bluuebunny/crossref_metadata_2025 huggingface dataset:
Post-Combustion CO2 WAG Pilot in a Mature Field: Model Calibration and Optimization
Authors: Olalotiti-Lawal Feyi , Onishi Tsubasa , Datta-Gupta Akhil , Fujita Yusuke , Watanabe Daiki , Hagiwara Kenji
Published: October 2018

We present a detailed history matching and process optimization of a CO2 WAG pilot at the West Ranch Field, Texas. The Petra Nova, a 50/50 joint venture between NRG and JX Nippon, operates a commercial scale post-combustion carbon capture facility at NRG's WA Parish generating station southwest of Houston. The industrially sourced CO2 is utilized for EOR in the West Ranch field, which is operated by Hilcorp Energy. A CO2 pilot was conducted to examine the potential for tertiary oil recovery by pattern-scale CO2 flooding and to better understand how pattern flooding will work in the fluvial geology of the reservoir. This paper discusses detailed modeling and history matching of the CO2 EOR pilot at the West Ranch field to understand the CO2 plume movement and optimize the flood design parameters.

For history matching the CO2 WAG pilot, we started by initializing the pilot sector model and imposing multiphase boundary fluxes generated from full-field compositional simulation. The pilot model calibration followed a hierarchical two-step approach. First, we performed a large-scale update of the model permeability distribution by integrating bottomhole pressure and multiphase production data. Next, streamline-based local updates were used to further calibrate the permeability field to match CO2 breakthrough times at the producers. Sensitivity studies were conducted using the calibrated pilot model to evaluate the effects of WAG ratio, CO2 Pore Volume Injected (PVI), number of WAG cycles and Voidage Replacement Ratio (VRR) on the oil recovery efficiency and CO2 utilization factor. Finally, we carried out a multiobjective optimization of the CO2 WAG process based on the influential operational parameters. With this strategy, multiple scenarios that consider the trade-off between the oil recovery efficiency and CO2 utilization factor were generated.

The history matched models capture the major trends observed in the producing Gas-Oil Ratio (GOR), oil production rate and CO2 mole fraction history at the wells. The updated models were independently validated in two ways. First, the models showed good agreement with reservoir saturation logs at two observation wells. Second, the models reproduced the CO2 recovery as a fraction of the injected CO2. These results imply that the history matched models are able to adequately capture the CO2 sweep profile in the pilot area. Sensitivity studies indicate CO2PVI and VRR (Voidage Replacement Ratio) as dominant parameters impacting oil recovery efficiency. The VRR and WAG ratio play a significant role in determining the CO2 utilization factor. A set of optimal operational parameters that utilize these decision variables was generated using a Design of Experiments (DOE) based multiobjective optimization workflow. This work presents, for the first time, modeling and optimization of a field-scale post-combustion CO2 WAG process.
Streamline Tracing and Applications in Naturally Fractured Reservoirs Using Embedded Discrete Fracture Models
Authors: Chen Hongquan , Onishi Tsubasa , Olalotiti-Lawal Feyisayo , Datta-Gupta Akhil
Published: October 2018

The streamline based technology has proven to be effective for various subsurface flow and transport modeling problems including reservoir simulation, model calibration and optimization. For naturally fractured systems, current streamline models are well suited for dual porosity single permeability systems because streamlines need to be traced only for the fracture system. However, complications arise for dual porosity dual permeability (DPDP) systems because streamlines need to be traced for both fracture and matrix systems. Also, the streamlines in the two systems may interact. We present a robust streamline tracing framework for use in the DPDP models via an embedded discrete fracture model (EDFM) framework.

The EDFM models utilize irregular gridding and non-neighbor connections to explicitly represent the discrete facture network. Our strategy is based on a boundary layer method that can be used to honor the fluxes at the matrix-fracture interface during streamline tracing. We generalize our previously proposed streamline tracing algorithms for local grid refinements (LGR) and faulted systems to discrete fracture network models where a fracture gridblock in EDFM is treated as a boundary layer for flux continuity and streamline tracing. The proposed method is benchmarked with a semi-analytical solution and a series of numerical examples encompassing different levels of geologic and geometrical complexity to illustrate the accuracy and robustness of the approach. Visualization of streamlines in complex fracture networks provide flow diagnostics such as sweep efficiency and connectivity of wells and fractures. The streamlines are then utilized to develop a workflow for rate allocation optimization for waterflood in naturally fractured reservoirs. We utilized a streamline-based gradient free algorithm whereby both injection and production rates are adjusted under realistic operational constraints. This approach only requires a few forward simulations and therefore offers significant advantages in terms of computational efficiency. It is confirmed that the optimized schedule provides improvements in oil recovery and sweep efficiency compared to the base scenario with uniform injection and production rates.

