bluuebunny/crossref_metadata_2025 huggingface dataset:
Emerging High Temperature Well Stimulation Diversion Technology Leads to Significant Increases in Conductivity
Authors: Bestaoui-Spurr Naima , Castillo Dorianne , Debenedictis Frances , Brannon Harold
Published: February 2017

Well stimulation fluids have been shown to improve oil and gas well productivity in both conventional and unconventional formations. Many formations contain multiple producing zones and areas of high and low permeability; therefore, during stimulation treatments, creating and increasing conductivity networks is highly desired. The most traditional method to increase conductivity networks is by diverting well stimulation fluids from high-permeability zones to low-permeability zones. This can be achieved by using various types of materials and techniques such as forming a filter cake that blocks off the high-permeability zone so that the fluid can be redirected to low-permeability zones. A more innovative approach is to use a diverter system made of dissolvable agents with proppants to force flow to the high-resistance path instead of the low-resistance path. The two types of particles are mixed in a way that they block any permeability from high-permeability zone once placed, effectively creating diversion of the fracturing fluid to other areas. Once the agent has provided its benefits and has dissolved, it leaves behind a proppant pack in both the lowand high-permeability zones, providing conductivity that is not otherwise achieveable. The fracture geometry is consequently enhanced by ensuring that the fluid and proppant are able to access all available fracture networks and open perforations. This paper describes an evaluation of two biodegradable particles and their application as diverters and also in combination with proppants for diversion.

Conductivity studies were performed to determine regained conductivity under stress and temperature. The dissolution profiles of two soluble particles and comparison with polylactic acid were also performed in static conditions as function of time, size and type of carrier fluid for individual particles as well as their mixtures with proppant. The conductivity studies showed that once the dissolvable particles dissolved, the proppant pack provides conductivity that is orders of magnitude higher than when only the biodegradable particles are used for diversion. The studies also show that a material with glass transition temperature below the application temperature had better strength for high-temperature application, and each material has a dissolution profile that is a function of the particle size distribution and temperature.
Optimal Management of Topside Diluent Injection for a Heavy Oil Field
Authors: Astutik W. , Hoffmann A. , Rasmussen F. , Whitson C. H.
Published: February 2017

Heavy oil fields can be developed using diluent (light oil, condensate, etc.) injection at the well level as a flow improver. However, diluent can also be injected at the surface, as used in Canadian heavy oil production. Benefits of topside diluent injection include among others (1) improved oil/water separation in the surface processing facility, (2) improved viscosity, and (3) better final crude quality. Such blending activities are often associated with additional OPEX due to the high price of diluent, which can add significant costs to a development. This paper describes an Integrated Asset Modelling (IAM) solution designed to minimize the topside diluent requirement while honouring technical and market crude specifications. The case studied is an offshore heavy oil field consistings of two reservoirs with API gravities of 14 and 12, and oil viscosities at reservoir conditions of 70 cp and 500 cp.

The production facilities include a two-stage surface processing facility followed by a coalescer aimed to separate the water from the crude. Diluent is injected in the surface processing facility prior to the second stage separator. Operating variables include (1) the topside diluent injection rate and (2) the temperature of the second stage separator. The difficulty of the production optimization problem lies in the non-linearity of the process and viscosity models, and the consistency of the fluid’s PVT description throughout the production system.

The proposed optimization solution is coupled with a reservoir simulator to determine optimal topside diluent requirements over time and foresee eventual bottlenecks in the surface infrastructure design. The proposed solution can also be used as a real-time management tool during the production phase to find the optimal operating point based on real-time data. The optimal operating point ensures the lowest diluent consumption while meeting all system constraints, providing the framework for significant cost savings.
Well Test Simulation for Dual Porosity-Dual Permeability Using Orthogonal Collocation
Authors: AL-Muftah Ali
Published: February 2017

This paper presents a new way to numerically simulate flow in Dual Porosity - Dual Permeability system which is solved rigorously with wellbore storage and skin. This paper shows that the use of Orthogonal Collocation method is feasible and that, in many cases, it results in solutions that are more realistic than those resulted from numerical inversion of Laplace transform. There are, however, certain disadvantages. For example, oscillation of the pressure derivative which can be overcome by using Orthogonal Collocation on Finite Element (OCFE) in which programming effort are usually in excess of that required by a finite- difference or numerical Laplace inversion scheme. Even so, it is felt that the potential of the technique is sufficient justification for this work and for a continuing effort to apply it to well test simulation problems.

