bluuebunny/crossref_metadata_2025_split huggingface dataset:
Water-Swellable Elastomers for Heavy Brine Environments
Authors: Wang Xiao , Sadana Anil K. , Mathur Vipul 
Published: September 2015

Abstract
Swellable packers are widely used to create annular seals between production casing and an open hole. The popularity of swell packers is due to their ease of deployment and streamlined design, which does not have moving parts to malfunction. The current water swell packer technology meets the swelling requirement in light monovalent brines, however, falls short of swelling requirements in heavy brines and especially divalent brines like CaCl2 and CaBr2. This work/paper presents the development of new swellable elastomers that exhibit superior swelling in divalent brines and enhanced mechanical properties compared to existing swellable compounds.
New swellable elastomers are made by blending newly developed swellable nanocomposite microgels with nitrile butadiene rubber (NBR). Nanocomposite microgels possess a unique polymer/nano-clay network structure in which nano-clay acts as a multifunctional cross-linker and leads to the formation of higher molecular weight polymer chains. As a result of the unique structure, the nanocomposite microgels exhibit better elastomeric behavior, higher swelling ratio and faster swelling kinetics compared to the conventional super absorbent polymer (SAP). The nanocomposite microgels were synthesized through the reverse-phase suspension polymerization method to achieve a gel particle size of less than 10 μm, which is essential for the fast swelling rate of the compound. A divalent brine-tolerant 2-acrylamido-2-methylpropane sulfonic acid (AMPS) monomer was selected for the synthesis to achieve divalent brine-swelling capability.
The new swellable elastomers exhibit a 100% volume increase within three days in 10% CaCl2 at 200° F, and a final volume swell of more than 200% for a 1-in. button sample. This volume swell of the button sample is four times higher than the current water swellable elastomers. The new swellable elastomers also exhibit better mechanical properties than current swellable compounds.
Newly developed swellable elastomers made by incorporating novel nanocomposite microgels in the base polymers offer swellable packers for heavy brine environments.
Integrated Production Logging Approach for Successful Leak Detection Between Two Formations: A Case Study
Authors: Al-Mulhim Abdullah , Al-Thwaiqib Ibrahim , Bogari Abdulkader , Bawazir Mustafa , Abdein Moutaz 
Published: September 2015

Abstract
A major exploration and production (E&P) company is acquiring a significant number of multiphase production logs a year for reservoir management. It is anticipated that this number will increase, when these deviated and horizontal wells start to produce water. It is more challenging when these wells become dead due to downhole communication between an aquifer and the objective reservoir resulting in excessive downhole water dumping. The strategy, therefore, is to run advanced production logging tools (APLT) integrated with the pulsed neutron logging tool (PNLT) to provide velocity along with holdup maps across the diameter of the borehole from an array of sensors and water velocities inside the wellbore or the annulus, respectively. The combination between APLT and PNLT data provides accurate detection and quantification of water zonal contributions.
The aim of the three case examples presented in this paper is to facilitate detecting the leak point and assembling the inflow profiles. The first example is an open hole completion. The logging data showed 1000 bbl of down-flow movements in the tubing-casing annulus (TCA) starting from the shallow aquifer. The second well was completed with an inflow control device (ICD). Water dumping was observed from the leak over the blank pipe down to the screen interval, which is also supported by temperature deflection. The third example is a cased-hole perforated completion. An integrated logging approach yielded reliable results in detecting the water entry interval, and the water entry was identified from the perforated section flowing upward to the casing leak. This detected crossflow in the mentioned examples at shut-in conditions was the reason that the wells were dead.
The established integrated logging solution and field examples showed evidence that a leaking interval was suspected to be responsible for high water cut, reducing well performance and killing the wells. The source of water production identified provides the justification for a workover to isolate the water entries, secure the objective reservoir, and revitalize the dead well.
Optimizing Unconventional Asset Development and Reserves Confidence With Portfolio Tradeoff Analysis
Authors: Kostuik K. , Mu Y. , Parma R. , Wearly J. , Rooney K. 
Published: September 2015