The uniqueness of this work is the robust streamline tracing algorithm in the EDFM using a novel boundary layer based approach for flux continuity. The proposed approach is simple and easy to implement and can be coupled with commercial simulators for field scale applications.
A Conceptual Structure to Evaluate Wells Producing Fractured Rocks of the Permian Basin
Authors: Raghavan Rajagopal , Chen Chih-Cheng
Published: October 2018

Pressure- and rate-time data at wells producing the Wolfcamp shale are evaluated by a model based on a framework using subdiffusive concepts. Quantitative measures to estimate heterogeneities in the fracture- and matrix-systems are provided. Multiple transfer mechanisms and complex structures govern the dynamic performance of the reservoir. Long-term depletion is governed by the matrix system; our evaluations indicate that excellent coverage is obtained in draining the lateral extents of the reservoir rock. As a physics-based model is used to evaluate responses, the suggested procedures are both extendable and scalable.
Compositional and Geomechanical Effects in Huff-n-Puff Gas Injection IOR in Tight Oil Reservoirs
Authors: Gala Deepen , Sharma Mukul
Published: October 2018

Lab experiments, field pilots and numerical modeling focusing on fluid flow aspects have indicated that gas injection in tight oil reservoirs is technically feasible. Several operators have conducted pilot tests in the Eagleford and Bakken shales for a Huff-n-Puff IOR strategy with mixed results. Our objective in this work was to study the impact of geomechanical effects, such as permeability changes and opening and closure of fractures during injection and production, on such huff-n-puff processes. We developed a fully coupled geomechanical compositional reservoir simulator to model Huff-n-Puff gas injection for improving liquid recovery in tight oil reservoirs. The simulator solves component mass balances, a suitable equation of state and pressure equations which are coupled with rock deformation and calculates stress changes due to both poroelastic (pressure changes) and mechanical (fracture opening and closing) effects. The phase behavior of the injected gas with a specified composition (which is different from the in-situ reservoir fluid) is accounted for using phase stability and flash calculation algorithms.

We present results from simulations using representative rock and fluid data from an unconventional reservoir and observe the following trends using our simulation studies: (a) Selection of the gas injection rate is very important in order to achieve a substantial pressure increase during the injection period. (b) Geomechanical effects, permeability decrease during increasing effective stress and permeability increase during decreasing effective stress has a significant impact on overall oil recovery. (c) Huff-n-Puff IOR will be more successful in certain reservoirs than in others depending on the composition of the reservoir fluid, saturation pressure, producing GOR and geomechanical reservoir rock properties. Our simulation results provide operators with significant new insights on the design of gas injection IOR processes. It is shown that geomechanical effects during huff-n-puff cycles have a significant impact on oil recovery, particularly if natural fractures and planes of weakness are present. Specifically, several design questions can be answered such as (a) gas injection rates and volumes (b) impact of injection fluid and reservoir fluid composition (c) selection of candidate reservoirs (d) impact of operating bottomhole temperature and pressure.
A Practical Approach to Casing Wear Prediction, Modeling and Mitigation on Challenging ERD Wells
Authors: Dai Weifeng , Noel Brian , Alvord Chip , Njoku Johnson , Hopper Joey , Smith Lee
Published: October 2018

Casing wear caused by rotating drill strings can lead to reduced well life, failed or burst casing strings, and expensive non-productive time (NPT) for remedial actions. In Alaska's Alpine Development field, where logistics are challenging, regulations are strict, and the operational window is small, drilling increasingly long laterals has vastly increased the cost and risk of casing wear, necessitating effective mitigation.

After detailed analyses of Alpine field wells, one operator successfully implemented a casing wear mitigation plan combining new tools, modeling techniques and analyses. The plan required strategic placement of Non-Rotating Protectors (NRPs) based on predicted casing wear, analyzed side forces, and lateral length. Additionally, the operations group wanted to simultaneously improve computer modeling for both casing wear and torque and drag (T&D) analysis.

One major challenge was predicting appropriate wear factors for casing wear modeling. Operational challenges included how to deploy the plan in managed pressure drilling (MPD) operations, where preventing premature wear on rotating control device (RCD) sealing elements had to be considered.

Implementing this casing wear mitigation plan allowed the operator to successfully drill extended reach multilateral wells to planned total depth while keeping wear below maximum allowable thresholds. The paper describes the challenges and approach to predict casing wear, as well as successful mitigation strategies and lessons learned from an extensive offset database. Included are comparisons to field results from casing logs, and several wells that deployed the casing wear mitigation plan, versus an offset well that was drilled without a plan.