Dual Porosity - Dual Permeability well testing problem is described by a complex set of nonlinear partial differential equations. Their solution is normally achieved analytically using Laplace transform or numerically through the use of numerical inverting methods of the Laplcace transform like Stehfest and Crump. This paper is an extension to the paper SPE 120668 that introduced the method for the basic well test problem.

The primary objective of this paper is to investigate the feasibility of using Orthogonal Collocation on well test in Dual Porosity - Dual Permeability system. Since this work was primarily concerned with the feasibility of Orthogonal Collocation simulation, no attempt was made to study a wide spectrum of cases of well test problems. However, a few typical applications are presented and some of the results are compared with those derived from analytical and numerical inversion.
Qualitative and Quantitative Impact of Thin Rock Lamination on Acoustic and Geomechanical Properties of Organic-Rich Shale
Authors: Al-Qahtani Adel A. , Tutuncu Azra A.
Published: February 2017

Thin rock lamination is one of unique features that distinguishes organic-rich shale source rocks from conventional reservoir rock formations. The orientation of rock lamination has an influenceon acoustic and geomechanical characteristics of organic-rich shalethat canaffect drilling and stimulation operation decisions.In this paper, the impact of rock lamination orientation was qualitatively and quantitatively assessed.

Core analysis and tri-axial experimental study were conducted on several US shale formations including Eagle Ford, Mancos and Green River. At various stress conditions, rock samples were tested at different lamination orientations and rock mechanical properties (e.g. rock strength, rock failure behaviour, acoustic velocities, and elastic moduli) were obtainedand qualitatively evaluated.

Fromthe tests, horizontal oriented samples exhibited highest maximum compressive strength where the lowest maximum compressive strength was observed at the orientation of 60°. The vertical and horizontal samples displayed a multi-step failure behaviour, resulting in a creation of complex fracture system, whereas sliding failure behaviour was noticed on other orientations. The analysis of Alqahtani's (2015) correlations showed that rock lamination orientation is a controlling factor that needs to be taken into account in estimation of static and dynamic elastic modulus.
Innovative Technology and Advanced Engineering Prove Concept for Future Field Development of an Ultra-HPHT Unconventional Gas Reservoir
Authors: Abbott J. , Eswein E. , Abad C. , Székely-Szabó T.
Published: February 2017

The well X in the reservoir Y of the Z basin comprises several low permeability siltstone reservoirs which require propped fracture stimulation to produce at economically attractive rates. This region is known for an abnormally high geothermal gradient, resulting in bottom-hole static temperatures over 210degC / 410degF. This paper will describe the state-of-the-art technologies and techniques required to successfully complete the well and optimize well and completion design for future field development.

Due to the extreme conditions, new technologies and techniques were required to address key challenges and ensure the success of the project. A novel, state-of-the-art fracturing fluid was successfully applied to ensure fluid stability when faced with temperatures in excess of 210 degC. Tracers and high temperature diagnostic tools were deployed to aid with onsite design changes and later to evaluate fracture geometry and production performance. The onsite execution data was combined with post-job diagnostics and well test data to evaluate well, formation and fracture performance with aim of optimizing well and completion design for new wells in the field.

Three fracturing stages were successfully completed in this ultra-high temperature tight gas well. The key technologies and techniques applied enabled the successful completion of the operation and, more importantly, provided the data crucial for optimizing well and completion design for future wells. The well achieved commercial production rates and provided proof-of-concept for future field development. Advanced production enhancement design workflows have played a key role in optimizing job design, assessing job performance and evaluating the completion strategies required for future field development.

A new ultra-high temperature fracturing fluid was applied for the first time in Europe. The first application of ultra-high temperature bottomhole gauges for reservoir characterization was performed. A reservoir centric fracture simulator was used to design and evaluate fracture performance, production prediction and optimize future well and completion designs.
Line Blind Technology
Authors: Almulhim Mohammed A.
Published: February 2017

Executive Summary

Line blind is a new positive isolation technology that may replace traditional blinding. Line blind requires minimal preparations to change the position from close to open or vice versa. With this technology, there will be no need for multiple technicians, cranes, and other logistical considerations when there is a need to change the position of the blind. This technology enables one or two operators to change the position of a blind significantly faster (5 min.) than with traditional blinding systems (4-8 hours). With this new technology, there is no need to replace gaskets every time the position of the blind is changed.

A trial test was conducted over six months to evaluate and assess the benefits that this device could bring to Saudi Aramco. The blind was installed downstream of a saltwater injection pump at one of Saudi Aramco's gas-oil separation plants (GOSPs) during the first week of February in 2013, and commissioned on Feb. 13. This location was selected as it represents one of the most challenging applications since it is very high pressure (up to 3000 psi) and a very corrosive environment.