Abstract
A multi-objective optimization algorithm was used to develop five-year capital plans for a portfolio of unconventional assets. The approach explored development plan tradeoffs, while considering statistical uncertainty of reserves additions. The objective was to apply the theory of multi-objective methods to an existing planning model, and to evaluate if such methods can provide greater knowledge, faster analysis, and better solutions.
The tradeoff analysis workflow applied recent advances in constrained multi-objective optimization. A hybrid optimization algorithm, combining elements of mathematical programming and evolutionary computation, was used to calculate tradeoff frontiers under varying assumptions and constraints. Portfolio metrics included net present value, capital, reserve replacement ratio, capital effectiveness, production, reserves, and well counts. Statistical metrics were used to calculate uncertainty bounds (P10 and P90) on portfolio reserves additions, plus confidence factors for achieving given reserves targets. Constraints on drilling activity by area over time were also applied.
The optimization algorithm successfully calculated tradeoff frontiers and efficient portfolios. The approach showed how tradeoff frontiers change with varying assumptions and constraints, and provided knowledge of strategic opportunities and limitations. The model enabled rapid replanning as objectives, constraints, and source data changed. The optimizer delivered better solutions than the previous planning model, and helped to identify short lists of optimized capital plans faster than otherwise possible. Reserves uncertainty metrics quantified the tradeoff between reserves targets and reserves confidence. The analysis revealed weaknesses of published uncertainty methods, and highlighted possible improvements for future research.
Root Cause Analysis of Drilling Lost Returns in Injectite Reservoirs
Authors: Buechler Scott , Ning Jing , Bharadwaj Nidheesh , Kulkarni Kaustubh , DeValve Caleb , Head Timothy , Mols Arnout 
Published: September 2015

Abstract
Identifying the root cause of drilling failures can often be challenging due to uncertainty in whether drilling failures were a result of lost returns leading to borehole instability and pack off, or ineffective hole cleaning leading to lost returns, pack off, stuck pipe, and eventual well failure. Such an analysis is further complicated when losses occur over a wide range of equivalent circulating densities (above and below predicted fracture gradients), well angles, and hole sizes. The work presented combines a fundamental physics approach with field data to identify the root cause of drilling failures in Paleocene and Eocene injectite sand intervals. The field data consisted of image and conventional log data, downhole equivalent circulating densities (ECD), loss rates, leak off tests, and formation integrity tests. Study results showed that unfavorably oriented sand-shale interfaces, which can occur more frequently at the top of an injectite reservoir, can re-open at ECDs below predicted fracture gradients, but above the minimum stress, and result in massive losses. The physical model is shown to correlate well with field data supporting the conclusion of lost returns being the root cause for observed drilling failures. Complimentarily, proprietary transient hydraulics and hole cleaning models showed that fluctuations in drilling parameters (flow rate, ROP, etc.) leading to suboptimal hole cleaning at a specific location along the wellbore were not able to generate significant enough pressures to result in observed losses if ECD at the bit was managed within the anticipated fracture gradient. By identifying the root cause of drilling challenges, potential solutions can be applied to include revised fracture gradients, operational hole cleaning parameters, drilling techniques, and well path planning to reduce overall drilling risk. These results will allow for informed trade-offs between reduced drilling risk and future production volumes.
Functional Approach to Data Mining, Forecasting, and Uncertainty Quantification in Unconventional Reservoirs
Authors: Grujic Ognjen , Da Silva Carla , Caers Jef 
Published: September 2015

Abstract
The difficulty in applying traditional reservoir simulation and modeling techniques for unconventional reservoir forecasting makes the use of statistical and modern machine learning techniques a relevant proposition for shale systems. However, the most current applications of these techniques often ignore the systematic time variations in production decline rates. Traditional decline curve modeling techniques fall short in predicting actual physical parameters and are highly dependent on the assumed physical model.
In this paper, we propose a non-parametric statistical approach, more specifically, using a modern technique termed functional data analysis (FDA). In FDA production data is modeled as a time series composed of a sum of weighted smooth analytical basis functions. Instead of assuming a model, this technique allows us to learn the model from the data by jointly fitting all production profiles in the field. Principal component analysis can be applied to the functional data, termed (fPCA). Applying fPCA to declining rates from many wells, transforms time varying data into lower-dimensional score data. We found that in the real field data studied, 2-3 such functional principal components were sufficient to describe the entire production in a shale play. Low dimensional score data is also very valuable for data mining and sensitivities studies that enable better understanding of production drivers. Finally, building regressional relationships between geological and completions parameters and functional principal component scores enables forecasting production at new well locations with new sets of geological and completion parameters.
Proposed methodology is demonstrated on a real reservoir case study with 172 horizontal and hydraulically fractured wells. Wells originate from one of the most prolific shale plays in North America, and have been in production for at least 500 days. Case study was focused on oil production rates, and obtained forecasting error over multiple test sets (100) was 21% (on average).
Development Best Practices in the Duvernay Liquid Rich Shale - Early Stage Sensitivity Analyses and Comparative Economics for Decision Making
Authors: Braun David , Gurden Catherine , Yang Wu , MacGregor Alex 
Published: September 2015