The paper describes new techniques for predicting and modeling casing wear which, in combination with utilization of specific tools, results in a readily-applicable approach to wear mitigation in extended-reach drilling (ERD).
An Experimental and Simulation Investigation on the Effect of Different Gas Mixtures on Performance of Miscible CO2 Injection in HPHT Abu Dhabi Reservoir
Authors: Alshuaibi Muataz , Farzaneh Seyed Amir , Sohrabi Mehran
Published: October 2018

The carbon dioxide flood represents one of the proven enhanced oil recovery methods. However, there are significant challenges associated with applying CO2 flood in onshore or offshore reservoirs. One of the common problems is a limited supply of CO2. Therefore, recycling and re-injection of the produced gas should be considered in many applications especially in the case of giant carbonate reservoir in the Middle East. In this work presented here, we performed a comprehensive series of slim-tube and phase-behavior experiments coupled with numerical simulation to explore the effect of the mixture of non- hydrocarbons and hydrocarbon gases with CO2 on the behavior and the performance of the gas flooding process.

This study involves a series of slim-tube experiments to identify the MMP of CO2 and different mixture of gases namely N2, C1, and C2. Moreover, mixing cell experiments were also performed to calibrate phase behavior models based on crude oil and injected gas interaction in a PVT cell. Furthermore, full compositional analysis of the produced oil and gas for both slim-tube and phase-behavior experiments were carried out to better understand the dominant mechanism of the injected gas at different conditions. Besides, the experimental results were employed as a benchmark against the numerical 1-D simulations which was based on the tuned EOS with advance PVT experiment's to predict the impact of different mixtures on the MMP.

The experimental results of CO2 with a different gas mixture of up to 20% were shown that the attribution of N2 and C1 in increasing the MMP in both dead and live oil systems and N2 has the highest impact on increasing the MMP. The results of the gas chromatography analysis of the produced gas clarified that there was an interaction between the injected gas and the crude oil in which a bank of immiscible light hydrocarbon gases created at the miscible front. The composition of C1 in the produced gas was decreased from 70% at CO2 BT to 31% at the end of the experiment. Therefore, when CO2 recycling was considered, the concentration of CO2 will be decreased, and miscibility between the oil and CO2 required much higher MMP. However, the CO2 extract oil components (C1 up to C30) which contribute to leaving heavier oil behind. The miscibility of remaining oil was achieved but at very high pressure due to the non-existence of light components. The results of 1-D slim-tube simulation have shown a promising result in predicting MMP of the performed experiments.

The result of the study demonstrated the potential of lowering the cost by design a mixture of CO2 with hydrocarbons and non-hydrocarbons gases instead of injection high purity CO2. Although, this study contributes to understanding the mechanism of the process of CO2 injection when recycling and reinjection are considered.
Design of Offshore Production Systems Considering Uncertainties
Authors: Sales Leonardo de , Morooka Celso Kazuyuki
Published: October 2018

The development of an offshore oil field is a complex and risky project. One core problem in this task is the selection of a production system that maximizes oil recovery and minimizes investments and operational costs while meeting external, economic, environmental, societal and technological demands in a scenario of uncertainties. Several studies address this problem in the literature; however, they do not consider uncertainties in the initial data neither justify objectively the chosen alternative among other feasible ones. We propose to select an offshore production system using an intelligent system that considers input uncertainties and chooses the best alternative in a rational manner. By comparing the results obtained with previous studies and real scenarios, we conclude that our methodology can obtain the optimal solution in situations where other methods cannot.
A Method to Measure Ultralow Permeabilities of Shale Core in Multiple Directions Using Pressure-Pulse Decay Technique
Authors: Yang Zehao , Bryant Steven , Dong Mingzhe
Published: October 2018

Permeability is a very critical tight reservoir parameter to characterize the process of oil/gas storage and production. In particular, distinct anisotropy of the shale reservoir, demands a practical method to measure permeabilities in multiple directions using the same core.

In this work, a systematic and practical pressure-pulse decay (PPD) technique is given to determine ultralow permeabilities of shale reservoir core in a cell with finite volume. The test gas can be non-adsorption gas such as helium or adsorption gas such as methane.

As described herein, given appropriate assumptions, the mathematical models based on the corresponding designed experiments (non-adsorption gas or adsorption gas) are formulated, and the exact solutions for the corresponding mathematical models are proposed using Laplace transform. Approximation techniques are further given to analyze experimental data to obtain radial and axial permeabilities. It is found that there are distinct anisotropy of shale reservoir and the permeability may be smaller when adsorption gas is used instead of non-adsorption gas.