After the 6-month test, the line blind technology showed high reliability and ease of use. The test results show a significant reduction in the time consumption and resources requirement to change the position of the blind at this particular location. Traditional blinds used to require a team of 4-5 technicians and a crane with its operator and substantial work coordination and time delays. Each time the traditional blind is changed used to take up to 4 hours of physical work.

With this technology, one operator was able to change the position of the blind in less than 5 min. The line blind, was tested against 3000 psig discharge pressure without any leaks. This test was repeated several times during the test period. There was one incident where minor droppings were noticed after the pressure reached 3050-3100 psig. This was mainly due to the fact that the faces of the line blind were not cleaned as per the recommendations from the vendor. The test was repeated after this incident and the faces were cleaned and the system was tested successfully to 3100 psig with no leak detected.

This is a test that confirmed that line blind technology is a very reliable system for positive isolation that can significantly improve operations and minimize risks.
Water Swell Packers with High Salinity Tolerance and Increased Performance Envelope
Authors: Sadana Anil K. , Badke Greg , Cook Christopher , Wang Xiao
Published: February 2017

Swellable packers are widely used to create annular seals between production casing and an open hole. These packers are popular because of the intervention-less deployment and are generally deployed in drilling or completion fluids. This paper presents the development of a new swellable packer that exhibits higher swelling in high-salinity downhole environments brines and greater differential pressure-holding capability than the existing water swellable packers.

The swellable packer is 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).

A 6 ft. swellable packer requiring 43% mandrel swell to seal the annulus was swollen in 3% NaCl at 260° F and pressure tested. The packer successfully held 7,000 psi differential pressure which out-performs existing swellable packers for similar environments. A mini swell packer (12 in.) made from this material exhibits 55% volume swell in 10% CaCl2 at 190° F, which is significantly more than swell achievable with existing compound.

The new high-salinity water swell technology not only offers a higher pressure rating than existing packer technology, it opens new opportunities in zonal isolation where the traditional water swell technology is not an option.
Numerical Modeling of Thermal-Mechanical Interaction Process in High Power Electromagnetic Heating of Rocks
Authors: Han Yanhui , Fang Yi , San-Roman-Alerigi Damian P. , Batarseh Sameeh I.
Published: February 2017

Perforation is an essential method to improve hydrocarbon flow from the reservoir into production wells. However, conventional methods to create it cause plastic compaction, lead to loss of permeability in the surrounding rock, and reduce the hydraulic conductivity of the immediate formation. One of few tested and feasible alterantives to conventional perforation is to use high-power electromagnetic (HPEM) sources to induce a phase change in the formation via dielectric heating. Over the course of the last decade, subsurface photonic technologies have been proven to perforate, fracture, and drill multiple rock types in the laboratory. Furthermore, it has been shown to improve conductivity and reduce general damage to the rock formation. These outstanding experiments purveyed an excellent understanding of the physical dynamics that guide the interaction between the HPEM sources and the rock. Cocerning modeling, several models have been proposed to simulate the the thermal-mechanical interaction and phase change. Yet, due to the innate sophistication of the problem, a comprehensive model remains a topic of research. Recently, we possited a numerical workflow that bridges these gaps and predicts the perforation geometry and mechanical impact departing from the electromagnetic field parameters, the rock properties, and the stress configuration. In this paper, the method is expanded to encompass a set of numerical thermo-mechanical coupling models to investigate the effects of heterogeneous material properties and stress ratio on the perforating rate and mechanical damage in the HPEM-enabled perforation process.
Modeling of a Complex Depositional System Using MPS Method Conditioned to Hard Data and Secondary Soft Probabilistic Information
Authors: Macé L. , Márquez D.
Published: February 2017

Spatial distribution and proportions of facies in a depositional system are essential drivers of reservoir heterogeneity and connectivity and, thus, flow performance. Modeling facies relationship in complex depositional systems is one of the major challenges, particularly thin, elongated and sinuous bodies such as channels due to their high aspect ratio. Traditionally, such geological bodies have been generated using object models but with limitations in regards to the geometries of the associated facies that can be handled.

In this paper, we propose a method to model a complex channelized depositional system using a multipoint statistics (MPS) method that efficiently integrates a non-stationary conceptual model with hard data and secondary information. The conceptual model is a clastic shallow-marine depositional system with fluvial and deltaic deposits. It comprises a transitional facies model with lateral variations and a transgressive-regressive sequence. The transgressive phase is a wave-dominated estuary environment, and the regressive phase comprises wave/fluvial-dominated delta deposits.