Abstract
To maximize the development value of the emerging Canadian Duvernay liquid rich shale (LRS) play quality risk-based decisions need to be made. These decisions must consider a number of complex variables that can all have a high impact on both short and long term economic viability. Credible ranges for variables such as well construction costs, production decline rates, infrastructure configurations, and commodity prices (e.g. oil price volatility witnessed in 2014) must be built. Quality decisions can then be made by leveraging a detailed understanding of the variables’ interdependencies and quantified economic impacts.
This paper describes the construction and analysis of a suite of Duvernay scenarios developed by Shell Canada using sophisticated hydrocarbon planning software. They were built using a strategy table approach and focused on options for gas processing facilities. The impacts of drilling ramp-up timing, shallow cut versus deep cut configurations, and operator versus midstream build-own-and-operate (BO&O) were examined. For example, several midstreamers exist in the Duvernay play area with significant, non-optimal (sour and shallow cut) processing capacity. These facilities can be used today to capture initial value but require expansion in the future; therefore, an evaluation of all credible new build options is required to understand how best to develop the play.
A suite of key comparative economic metrics, including net present value (NPV), profit to investment ratio (PIR), and payout period (POP), was generated. Expected monetary values (EMV) for each scenario were calculated and used to identify the optimal, risk-based approach. Additional insights were derived by comparing the scenarios, these insights included: the value of information associated with a longer appraisal period, the value of infrastructure flexibility, and the NGL recovery and product price thresholds required to justify deep cut construction.
Is Pumping Large Volume Sand Frac Treatments Sustainable?
Authors: Shelley Robert* P. , Shah Koras , Guliyev Nijat , Mohammadnejad Amir , Sheludko Stanislav 
Published: September 2015

Abstract
Mud rock “shales” by their very nature can be problematic to fracture stimulate given the wide variation in geology, rock properties and reservoir characteristics. Quite often, a positive production response from a well may be incorrectly credited to the completion and frac design when in reality the production was dominated by favorable reservoir characteristics. Conversely a poor production response from a well may be blamed on the completion and frac design when in fact poor reservoir quality is the controlling factor. The subject of this paper is a revisit of the physics behind production increases from hydraulic fracturing and results from detailed evaluations performed by experienced engineers with reservoir knowledge for the purpose of evaluating completion effectiveness and frac efficiency for shale and other low permeability formations.
The findings presented show that in many cases pumping large volume sand frac designs result in an inefficient hydraulic fracture. This inefficiency is due to minimal production contribution from a relatively large portion of the hydraulically exposed fracture face and/or frac length. These findings are supported by current hydraulic fracturing theory and understanding. The evaluation methods utilized in these evaluations are not new, however they currently are under-utilized by the industry for completion and frac analysis.
Fracture Diagnosis in Multiple Stage Stimulated Horizontal Well by Temperature Measurements Using Fast Marching Method
Authors: Cui Jingyuan , Yang Changdong , Zhu Ding , Datta-Gupta Akhil 
Published: September 2015

Abstract
Downhole temperature measurements is one of the solutions to understand downhole flow conditions, especially in complex well/reservoir domains such as multi-stage fractured horizontal wells. In the past, models and methodologies have been developed for fracture diagnosis for multiple-stage fractured horizontal wells. They are based on either semi-analytical approach for simplicity or reservoir simulation for generality. The challenges are that semi-analytical models are not robust enough to describe complex fracture systems, while numerical simulation is computationally expensive and impractical for routine inversion. To develop a comprehensive approach to translate temperature to flow profile, we adopted Fast Marching Method in simulating both heat transfer and velocity/pressure field in the domain of interest (heterogeneous reservoir with multiple fractured horizontal wells). Fast Marching Method (FMM) is a relatively new approach which is efficient in front tracking. Previous studies show a significant success in the investigation of pressure depletion behavior and shale gas production history match. By the nature of heat transfer in porous media, the thermal front propagation would lag behind pressure and the noticeable temperature change in reservoir only happens near hydraulic/natural fractures. FMM can be used to efficiently track the heat front that is associated with flow field.
In this study, we solve the thermal model in porous media by transforming the general energy balance equation into a 1-D equation with a ‘diffusive time of flight’ as the spatial coordinate system. Besides the diffusive heatpropagation, Joule-Thomson effect and viscous dissipation are also considered in the model. The inner boundary of the model is carefully handled and the drainage volume of each fracture is calculated to identify different inflow temperature related to flow rate at perforation locations. The model was validated by a finite difference approach. Examples are presented in the paper to illustrate the application of the new method. The approach can be used to quantitatively interpret temperature measurements to fracture profiles in horizontal wells.
Why “Do Not Disturb” is a Safety Message
Authors: Sweatman R. E. , Mitchell R. F. , Bottiglieri A. 
Published: September 2015