Compared with traditional two-chamber PPD techniques, its advantages mainly lie in three points: only the pressure in one chamber is measured, which can lead to fewer pressure transducers and easier experimental operation. Meanwhile, the center of shale core needs not be drilled when the radial permeability is measured. What's more, the whole measurement is based on the same core and more information of the core can be obtained. However, it should also be noted that there is about 1 MPa difference of effective stress between our axial experiments and radial experiments. The effect of this difference on permeability is typically less than 5%, so the modified PPD can detect anisotropy efficiently.
Quantitative Integration of 4D Seismic with Reservoir Simulation
Authors: Ketineni Sarath Pavan , Kalla Subhash , Oppert Shauna , Billiter Travis
Published: October 2018

Standard history matching workflows use qualitative 4D seismic observations to assist in reservoir modeling and simulation. However, such workflows lack a robust framework for quantitatively integrating 4D seismic interpretations. 4D or time-lapse seismic interpretations provide valuable inter-well saturation and pressure information and quantitatively integrating this inter-well data can help to constrain simulation parameters and improve the reliability of production modeling. This paper outlines technologies aimed at leveraging the value of 4D for reducing uncertainty in the range of history matched models and improving the production forecast.

The proposed 4D Assisted History Match (4DAHM) workflows utilize interpretations of 4D seismic anomalies for improving the reservoir simulation models. Design of Experiments (DOE) is initially used to generate the probabilistic history match simulations by varying the range of uncertain parameters. Saturation maps are extracted from the Production History Matched (PHM) simulations and then compared with 4D predicted swept anomalies. An automated extraction method was created and is used to reconcile spatial sampling differences between 4D data and simulation output. Interpreted 4D data is compared with simulation output, and the mismatch generated is used as a 4D filter to refine the suite of reservoir simulation models. The selected models are used to identify reservoir simulation parameters that are sensitive for generating a good match.

The application of 4DAHM workflows has resulted in reduced uncertainty in volumetric predictions of oil fields, probabilistic saturation S-curves at target locations, and fundamental changes to the dynamic model needed to improve the match to production data. Results from adopting this workflow in two different deep-water reservoirs are discussed. They not only resulted in reduced uncertainty, but also provided information on key performance indicators that are critical in obtaining a robust history match. In the first case study presented, the deep-water oil field 4DAHM resulted in a reduction of uncertainty by 20% in OOIP and by 25% in EUR in the P90-P10 range estimates. In the second case study, 4DAHM workflow exploited discrepancies between 4D seismic and simulation data to identify features necessary to be included in the dynamic model. Connectivity was increased through newly interpreted inter-channel erosional contacts, and sub-seismic faults. Moreover, the workflow provided an improved drilling location which has the higher probability of tapping unswept oil and better EUR. The 4D filters constrained the suite of reservoir simulation models and helped to identify 4 out of 24 simulation parameters critical for success. The updated PHM models honor both the production data and 4D interpretations, resulting in reduced uncertainty across the S-curve and, in this case, an increased P50 OOIP of 24% for a proposed infill drilling location, plus a significant cycle-time savings.
Improved Reservoir History Matching and Production Optimization with Tracer Data
Authors: Chen Hsieh , Poitzsch Martin E.
Published: October 2018

Interwell tracers have been shown to provide invaluable information about reservoir dynamics, well connectivity, and fluid flow allocations. However, tracer tests are often applied sporadically because their immediate returns of investments are not readily apparent to a resource-holder. Here, we rigorously demonstrate that tracer data can indeed improve reservoir history matching, and, more importantly, improve future production, using reservoir simulations on benchmark problems. Sensitivity studies and the limitations of tracer data are also provided.

The numerical experiments were divided in two sections. First, production data with or without tracer data from reference fields were collected for the first water flooding periods for history matching. Second, the history matched models from the first section were used for production optimization for the next water flooding periods. The ensemble smoother with multiple data assimilation (ES-MDA) was used for the history matching processes for the first part of the numerical experiments, and the modified robust ensemble-based optimization (EnOpt) was adopted to maximize the net present value (NPV) for the second part of the numerical experiments.

The three-dimensional channelized "Egg Model" was chosen as the initial benchmark problem. From the first part of the numerical experiments, using the same hyper-parameters, it was observed that history matching including tracer data resulted in a better match of the field production rates with smaller standard deviations. In addition, history matching including tracer data resulted in more distinct geological features when observing the history matched permeability maps. From the second part of the numerical experiments, we observed that the geological models history matched including tracer data resulted in better production optimization with higher NPV produced. In the specific case of the Egg Model, +4.3% increase of the NPV was observed.

To understand the sensitivity and the limitations of the tracer data, the same numerical experiments were performed on a library of reservoir models with different fracture patterns. After the history matching and production optimization simulations, we observed that including tracer data gave positive NPV increases ranging from +0.3% to +9.4% from 5 of the 7 test cases. It was observed that tracers were more effective for the non-homogeneously flooded reservoirs.