The proposed methodology allows us to quickly create a 3D geocellular reservoir model of a complex depositional system that efficiently incorporates measured data and geological conceptual knowledge. The resulting MPS model satisfactorily reproduces facies patterns, proportions, and connectivity.
A Robust Framework for ICD Design in a Giant Field Using 4-D Dynamic Modeling
Authors: Ogunsanwo O. A. , Lee B. O. , Isichei O. , Amjad B.
Published: February 2017

In this study, a review of production performance of four existing horizontal producers equipped with Inflow Control Device (ICD) completions was conducted using 4-D dynamic modelling on a sandstone reservoir with high water mobility. The aim of this study was to investigate the optimum regulation degree across ICD completion i.e. the ratio of pressure drop across ICDs to the reservoir drawdown, suitable to delay water breakthrough, minimize water cut and achieve production balance.

A single wellbore model was built by populating rock and fluid properties in 3-D around the wellbore for each of the studied wells. The model was then calibrated to the measured production log flow profile and bottomhole pressure profile for the deployed ICD completion in each well. Thereafter, several ICD simulation cases were run at target rates for a production forecast of 4 years. An optimum ICD case for each well was selected on the basis of water breakthrough delay, water cut reduction and incremental oil gain.

The study results showed that there is a correlation between reservoir heterogeneity index, well productivity index (PI) and optimum regulation degree required across ICD to achieve longer water breakthrough delay and better water cut control. In general, high heterogeneity, high PI wells require higher regulation degree across ICD of close to one; medium heterogeneity, low PI require regulation degree across ICD of between 0.3 – 0.45 while low heterogeneity, low PI, require very low regulation degree of between 0.1 – 0.15. Based on study results, a new ICD design framework and correlation chart were developed. This framework was then applied to two newly drilled horizontal producers to test the applicability of the workflow in real time ICD design scenarios and positive results were achieved.

Given the significant number of ICD completions deployed yearly, this new ICD design framework would provide guidance on how much pressure drop across ICD is required during real time design for newly drilled or sidetrack wells and would ultimately ensure maximum short and long term benefits are derived from deployment of ICD completions.
Developing a Robust Inflow Control Device Suitable for High Rate Injection
Authors: Snitkoff Joshua , Abdelfattah Tarik , Fisher Britain
Published: February 2017

Demand for inflow control devices (ICDs) in injection applications is increasing, leading to design initiatives by operators and service companies. These initiatives address the more rigorous conditions of injection applications including acidizing, SAGD, and cyclic steam stimulation. This paper will demonstrate the success of an iterative design and qualification process to develop a robust tortuous path ICD that can withstand higher pressures and higher stimulation rates operators desire for injection applications.

The design process started with computation fluid dynamics (CFD) modeling to predict the stimulation flow performance and resulting pressure gradient underneath the ICD's outer housing. This information was input to the finite element analysis (FEA) model to determine the stress and deformation of the housing. Results of a dynamic flow test with strain gages attached to the housing were compared to the simulated deflection. Additional iterations of the FEA model resulted in the final ICD design. An endurance test verified the final design could withstand full length stimulation operations.

The implementation of the design and qualification method enabled the ICD to withstand higher injection rates without losing any ICD functionality. Overall, the maximum allowable injection rate was increased by 50% compared to the proven ICD design used in production wells.

Previous ICD qualification testing mainly involved characterizing the ICD in production, not the rigorous conditions during stimulation. Thus, designs were not subjected to such intensive mechanical integrity testing. However, in carbonate reservoirs it is often imperative to stimulate wells to bypass damage induced during the drilling and completion phases [Bachar, November 2014]. As stimulation techniques for horizontal wells continue to improve, it is important for well completion technology to keep pace. Differential improvements in ICD design enable a much wider range of well stimulation capabilities increasing well productivity over the life of the well.
Static Mixer Technology
Authors: Alhajri Nasser A. , Al Abdulgader Mohammed A.
Published: February 2017

