulsed Neutron Instrument for Quantitative Gas Saturation Monitoring in Air- or Gas- filled Boreholes: Physics, Modelling and Application
Authors: Zhang Qiong , Chace David , Inanc Feyzi , Wu Jianghui , Yuan Peng , Gade Sandeep , Kim Yonghwee
Published: October 2017

One important application of a multi-detector pulsed neutron instrument is to detect gas response for determining quantitative gas saturation in the formation. Obtaining this saturation value is achieved by differentiating the gas response from the liquid response. The maximum formation sensitivity to gas and liquid is observed when the wellbore is filled with liquid. When the wellbore is filled with gas, however, the separation between formation gas and liquid responses is reduced. This reduced separation results in increased uncertainty in the log analysis. The current operational solution is to set a plug and the fill the borehole with water. Although this technique helps to obtain the desired formation gas-liquid sensitivity, it incurs increased operational expenses, potential damage to fragile formations, reinvasion effects, etc.

To overcome these challenges, a sleeve has been designed to deploy with the pulsed neutron instrument. The sleeve imitates the presence of water in the borehole around the tool and increases the dynamic range to the levels seen with the boreholes filled with water and oil-based fluids. This technique extends the application of multi-detector pulsed neutron instrument to provide solutions in airor gas-filled boreholes. It avoids the potential damage to the formation, diminishes HS&E hazards, and reduces operational expenses by eliminating the operation of loading the borehole with water or brine.

The sleeved pulsed neutron instrument has been evaluated using Monte Carlo nuclear modelling for design and validation. Prior to any deployment, a sensitivity analysis is conducted using Monte Carlo N-particle (MCNP) transport code to evaluate the formation sensitivity improvement due to the presence of the sleeve. The impact of various tool-sleeve positions and the performance of various sleeve materials have also been studied. A case study is presented to demonstrate how the sleeved pulsed neutron tool significantly improves formation gas sensitivity as compared to the standard tool in gas-filled boreholes.
Hydrate Plug Remediation in Deepwater Well Testing: A Quick Method to Assess the Plugging Position and Severity
Authors: Zhao Yang , Wang Zhiyuan , Yu Jing , Pan Shaowei , Zhang Jianbo , Sun Baojiang
Published: October 2017

Gas hydrates can form during deepwater well testing, resulting in serious flow assurance problems. Once plugs form, remediation operations must be carried out to remove the plugs. We developed a method to quickly locate the plugging position and assess the severity of hydrate plugs. The proposed method was developed based on hydrate thermodynamics, kinetics, and hydrate particle transport & deposition dynamics. The application procedure was established. Flowrate, pressure and temperature data in well testing was collected and used as input data for hydrate plugging development analysis, from which the plugging location and severity could be quickly assessed. The plugging position and severity under various water depth, gas production rate and inhibitor concentration conditions were obtained. It indicates that hydrates generate and attach to the tubing wall and form a growing hydrate layer, which narrows the effective flow area of the tubing. As the hydrate layer becomes thicker, the plugging becomes more severe and bring a greater interference to well testing operations. A significant choking effect is encountered when the hydrate layer thickness increases to a critical value, resulting in distinct pressure drop increase in the testing tubing. It indicates the occurrence of conduit blockage. The plugging position is found at the site where the maximum subcooling is encountered, rather than where the lowest ambient temperature presents. For a typical deepwater gas well, the plugging position is at 150 m below the sea surface. The effects of gas production rate, inhibitor concentration and water depth on plugging position are studied. It is found that the plugging position becomes deeper as the water depth increases and/or the production rate decreases. More severe plugging can be encountered when the gas production rate is lower, the water is deeper, and/or the inhibitor concentration is lower. The proposed method can help operators locate the plugging position and assess the severity of hydrate plugs in a shorter time compared to traditional methods. This study provides key instructions and helps reduce uncertainties involved in removal work. Therefore the operational risk and duration can be significantly cut down.
Extension of Capacitance-Resistance Model to Tracer Flow for Determining Reservoir Properties
Authors: Naudomsup Nuntha , Lake Larry W.
Published: October 2017

Several tools and techniques exist to understand distributions of reservoir properties. Interwell tracer testing is one ofthe most common methods to obtain reservoir information from the amount of tracer produced. The capacitance-resistance model (CRM) is an analytical tool to estimate connectivity between producer-injector pairs from historical rates and (when available) bottom hole pressure data in waterfloods.Because the CRM is a physically based, simple input-output model, its combination with tracer testing can provide insight into reservoir features.