To the best of our knowledge, this paper is the first study that quantifies the benefits of tracers in the context of the improved production, measured in NPV. In a broader perspective, we believe this is the best way to test any new history matching algorithms or reservoir surveillance methods. In this work, we show that tracers can result in positive NPV in most situations, and oil producers using large-scale water flooding operations would benefit from performing more tracer tests in their operations.
Enabling Collaborative Decision Making Through Immersive Visualisation
Authors: Helm Paul , Pickering Julian
Published: October 2018

Objectives/Scope

Virtual Reality (VR) and Augmented Reality (AR) are becoming increasingly popular in many industrial sectors but the uptake in oil and gas has, in comparison, been very modest. There is little doubt that these technologies will have a growing influence in our recreational lives over the next few years, as the hardware capability increases, costs decrease, and applications become more widely available. The real strength of these technologies is their capability to disseminate information to the user in a truly immersive experience. One area where this could be very valuable in our industry is in the support of drilling and production operations. Real-time Operations Centres (RTOCs) are now in widespread use but these suffer from high capital and operating costs, they are difficult and expensive to reconfigure and are often difficult to engage with from a remote location. Conversely, a Virtual Real-time Operations Centre (vROC) is low cost, can be configured quickly and decommissioned readily when no longer required. With modern networking configurations it is easy to connect from anywhere. This paper describes the first developments of a vROC.

Methods, Procedures, Process

A common understanding or shared situational awareness is essential for making the best operational decisions in the shortest possible time. This has been the main driver for the development of collaborative working and has resulted in the development of a wide range of work spaces ranging from smaller Collaborative Work Environments (CWEs) through to large scale RTOCs and interactive visualisation centres. The vROC replaces the need for the user to relocate to these physical areas. By deploying a 3D headset, they can enter the 3D virtual workspace and work with colleagues in true collaboration. This project has enabled data to be visualised within the workspace in the same way that it would be seen in a physical room with conventional display panels.

Results, Observations, Conclusions

This project is in the early stages of development, but it has shown already how quickly a vROC may be configured and populated with live and historical data from different sources. Using 3D CAD models, photogrammetric representations and other spatial data, process plants, reservoirs and wells can be brought into the vROC, annotated with real time data and experienced by all users. We have developed live trends and have animated models to highlight alarm situations.

Novel/Additive Information

At a time when operators need to minimise their operating costs whilst maintaining top performance the use of virtual work environments is likely to become a major contributor to cost savings.
Geological Heterogeneity in Geological Models - A Review of the Impact of Available Data, Modeling Parameters, and Modeling Workflow on Primary Recovery, Waterflooding, and Steamflooding Projects
Authors: Meddaugh W. Scott , Meddaugh Andrew J.
Published: October 2018

Reservoir modeling and the derived fluid production over time curves are a key part of the workflows associated with major capital project decisions. These models may be very complex and use a variety of geological constraints in an effort to develop the porosity, permeability, and saturation distributions used in dynamic models (with or without upscaling). Over time and partially in response to increased computing capability as well as the need for more realistically heterogeneous models, model size as measured by number of model cells and model complexity has increased but model-derived production forecasts remain optimistic. This paper, one of a series that now stretches back over a decade, addresses a number of modeling issues with the goal of (1) better understanding how modeling workflows may contribute to forecast optimism and (2) what reservoir modelers, both geologists and engineers, may do to reduce forecast optimism derived from their subsurface models by improved understanding of how model parameters such as grid size, number of grid cells, semivariogram parameters (e.g. the range), and number of geological/stratigraphic "control" surfaces used to constrain models. Adequate modeling of reservoir heterogeneity appears to require very to extremely large models (e.g. large number of small cells). Many of the parameters used to "control" heterogeneity including the semivariogram range parameter, the number of "detailed" stratigraphic layers, and the number of rock/facies "containers" or model regions appears to have only a small impact on forecast recovery.
Temperature Logging Guidelines and Factors that Affect Measurement Accuracy
Authors: Adnyana Gede , Sharma Jyotsna , Mims Don , Barnes David , Behrens Ron
Published: October 2018

A robust reservoir surveillance program is the key to successfully managing a steamflood operation. Observation wells allow us to directly monitor changing reservoir conditions throughout the life of the steamflood using time lapse surveys. Temperature surveys are a primary data type collected from the observation wells to evaluate the reservoir heating, and to monitor the steamchest. Thus, accurate measurement and proper interpretation of temperature surveys is essential for steamflood management.