The Static Mixer is a motionless mixer in which fluids are injected and rapidly mixed by combination of alternate vortex shedding and intense shear zone turbulence. It is a compact mixing plate with injection nozzles on two sides to ensure excellent distribution (figure 1 below). Moreover, it has bent tabs (which are designed using Computational Fluid Dynamics Modeling) to generate an efficient mixing with minimal pressure drop and maximum salt removal & chemical effectivness of the crude oil. This subject technology is aimed to optimize the wash water (underground water) & treating chemicals consumption in Gas Oil Separation Plants (GOSP). Also, it is aimed to achieve efficient blending between the crude oil stream and secondary streams resulting in high process efficiency with low consumptions of resources.
Integration of Advanced Cuttings Analysis and Fluid Typing with NMR and Acoustic Logs for Petrophysical Log Interpretation Without Radioactive Sources
Authors: Mohnke O. , Bartetzko A. , Ritzmann N. , Aarnes I. , Thern H. F.
Published: February 2017

The density-neutron log combination is a common standard for reservoir evaluation, typically used for porosity and lithology estimation. The measurements require the use of radioactive sources that operators are increasingly trying to avoid, particularly in areas where drilling operations are challenging and the lost-in-hole risk is elevated. This paper introduces a workflow that integrates surface-measurements, i.e., advanced cuttings, with nuclear magnetic resonance (NMR) and acoustic log data to estimate formation-porosity and bulk density and to distinguish different lithologies.

We present cases where we integrate the porosity from NMR or acoustic with mineralogical analyses on cuttings to infer matrix density by calculating a weighted average of the mineral densities according to their fractional volume in the rock. Formation fluid density is calculated based on a saturation analysis, with the fluid composition and densities of water and hydrocarbons estimated from downhole fluid sampling. This novel method develops a calculated continuous synthetic bulk density log.

Standalone NMR logging can deliver a very accurate, lithology-independent measurement of porosity in oil and water zones. Even though NMR measurements may face challenges in gas-bearing reservoirs, a very accurate porosity can be obtained by integrating NMR and acoustic logging data together with natural gamma ray and resistivity data. An overall comparison of NMR-acoustic porosity to porosities derived from density-neutron and core data within different lithologies shows that the measurements are consistent within +/- 1 porosity unit (pu).

To deliver the same set of information as the density-neutron log with standalone NMR, acoustic or an NMR-acoustic log combination, bulk density, and lithology information utilizes the presented workflow integrating the data from surface measurements and downhole logging. The calculated synthetic bulk density logs from the integrated analysis of surface and downhole log data are in good agreement with measured bulk density logs.

The presented workflow introduces an alternative to the common density-neutron combination for formation evaluation. It delivers a set of petrophysical properties, such as porosity, bulk density and lithology by integrating NMR with advanced cuttings and fluid analysis without using any radioactive sources in the borehole.
Influence of Near-Wellbore Stress Field Variation on the Success of Hydraulic Fracturing: Experiences from the Middle East
Authors: Vossen Johannes , Perumalla Satya , Sherbeny Wael El , Mendez Alfredo
Published: February 2017

Success and failure of hydraulic fracturing is driven by a number of factors including operational procedures, fluid dynamics and the geomechanical response of the reservoir. Thus, the complex nature of the hydraulic fracturing process makes it difficult to correlate its success or failure to one of the many factors alone. However, in this paperwe demonstrate – based on real experiences–some successes and failures that show strong evidence of being driven by geomechanics aspects alone.

The unsuccessful hydraulic fracturing of a well can be often interpreted as a failure in terms of operational procedures. However, there are cases where the unfavorable geomechanical setting plays the dominant role on the fracturing success. Modeling such complex processes can be very time consuming and costly, especially, if fluid dynamics of the pumped fluids is integrated into the calculations. One suggested way forward is to modestly simplify the world of (rock-) physics and hence focus on the problem down to the main contributors of the processes while still reaching the desired and representative result.

In this work we focused on stress and pressure changes around the wellbore and perforations, that have strong influence on the end result of fracturing. In four wells that were hydraulically fractured, we observed two wells experiencing successful breakdown (and propagation), whereas the other two wells could not be fractured. Optimal application of analyticalgeomechanical modeling was more than sufficient to prove that the major cause for the failure in formation breakdown was stress field changes around the well bore and perforations in coherence with the rockmechanical properties. Thus, the specific geomechanical setting has led to an elevated breakdown pressure that was too high to be achieved by the horse powerof the pressure pumping equipment. At the same time the model also explains the underlying reasons for the two successfully stimulated wells.