To enable the CRM application to tracer flow, we incorporated tracer models,based on miscible displacement theory, into the CRM. Reservoir properties are estimated as a result of the model fitting to produced tracer data. In this paper, we present three tracer models:a dispersion-only(short range autocorrelation) model, a Koval (long-range) model, and a combination of the two. To incorporate the tracer models into the CRM, we used two methods, serial fitting (CRM then tracers) and simultaneous fitting (CRM and tracers).

We applied these techniques to tracer data from 10 injectors and 10 producers of the Lawrence field. Results suggest that interwell connectivity obtained from the CRM is in good agreement with the observed peak tracer concentrations. All tracer models are able to give a good fit in most of the cases. Comparing among the tracer models, the combined model can better represent a tracer flow than the other two models alone. We also found that the simultaneous fitting method gives the best fit to total producer rate data and tracer data. Simultaneous fitting mitigates the non-uniqueness of the fits, leading to an improvement of tracer matching. The reservoir properties obtained in this study (Koval factor and dispersion coefficient) were also analyzed and compared to those from previous measurements.
Downhole Multiphase Flow Monitoring Using Fiber Optics
Authors: Fidaner Onur
Published: October 2017

Distributed Acoustic Sensing (DAS) technology has been used in an increasing number of applications in the petroleum industry.Multiphase flow rate measurement is an important DAS application. In this work we provide a forward model relating multiphase flow rates and two-phase flow patterns in the wellbore to the DAS data. Modeling consists of a series ofanalytical relationships between various physical parameters, which allows for simulating DAS data efficiently based on various assumptions regarding the flow and wellbore. The forward model also allows us to characterize various mechanisms that introduce uncertainty to DAS data and various parameters estimated from DAS data. We also discuss methods to analyze DAS data to find the speed of sound and flow rates in the wellbore. The forward model enables us to develop efficient algorithms for the inverse model, including the wavelet transform and artificial neural networks to analyze DAS data in real time and calculate the flow rate and flow patterns in the wellbore.
Integration of Pressure and Rate Transient Analysis for Transverse and Longitudinal Multistage Fractured Horizontal First Unconventional Gas Well in Egypt
Authors: Ibrahim Mazher , Salah Mohamed
Published: October 2017

Recent advancements in technologies pertaining to the drilling of horizontal well and multistage hydraulic fracturing have made it possible to get significant hydrocarbon production even from extremely low permeability formations. Evaluation of the economics is becoming increasingly essential before committing to any big investment. In this scenario, production forecasting plays an important role by not only evaluating the economic feasibility of the project, but also helping in the selection of the most optimal development strategy (Shivam et al. 2017).

This paper presents an integrated workflow that has been applied in one of unconventional gas bearing formation which is a common reservoir in Egypt’s Western Desert. It does form a reasonable reservoir size and spread over several hundred sq.kms. It is characterized as a low permeability carbonate (0.2 mD) in soft chalk reservoir. Many vertical wells were drilled and completed in the appraisal program for collecting the required data to evaluate reservoir performance before the completion of horizontals, but economical target production rates could not be achieved. To help optimize field development strategy and further increase production, a full field development plan was initiated by drilling horizontal wells with multistage fracturing stimulation. Horizontal pilot wells were drilled and completed along and perpendicular the minimum horizontal in-situ stress direction to enable both transverse and longitudinal fracture propagation patterns for the best completion option.

The objective of this paper is to present an integrated approach to evaluate an unconventional resource, improve the completion efficiency, improving the future fracture design and understand the productivity enhancement specifically in the Western Desert of Egypt, through a detailed analysis of production data and pressure transient analysis.

The conclusions from this study will help in evaluating the behavior of multistage fractured horizontal with different fracture azimuth direction and generate production forecast for different development scenarios. The stimulated rock volume estimation will help in planning the future fracture design to increase well EUR. The proposed workflow and lessons learned formed the basis for subsequent development of various unconventional plays in Egypt.
An Engineered Approach to Design Biodegradables Solid Particulate Diverters: Jamming and Plugging
Authors: Shahri Mojtaba P. , Huang Jian , Smith Clayton S. , Fragachán Francisco E.
Published: October 2017

Fluids introduced into a reservoir for stimulation typically take the path of least resistance and therefore frequently go into areas where there are open flow paths. In many cases, those are neither the areas you would want to stimulate for increased production nor areas from which formation damage will need to be removed. The success of a hydraulic fracturing or an acidizing operation depends on maximizing the contact between the fracturing fluid (or acid) and intact rocks. To achieve this goal, existing fluid paths must be effectivelyplugged to divert the fluid towards intact rock for an efficient application.