The objective of this study was to look at factors that can impact a temperature log and steps that can be taken to improve temperature measurement accuracy. Several field examples are presented to illustrate the effects of logging speed, steamchest temperature, sensor type and wellbore fluid on recorded temperature data. Guidance on evaluating and interpreting different temperature signatures such as, interpretation of liquid level in an observation well, understanding temperature signatures in air, wellbore reflux phenomenon, and examples of logs from malfunctioning logging tools, are also provided. The main purpose of this work is to aid both the operators and the service companies to gather accurate temperature data for improved steamflood management. This study is based on an extensive study of field data, primarily gathered from a single company's steamflood operations in California (using over 1000 temperature observation wells). Additionally, an analytical model was developed based on reservoir heat transfer and the sensor response mechanism to understand the impact of steam chest temperature, logging speed and sensor response time on the accuracy of the temperature log data. Results from the analytical model support the field observations.

Field data and analytical assessment show that several factors can impact the accuracy of a temperature log, which can subsequently affect our interpretation and operational decisions. Data suggests that higher logging speeds introduce greater error in measured temperature data and these errors are greater at elevated steamchest temperatures. Temperature tools with longer sensor response times need to be run at slower logging speed to get accurate measurements. Ensuring adequate level of thermally equilibrated liquid (typically water) in the observation well is essential both, for gathering accurate data and to mitigate possible safety concerns for the logging operator. The examples and guidelines provided in this study will aid the practitioners to improve the gathering and interpretation of temperature log data.
Numerical Evaluation of Plastic Strains in Coiled Tubing Surface Flaws for Comparison to Analytical and Emperical Models
Authors: Kilambi Sreelatha , Tipton Steven M.
Published: October 2018

Coiled tubing (CT) endures cyclic bending strains on the order of 2 – 3% during its normal operation. Consequently, fatigue is the major factor limiting its useful life. Furthermore, CT is routinely subjected to gouges or defects due to harsh oil field environments. Assessing the stress and strain at the root of the defects, is essential to estimate the influence of flaws on CT fatigue life. This is physically difficult to accomplish experimentally due to the small defect size and limited access to the flaw during testing. Therefore, FEA is conducted on CT samples with and without flaws of realistic size and shape. These results are used to assess the validity of conventional notch strain analysis techniques.

Conventional notch strain analysis models have long been used to estimate localized notch root strains. This paper investigates applicability of conventional notch strain analysis under bulk plasticity situations for CT.

This paper presents a comparison of Neuber's rule and Glinka's strain energy density approaches, along with an empirical model developed to estimate notch root strain for CT applications.
Zero Wellsite Personnel. The First Truly Man-Less Operation for Directional Drilling Services
Authors: Chatar Crispin , Stepnov Alexey , Mardyashov Anton , Fedotov Viacheslav
Published: October 2018

Years of effort, knowledge, innovation, and process integration resulted in the first unmanned remote operation where the drilling services company completed the directional drilling contract without any physical presence of personnel on the rig. In addition, the company has successfully run these remote operations across multiple continents. An opportunity presented itself to the global drilling community to drill a well where it was deemed unsafe for human operations. Building on prior successes in remote operations, a relevant solution was provided that could be executed anywhere on the Earth remotely from any other location. The evolution of remote drilling operations began in 2009, the most significant result of which occurred in 2016 when for the first time, a well was drilled without any directional services staff even visiting the drilling rig. This operation was the result of more than 8 years of foundation work.

This paper will present three main concepts for any future efforts in this drilling area. Due to the need for maintaining the drilling company's strategic advantage, not all of the details will be explored. The process and procedures used to accomplish the remote operations will be summarized, followed by a brief update on the history of remote operations. Secondly, a description if remote operations in directional drilling, intercontinental remote operations, and unmanned directional drilling operations will be presented. Finally, tools and technologies to accomplish these goals will be summarized in a suitable manner for the industry to build on to take remote operations to the next level. The main goal of this paper will be to highlight what was achieved with current technology and predict the future of area of the industry. This paper will divulge many industry firsts; unmanned directional drilling jobs, unmanned logging-while-drilling (LWD) jobs, intercontinental remote operations, and finally, for the first time, operations where the service company never visited the rig.
Enhanced Flux Management for Sand Control Completions
Authors: Cameron John , Zaki Karim , Jones Colin , Lazo Antonio
Published: October 2018

A probabilistic flux and erosion model and workflow has been constructed to estimate the inflow through sand screen on a foot by foot basis along the wellbore using the completion details, production rate, and reservoir and bottom hole flowing pressures. The model is then calibrated & history matched using well data from pressure transient analyses, well test and production logs as available. Extensive laboratory testing coupled with computational flow dynamics modelling provided the algorithms for a number of different screen types to relate flux and sand production to the expected service life for any given future production profile. This allows the well's planned production profile to be optimized by balancing risk, rate and reserves recovery.
Osmosis and Clay Swelling Effects in Gas Shale Formations under Stress
Authors: Eveline Vena F. , Akkutlu I. Yucel
Published: October 2018

Water-shale interactions are traditionally perceived as complex phenomena due to reactive nature of shale with water. However, the current trends in shale gas industry requires an advanced-level of understanding of these interactions and their impact on gas production. In this paper we investigate the invasion of fracturing water into the formation and the subsequent water-shale interactions. Objective of this work is to study osmosis and clay swelling effects of the invasion on the formation permeability.