This experience not only leadsto a geomechanical explanation for hydraulic fracturing- (formation breakdown) failure and success, but also to more customized recommendations for avoiding loss in pump horse power. This is of importance when limitations in pump- and completion pressures are a concern. From this experience we learn also about the influence of geomechanical drivers on well placement, completion strategy, perforation schemes and injection point selection.
A New Approach for Permeability Distribution in Carbonates Using LWD High-Resolution Image Analysis
Authors: Chen Chao , Ibrahim Hossam El-Din , Mostafa Tamer G , Nair Sajan R. , Abdulkarim Anar , Aki Ahmet , Rahimov Huseynagha
Published: February 2017

Because core porosity versus permeability relationships are often limited for predicting production performance, it is desirable to investigate alternative methodologies to improve permeability estimates. This paper presents a workflow using logging-while-drilling (LWD) sensor measurements, namely laterolog resistivities for permeability derivation and high-resolution microresistivity images for porosity partitioning.

High-resolution microresistivity images were used for traditional picks of symmetric features, such as bedding planes and fractures, as well as for identification of asymmetric features, such as vugs or secondary porosity. The estimation of secondary porosity was based on several assumptions. In water water-based mud (WBM) systems, the encountered vugs during drilling will be filled with conductive fluid and hence display dark pixels on the high-resolution image. The determination of these features was based on a histogram of pixels created corresponding to a full azimuthal coverage. Next, an associated mean value and standard deviation were calculated, and any pixel values lower than the average minus a standard deviation was classified as a vug. The number of these pixels was then divided by the total count of all pixels, the fractional value of which then represented the ratio of secondary porosity with respect to total porosity. This ratio could then be converted into porosity units (pu) from any independent source.

Permeability transform was based on the average image resistivity and/or conductivity values from button values, which were then normalized to an external permeability value or indicators; in this paper, these were formation tester mobility measurements.

The workflow also entailed partitioning of the horizontal section to different intervals based on the derived permeability profiles and petrophysical attributes.

Finally, the derived results from microresistivity and mobility measurements were analyzed to provide qualitative estimates of permeability, leading to identification of reservoir flow units.

This paper presents a case study where the discussed methodology was applied and provided the derived interpreted results. Multiwell interpretation in this reservoir sector in the vicinity of the case study well, together with further data integration, is desirable to fine-tune this methodology and workflow.
4D Study in Middle-East Carbonate Field: How to Deal Intelligently with Noisy Data
Authors: Neau A. , Cailly F. , Hubans C. , Lafram A. , Monnier D. , Schildberg Y. , Berthet P. , Le-Roch J.
Published: February 2017

Time lapse seismic or 4D seismic is a geophysical monitoring tool used by the industry to guide and maximize field development. It has been proven successful in many clastic deposit environments (Gulf of Mexico, Gulf of Guinea, North Sea…) but barely used operationally on carbonate fields. Major concerns are both on carbonate petrophysical sensitivity to pressure and saturation changes, and particularly in the Middle-East on the expected noisy seismic quality. In reality Truth is more complex and some cases emerge showing that good quality 4D seismic in carbonates is possible.

The case study presented here belongs to the worst case family: random noise is high level due to very shallow streamer acquisition design during Base survey, and multiples are highly non repeatable and pollute the dataset. However the final result is an added-value and this paper aims to explain that a comprehensive interpretation mixing innovative QC tools and an integrated 2G&R interpretation can allow separating intelligently noise and 4D signal.
Mechanisms of N2 and CO2 Assisted Steam Huff-n-Puff Process in Enhancing Heavy Oil Recovery: A Case Study Using Experimental and Numerical Simulation
Authors: Wei Bing , Pang Shishi , Pu Wanfen , Lu Laiming , Wang Chongyang , Kong Lingle
Published: February 2017

N2 and CO2 assisted steam huff-n-puff method has been proposed as the primary strategy to develop a new heavy oil reservoir located in the northeast of China having average oil viscosity of 5000mPa·s, reservoir pressure of 14MPa and temperature of 56°C. Prior to field application, a laboratory study from phase behavior to numerical simulation was conducted in this work. The experimental data showed that the swelling of the heavy oil as a result of CO2 dissolution varied almost linearly with pressure, but appeared independent on N2 pressure. CO2 markedly outperformed N2 in swelling heavy oil reducing viscosity and extracting hydrocarbon. In huff-n-puff simulation, averagely 4% and 6% of additional heavy oil was produced by steam injection compared to CO2 and N2 injection after natural depletion. In the scenario of gas assisted steam process, a more noticeable incremental oil recovery (>10%) was produced, which thus demonstrated its potential in this reservoir. The mechanisms of oil recovery stimulation were further elucidated using numerical simulation from the point of parameter variations for pressure, viscosity, temperature, and oil saturation.
Synergistic Effect of Thermally Stable Polymers for HPHT Brine-Based Drill-in Fluids
Authors: Zhou Hui , Galindo Kay A. , Zha Weibin
Published: February 2017

This paper discusses two high-temperature-resistant polymers (Polymers A and B) that have been developed as thermally stable, dual-functional viscosifiers and fluid-loss additives. Polymer A was designed for monovalent brines, while Polymer B works for divalent brines. These polymers enable the formulation of brine-based drill-in fluids that are stable at high to ultra-high temperatures, which is a significant improvement when compared to conventional biopolymer-based drill-in fluids. When combined, the two polymers work synergistically to further reduce fluid loss in monovalent brines.