Abstract
Although not disturbing the cement during its curing time is sometimes mentioned in the oil and gas industry's literature and training courses, the information is often not thorough or explicit on how cement can be disturbed during the waiting on cement (WOC) time period and adversely affect safe drilling operations. This has contributed to a lack of understanding of best practices to use and those to avoid by personnel involved in planning, designing, and drilling wells, including those involved in cementing casing and liners and in other associated operations to install annular sealing devices such as setting openhole packers, liner hanger seals, subsea wellhead casing seal assemblies (WCSA), and liner top packers. This paper includes comprehensive information to help rectify this situation.
In addition to describing previously known damage mechanisms and consequences, new ones will be presented such as how the setting of WCSA may have undesirable safety results: a) the drilling fluid level above the cement is blocked so abnormal levels can't be monitored; b) cooling of drilling fluids may change its volume and density causing progressive losses of the fluid column's hydrostatic pressure; and c) formation influx can then initiate to damage the cement.
Thermal modeling with supplemental algorithms and lab tests are used to evaluate whether or not overbalanced pressures are converted into underbalanced ones during WOC times when cement is a fluid and not yet set hard into a pressure barrier.
In an example well where a WCSA was set shortly after the cement job, thermal analysis indicated how flow-able formations became underbalanced within the first two hours of WOC when the cement was still a fluid. After 16 hours later, sufficient pressure differentials built up to breach a mechanical barrier, causing a loss of well control.
Novel information identifies safety risks such as loss of zonal isolation, wellbore integrity, and well control when adverse thermal effects on drilling fluids are combined with setting of annular seals above the top of cement during WOC time periods.
Comprehensive Global Model for Before-Closure Analysis of an Injection Falloff Fracture Calibration Test
Authors: Liu Guoqing , Ehlig-Economides Christine 
Published: September 2015

Abstract
Since the injection-falloff fracture calibration test is generally accepted as a reliable way to obtain several key formation parameters, it is one of the essential parts of hydraulic fracturing design. While several abnormal behaviors have been described qualitatively and are frequently observed in an injection falloff fracture calibration test, the only quantitative model for before-closure behavior accounts only for normal leakoff, which seldom happens in practice. This paper describes several new analytical and semi-analytical models to simulate and quantify abnormal leakoff behaviors such as tip extension, pressure dependent leakoff (PDL), multiple apparent closures and transverse storage.
Based on material balance, we model pressure change with time considering the fracture geometry and leakoff volume under various leakoff mechanisms. Then, we show that the appearance of the modeled mechanisms both on the standard Nolte plot and on the log-log diagnostic Bourdet derivative presentation qualitatively matches behavior seen in previously published field data examples.
Results suggest that the early '/2-slope occasionally observed on the log-log diagnostic plot is probably fracture linear flow. When present it can mask all or part of a wellbore storage effect. Natural fractures have a significant impact on the pressure falloff behavior when they open during treatment. Depending on the properties of the natural fracture system, the pressure response can behave as pressure-dependent leakoff (PDL), transverse storage, multiple closures or even normal leakoff in some cases. In addition, if tip extension or PDL behavior are observed, propagation pressure or natural fissures opening pressure can be estimated respectively.
The global model for the closure behavior combines the flow regime models. When shown on the loglog diagnostic plot, calibration test data reveal derivative trends that are used to estimate parameters to which each flow regime is sensitive. Sensitivity analyses with the new model show relative importance with time of the various model features. This work promotes a complete understanding of the pressure response from various leakoff physics and provides a method to quantify parameters needed for more effective hydraulic fracture design.