For this purpose, a new geomechanically-coupled reservoir flow simulator is developed, which accounts for water imbibition, osmosis and clay swelling effects on the formation permeability under stress. The simulation model considers the formation has a multi-scale pores consisting of microcracks, clay pores and organic pores. Water imbibition occurs in the water-wet inorganic part of the matrix in the microcracks. Osmosis and clay swelling effects develop in the clay pores acting as semi-permeable membrane to the imbibed water and changing the local stress in the formation. The simulation model includes aqueous and gaseous phases with three components: water, gas and salt.

The simulation results show that the formation permeability is dynamically affected during the shut-in period by a combination of mechanisms including imbibition, capillarity, diffusion/osmosis, and total stress. Notably, a permeability impairment zone, rather a fracture skin, develops near the fracture. The permeability alteration is due to osmosis-related clay swelling and changing stresses in the formation. The magnitude of the permeability alteration is controlled mainly by the salt concentration difference between the fracturing fluid and the clay-bound water, the clay-membrane efficiency, the clay cation exchange capacity (CEC), the clay porosity, the stress and the duration of the shut-in time. We develop a fracture skin factor that can be used with the single-phase (gas) shale reservoir flow simulators that are typically run in the absence of water invasion at the scale of the stimulated reservoir volume (SRV) and in multidimensional geometries.

Currently there is a clear need in the unconventional industry to better-understand and control the hydraulic fracturing fluid-shale interactions. This work is an important milestone considering the complexity of the problem and suggesting that the water chemistry and the formation lithology plays a significant role after the fracturing operations.
Evaluation of New Viscoelastic Surfactant Systems in High-Temperatures Carbonates Acidizing
Authors: Ibrahim Ahmed Farid , Nasr-El-Din Hisham , Paulo Jaqueline de , Ewbank Conrado , Poltronieri Olívia Cueva
Published: October 2018

Viscoelastic surfactants (VES) have been introduced as acid divergent agents for easier cleaning and mixing advantage over in-situ gelled acid systems. Thermal stability and compatibility with the other additives, such as corrosion inhibitors, are the main problems with conventional VES. This work introduces five VES-based acid systems for diversion in matrix acidizing.

A series of VES samples were developed, hereinafter named samples A, A1, B, C and C1 according to their chemical composition, and evaluated for various applications. The initial screening was conducted by viscosity measurements of the spent acid system at 150°F and shear rates of 10 and 100 s−1. The effects of different corrosion inhibitors on the viscosity of the selected VES were then examined. The viscosity of the VES system was then measured as a function of temperature (77 to 300°F) and shear rate (10 and 100 s−1) to evaluate thermal stability. The diversion characteristic of the VES systems was evaluated with single core flood experiments on Indiana limestone cores with a permeability range of 10-200 md. CT-scan imaging of the cores after the acid treatment was used to evaluate the structure and the propagation of the wormhole. Dual coreflood experiments were conducted on Indiana limestone cores with permeability contrast of 1.5-50 to examine the ability of the VES to divert the acid system on heterogeneous limestone formations.

Phase separation was observed during the preparation of the systems with a samples C and C1 VES samples. High viscosity was found in the case of A and B VES systems with the viscosity of 2,500, and 350 cP at 10 and 100 s−1, respectively, at 150°F. The viscosity of the Sample A1 and B VES systems were not affected by the tested corrosion inhibitor. The single coreflood experiments revealed the ability of the VES to divert the acid system. The breakthrough injected acid volumes were 0.7 and 0.6 in the case of Sample A1 and Sample B, respectively. The wormhole tortuosity was 1.8 in sample A, compared to 1.4 in Sample B.

This work introduces VES systems with superior divergent ability and viscosity measurements at high temperature even when in contact with the other acid additives, which leads to less acid spending and better wormhole structure.
Activating Shale to Form Well Barriers: Theory and Field Examples
Authors: Kristiansen Tron Golder , Dyngeland Torill , Kinn Sigurd , Flatebø Roar , Aarseth Nils Andre
Published: October 2018

Shale is a general term used for argillaceous (clay-rich) rocks which are the most abundant sediment on the earth. It is believed that clay rich rocks comprise more than 50-75% of the geologic column. Shale has very varying petrophysical and mechanical properties. Shale is in the most cases acting as a trap or seal for hydrocarbon migration, but has also in more recent years been targeted as a reservoir target in some basins. In some wells it has been observed on cement bond logs that shales in uncemented intervals have moved in and closed the annulus. Pressure communication testing has been performed on these sections and the sections has been qualified as well barrier elements (Williams et al., 2009) for plug and abandonment (P&A) purposes. The main mechanism behind the deformation process is believed to be shale creep.