The two thermally stable polymers were readily incorporated into various drill-in fluid formulations containing either monovalent or divalent brines over a broad range of densities. These drill-in fluids exhibited exceptional thermal stability and showed no stratification after static aging at 400°F for three days or at 375°F for seven days. A minimal change in fluid behavior was observed when comparing the rheological properties of the un-aged and aged samples. The samples provided excellent fluid-loss control, even after aging. A synergistic effect was observed between Polymers A and B when used in monovalent brines to further reduce the HPHT fluid loss with no negative impact on fluid rheology. Core flow tests showed that both fluids were non-damaging after acid-breaker treatment. It is anticipated that these polymers will extend the envelope to which water-based drill-in fluids can be successfully used to drill high- and ultra-high-temperature reservoirs. Recent successful field trial of the divalent brine-based fluid as a testing fluid further proved the robustness of these fluids for these reservoirs.
ESP Pump Considerations for Thermal Recovery Applications
Authors: McManus D. F. , Coates B. C. , Montilla C. A.
Published: February 2017

Steam-assisted gravity drainage (SAGD) and other thermal recovery applications require electrical submersible pump (ESP) equipment which can withstand extremely harsh oilfield environments with well conditions typically including high gas, sand, and scale concentrations in addition to the extreme temperatures and temperature cycles generated in the process.

Thermal recovery pump construction specifications were developed as part of a new tiered product line covering deployment of equipment in wells with bottom hole temperatures (BHT) as high as 250°C. Special construction considerations were implemented for stage compression, thrust handling, bearing design and materials of construction.

The new pump technology combines high temperature and abrasive handling features to extend product life and provide consistent reliability in thermal recovery applications. Enhanced temperature tolerance is achieved through reduced thermal stresses on internal components leading to better reliability and increased run life.

This next generation of thermal recovery pumps has been extensively field validated with systems utilizing the new technology currently installed and operating in over 400 wells.
Using Digital Rock Modeling to Estimate Permeability and Capillary Pressure from NMR and Geochemical Logs
Authors: Zhang Hao , Yuan Peng , Wu Jianghui , Mezzatesta Alberto , Jin Guodong , Satti Rajani , Koliha Nils , Bautista Juan , Crouse Bernd , Freed David
Published: February 2017

Permeability is one of the most important characteristics of hydrocarbon-bearing formations. Many approaches exist for estimating permeability. Formation permeability is often measured in the laboratory from core samples or evaluated from well test data. However, core analysis and well test data are expensive and available only from a limited number of wells in a field. On the other hand, logging data are available from almost all wells. Therefore, accurate prediction of the formation permeability using logging data becomes very attractive.

This paper describes a unique integrated modeling approach to predict formation permeability. By combining digital rock physics (DRP) and downhole logging measurements, formation permeability and capillary pressure were predicted using computational analyses. In this approach, a representative geometrical rock model for the formation at each given depth of interest was numerically generated. These numerical rock models are constrained by the formation parameters derived from NMR and geochemical logging data, i.e., all input parameters for the geometrical rock model such as the rock density, porosity, grain-size distribution, and grain mineralogy, are directly or indirectly obtained from downhole logging measurements. Then, using the geometrical rock model as input, pore size information, capillary-pressure curve, and permeabilities were obtained by computational analyses, including fluid flow simulations based on the lattice-Boltzmann method (LBM).