A typical fluid diversion application can be divided into three major steps; i.e., displacement from surface to downhole, downhole plugging/diversion and corresponding stimulation and production efficiency.The aim of this paper is to review and identify the criticalparameters controlling the downhole plugging and diversion step. In addition, an analytical solution is used for predicting minimum required concentration of solid-particulate diverting agent. The proposed model incorporates multiple operational parameters such as flow rate, fluid viscosity, particle size, and opening size. The validity of the proposed solution is checked byusing experimental testswith single slot-opening. In addition, a coupled Computational Fluid Dynamics (CFD) and Discrete Element Method (DEM) model has also been used to verify the proposed analytical solution.The findings will have beneficial implications for acidizing, multistage hydraulic fracturing, and refracturing operations.

By using a scientific approach, better understanding of the controlling parameters along with the verified analytical solution,we can better design and achieve efficient fluid diversion and necessary pressure buildup.The analytical solution verified against both experimental data and advanced numerical simulations (CFD-DEM) can significantly and reliably enhance the diversion job efficiency. Using the analytical solution along with the thorough understanding of underlying mechanisms, we can optimize the particulate system characteristics for a successful diversion process. As an example and by selecting the minimum required concentration, we can eliminate the excessive use of diverting agents, which would reduce costs and adverse effects on equipment resulting from high concentrations.
Full-Range Quantitative Cement Bond Evaluation with LWD Sonic: The Right Way of Approach Using a Hybrid of Amplitude and Attenuation
Authors: Izuhara W. , Yamamoto H. , Blyth M. , Saenz E.
Published: October 2017

Cement evaluation plays an important role in determining well integrity, to ensure zonal isolation in a wellbore. Cement evaluation has recently evolved to include Logging-While-Drilling (LWD) sonic tools due to the multiple benefits of LWD logging compared with conventional methods, including tool conveyance, reduced tool eccentering effects, time lapse evaluation, etc. On the other hand, there is an LWD-specific challenge which is the contamination of the casing mode by the drill collar mode. The recent development of the algorithm to use the attenuation through receiver array of both the tool and casing arrivals, gave an initial insight into how to overcome the problem.

We investigated the applicability of a hybrid method using both the signal amplitude and attenuation which was introduced in 2014, and have now further enhanced the processing method. A new processing workflow has been developed to improve the measurement. In the new workflow, the waveform envelope is initially calculated by the Hilbert transform, and the signal amplitude is then evaluated in a time window, in which both casing and collar modes are present. Next, the apparent attenuation rate of the signal across the receiver array is considered. The applicability of the method is validated by an intensive numerical modeling study using finite difference methods (FDM) with detailed tool structures in various casing sizes, mud properties, and cement types. We also conducted a sensitivity study of the apparent signal attenuation to the bonding over the receiver array and the bonding over the transmitter-receiver (TR) spacing, respectively, to identify in which zone of bonding the hybrid method is more sensitive.

Field data examples of quantitative cement evaluation are presented for different LWD tool sizes and casing sizes together with wireline reference to demonstrate the validity of the new method and the suggested quality control processes. All of the results finally prove that the hybrid method using both amplitude and attenuation is the right way for full-range cement bond evaluation with LWD sonic tools.
Losses? No Problem. Unconventional Solutions to Cure Unconventional Losses and Improve Wellbore Instability Problems in Saudi Arabia
Authors: Heinold Thomas , Shine Joseph
Published: October 2017

Saudi Aramco faces a wide array of challenges maintaining wellbore stability during drilling and primary cementing operations. As a result, it has implemented revised strategies and methods to remediate losses during well construction operations. The origin of these strategies, swith some adopted from deepwater operations, has led to improved zonal isolation and operational efficiencies. The conventional methods used to cure losses during drilling with cement plugs can be inefficient usually requiring multiple attempts with mixed success. A revised method focuses on hydrostatics of the cementing fluids as well as advanced placement methods based upon the loss circulation boundary conditions to improve the plug success rate. During primary cementing across multiple zones with risks ranging from ultra-high permeability, low bottom hole pressures, and highly natural fractured carbonates, the risk of losses during cement placement has led to inconsistent zonal isolation. A revised strategy for the cementing fluids used during primary cementing based upon these same risks will demonstrate the improved zonal isolation success. The manuscript details the methods, strategies, and case histories discussed above.