In this paper we will discuss shale creep and other shale deformation mechanisms and how an understanding of these can be used to activate shale that has not contacted the casing yet to form a well barrier. We have developed a numerical model based on first order principles to better understand the mechanical deformation process. We are also supporting the modeling results with laboratory experiments, before we discuss a couple of field cases where shale intervals have been activated and verified to have formed a well barrier as part of the well construction process in new wells.
An Assessment of the Physical and Mechanical Properties of Foamed Cement Generated at a Field Site vs. Laboratory
Authors: Spaulding Richard , Kutchko Barbara , Haljasmaa Igor , Fazio Jim
Published: October 2018

The objective of this paper is to evaluate the physical and dynamic mechanical properties of foamed cement generated at a field site and compare them to similar cements fabricated within the laboratory. Physical and mechanical properties such as porosity, permeability, Young's modulus, Poisson's ratio, bulk modulus, shear modulus, etc. will be discussed. Mechanical properties were obtained under cyclic confining pressures ranging from 12 – 52 MPa. This paper will document the final results of a long-term project that examined the differences between foamed cements generated with laboratory equipment and field foamed cementing equipment. The cement samples in this study were generated at pressure using field foamed cementing equipment as part of a joint effort between the API Sub-Committee 10 and the National Energy Technology Laboratory (NETL). The samples were characterized using helium porosimetry, ultrasonic velocity, and permeability measurements after they were depressurized. To test the variation in permeability and strength parameters of various foam cements, stepwise loading and unloading experiments were conducted. Effective pressures varied between ≈6.8 MPa to ≈46 MPa in ≈4 MPa increments. Permeability was measured at each effective pressure step to determine the change in flow pathways due to cyclic confining pressures. Dynamic moduli including Poisson's ratio and Young's modulus were calculated to determine the impact of effective pressures on the flexibility of the cement. The data shows that the cement's physical and mechanical behavior varied along the length of the sampling containers. During the initial loading of some of the samples, permeability decreased to a point lower than the initial permeability and stayed constant for the remainder of the pressure cycle, which was observed in previous experiments. However, some of the permeability values increased suggesting that the pressure cycles had permanently reconfigured the internal structure of the samples. Our approach to evaluating foamed cement is somewhat novel in that we have collaborated with the API, operators, and service companies, to obtain foamed cement generated at pressure using field equipment enabling a robust comparison to those generated in a laboratory per the API's RP 10-4B. Not only will the information provided by these comparisons help to facilitate the better design and implementation of foam cement generation processes but it will also help improve the understanding of the physical and mechanical behavior of foam cement.
Look-Ahead Vertical Seismic Profiling VSP Inversion Approach for Density and Velocity in Bayesian Framework
Authors: Daoud Ahmed M. , Abd El Dayem Muhammad A.
Published: October 2018

To reduce drilling uncertainties, zero-offset VSPs can be inverted to quantify acoustic properties ahead of the bit. In this work, we propose an approach to invert VSP corridor stacks in Bayesian framework for look-ahead prediction. The implemented approach helps to successfully predict density and velocity using prior knowledge from drilled interval. Hence, this information can be used to monitor reservoir depth as well as quantifying high-pressure zones, which enables taking the correct decision during drilling.

The inversion algorithm uses Gauss-Newton as an optimization tool, which requires the calculation of the sensitivity matrix of trace samples with respect to model parameters. Gauss-Newton has quadratic rate of convergence thus ensure speeding up the inversion process. Moreover, geo-statistical analysis has been used to efficiently utilizes prior information supplied to the inversion process. The algorithm has been tested on synthetic and field cases. For the field case, a zero-offset VSP data taken from an offshore well was used as input to the inversion algorithm. Well logs acquired after drilling the prediction section was used to validate the inversion results.

The results from the synthetic case applications were encouraging to accurately predict velocity and density from just a constant prior model. The field case application shows the high strength of our proposed approach in inverting VSP data to obtain density and velocity ahead of a bit with reasonable accuracy.

Unlike the commonly used VSP inversion approach for acoustic impedance using simple error to represent the prior covariance matrix, this work shows the importance of inverting for both density and velocity with using geo-statistical knowledge of density and velocity from the drilled section to quantify the prior covariance matrix required during Bayesian inversion.