To demonstrate the method's feasibility and applicability, the proposed modelling approach was used on two sets of field data from a North Sea well and an Austin testing well. Permeability and capillary pressure were experimentally determined from laboratory measurements on cores and compared to the simulation results. The predicted permeability values from the proposed DRP approach were in good agreement with measured values from cores. The drainage capillary-pressure curves derived from rock models also matched well with laboratory measurements on core samples. The promising results generated from this study demonstrate the feasibility of a digital core analysis method that integrates a geometrical rock model with downhole logging measurements to accurately and reliably predict formation petrophysical properties in a cost-effective and timely manner.
Best Practices for Effective Wellbore Cleanup and Displacements in Open-Hole Sand Control Completions
Authors: Beldongar M. , Agee D. , Kumar A. , Offenbacher M. , Flamant N. , Lees A. , Gadiyar B. , Parlar M.
Published: February 2017

At some stage after drilling to target depth and before pumping the gravel packing treatment or before putting the well on production, the drilling fluid is typically displaced from the wellbore. Practices in the industry vary significantly depending on the primary drivers of the completion engineers, sometimes with disastrous results. Inefficient wellbore displacements can cause a variety of problems including increased non-productive time, reduced well productivity and incomplete gravel packing through various mechanisms.

In this paper, we detail our best practices to ensure efficient wellbore displacements for sand control completions. In the design phase, these involve various compatibility tests some of which are not commonly done and/or potential problems cannot easily be identified when they are done using conventional test procedures, modeling of fluid-fluid displacements and determining the fluid properties, pump rates and fluid volumes required for effective displacements in a given wellbore geometry and flow paths. On the rig site, they involve several quality control tests, some of which have not previously been implemented.
Development of an efficient Vibration Modeling Technique for Design-Related Optimization of Tools in the Global Drilling Environment
Authors: Hohl Andreas , Heinisch Dennis , Oueslati Hatem , Herbig Christian , Reckmann Hanno
Published: February 2017

Severe vibrations in drilling systems and bottom-hole assemblies can be caused by cutting forces at the bit or mass imbalances in downhole tools such as mud motors. Vibrations can lead to reduced drilling performance, poor measurement quality and reduced reliability. Models are important to understand the phenomena and predict loads. So far models are established that calculate the dynamic behavior of the drilling system from a global point of view: The drilling system is modeled with simplified geometry and placed in the drilling environment under consideration of the wall contacts with the borehole and the fluid properties. Global models are typically used for optimization of drilling parameters such as the rotary speed or the flow rate with respect to estimated dynamic loads. Global models are not suitable for detailed modeling and analysis for optimization on a tool component level.

A system-approach is established to overcome the limitations. A method is developed to connect a detailed 3D-model of a downhole tool with the model of the drilling system and the bit that is placed in the global drilling environment. The method enables new insights into the behavior of downhole tools that can be used to optimize downhole tools with respect to their reliability and their performance: Dynamic loads on tool components such as probes and pockets can be calculated to optimize the tool design and increase reliability. The probe design can be optimized to reduce the dynamic loads on sensor components and significantly increase the measurement quality.

In a case study the method is validated with measurements. Herein, torsional eigenfrequencies and corresponding mode shapes which are localized to the bottom-hole assembly as well as the resulting tool stresses and loads are considered. The impact of a dampening tool to mitigate torsional vibrations is discussed. In a second example the capability of the method to capture lateral vibrations under consideration of wall contacts and mass imbalances is shown. The method is used to optimize the design of a downhole tool to decrease the dynamic loads at sensor components that are placed in a probe.

The system-approach of the method allows to efficiently simulating the vibrational behavior of tool parts in an arbitrary detail and in a global drilling environment. The new method enables improved tool design for performance and reliability and increased measurement quality.
Ensemble-Based Assisted History Matching Using 4D Seismic Fluid Front Parameterization
Authors: Trani Mario , Wojnar Konrad , Moncorgé Arthur , Philippe Berthet
Published: February 2017

An ensemble-based 4D seismic history matching case is presented. Seismic data are re-parameterized as distance to 4D anomaly front and assimilated with production data. The field is a large turbiditic system, with initial fluid pressure close to the bubble point. Production causes the pressure to fall below the bubble point, resulting in a widespread gas-exsolution. The time-lapse change in gas saturation is considered responsible for the observed negative relative changes in seismic velocity seen over the all reservoir. This study is innovative for two reasons. First, the distance-to-front parameterization is applied to the gas-phase which appears everywhere in the field, rather than coming form an injection source like in previous application of the parameterization. Second, the binarization of the simulated time-lapse anomaly is performed circumventing the use of a petroelastic model; the petroelastic model would be necessary to relate the measurements to fluid properties changes and to decide a threshold for binarizing observations and pressure. However, the effect of gas is so widespread and evident that the petroelastic model is replaced by a clustering approach based on the gas saturation change of the reservoir cells. This study shows that adding the 4D re-parameterized seismic data in addition to the production data is keeping a reasonable match with production data while constraining the overall gas distribution in the reservoir to the observed seismic data.