bluuebunny/crossref_metadata_2025 huggingface dataset:
The Potential Of CuO Nanoparticles to Reduce Viscosity and Alter Wettability at Oil- Wet and Water- Wet Rocks in Heavy Oil Reservoir
Authors: Tajmiri Masoumeh , Ehsani Mohammad Reza
Published: September 2016

The petroleum industry have been working for decades on various solutions to increase recovery. When petroleum companies abandon an oil well, more than half the reservoir's oil is usually left behind as difficult to recover. Recent investigations have developed a new method is based on adding particles that are considerably smaller than the tunnel diameters. Nanotechnology provides the capability to enhance energy efficiency across all branches of industry and economically renewable energy production through new solutions and optimized technologies. Nanoparticles defined as EOR potential agents for detailed control of benefits such as wettability alternation, interfacial reduction of oil and water and viscosity reduction. This study provides new idea of CuO nanoparticles effects on wettability alteration through spontaneous imbibition, reducing the viscosity and extracting heavy oil involving steam assisted gravity drainage (SAGD) by experimental work. In the first step of this research, the potential of CuO nanoparticles to imbibe and alter the wettability are determined experimentally and numerically. Laboratory tests were conducted in two experiments on two cylindrical core samples taken from Iranian heavy oil reservoir. In the first experiment, core samples were saturated by crude oil and in the second one, nanoparticles were flooded, and then saturated by crude oil, immersed in distilled water and the amount of recovery was monitored during 30 days for all tests. Experimental results show oil recovery for sandstone cores change from 20.74 % of OOIP without nanoparticles to 31.77% of OOIP with CuO nanoparticles, respectively. The oil recovery for carbonate core vary from zero without nanoparticles to 6.92% of OOIP with CuO nanoparticles, respectively. By investigation of relative permeability curve, the crossover-point is shifted to the right by adding CuO nanoparticles which means nanoparticles succeeds in altering the wettability to more water- wet for sandstone and even carbonate cores. In the second step, the effect of vertical spacing between two horizontal wells on oil recovery and the ability of low CuO nanoparticles concentration to reduce viscosity are clarified in SAGD process. Laboratory tests were conducted in three experiments through the use of 2 dimensional scaled SAGD cell from an Iranian heavy oil reservoir. In the first and second experiments, the SAGD cell were saturated by heavy oil and in the third one, the cell was flooded by CuO nanoparticles before oil saturation. The amount of recoveries were monitored during 12h. The experimental results explore that by adding nanoparticles, the ultimate oil recovery increases from 52.43 to 80.027%. Viscosity reduction, increasing oil recovery, decreasing residual oil saturation (SOR) and water cut (WCUT%) are the main purposes of this investigation.
The Influence of HLB in Surfactants for Drill Cuttings Cleaning
Authors: Stanciu C. , Fernandez J. M. , Lambert B.
Published: September 2016

Drilling operators are facing increased challenges in dealing with the drill cuttings produced due to higher demands from regulatory agencies. Government entities such as the US Environmental Protection Agency (EPA) and Norway's State Pollution Control Authority (SFT) set strict limits regarding the retention of oil on cuttings (ROC) for offshore drilling. This paper describes the role played by the hydrophilic-lipophilic balance (HLB) of a surfactant in designing efficient washing solutions (WS) that utilize both non-ionic and anionic surfactants to mitigate the ROC.

A range of anionic and non-ionic surfactant blends was screened for their cleaning ability on field cuttings. The main parameters considered during the surfactant selection were: chain length, branching/linearity, substitution pattern and polarity. For non-ionic surfactants the emphasis was placed on ethoxylated vs propoxylated molecules. Following treatment with WS the ROC was determined by using the retort distillation method (RD) as described in API RP 13B-2. The numbers obtained were graphed against HLB values for the surfactants in order to determine the best correlation between structure and cleaning ability for that particular type of cuttings.

The results show the achievement of a maximum cleaning ability of the WS for a given chain length of the surfactants used. The linearity of the molecules, although initially thought to play a significant role, proved to have a limited influence. In fact, blends containing roughly equal amounts of linear vs branched surfactants displayed the highest cleaning ability. The overall polarity of the mixture seemed to be important too, since blends containing non-ionic surfactants had almost no cleaning capacity. Of major importance in this particular study was the substitution pattern on the non-ionic surfactants. An optimum combination of propoxylated vs ethoxylated molecules was critical for the design of the most successful WS. Our results indicate that ethoxylation on the anionic component of the mixture and propoxylation on the non-ionic portion was critical since tests performed with the opposite combination showed almost no cleaning capacity. Increasing the PO content on the non-ionic molecule has a detrimental effect which is more pronounced than a similar increase in EO content on the ionic molecule.

The present study aims to help elucidate the roles played by the different surfactant molecules in designing efficient washing solutions for cleaning drill cuttings. This will assist the oilfield service companies in addressing the continuously increasing environmental regulations for disposing of drill cuttings while reducing the present costs and carbon footprint on the environment incurred by the current methods.
Pushing the Envelope of Residual Oil Measurement: A Field Case Study of a New Class of Inter-Well Chemical Tracers
Authors: Sanni Modiu , Al-Abbad Mohammed , Kokal Sunil , Dugstad Øyvind , Hartvig Sven , Huseby Olaf
Published: September 2016

The success of any improved oil recovery (IOR) project is largely dependent on how much oil is remaining to be mobilized within the targeted area of the partially depleted or mature reservoir. Partitioning tracers are generally used to measure residual oil saturation (Sor) or remaining oil saturation (ROS) in the near wellbore region via a single well chemical tracer test (SWCTT) or in an inter-well region via a partitioning inter-well tracer test (PITT). There is a limited repertoire of nonradioactive and environmentally friendly inter-well partitioning tracers for measuring ROS. A new class of environmentally friendly partitioning tracers was field tested, in a giant carbonate reservoir undergoing peripheral waterflood, for measuring ROS in inter-well regions in a depleted area.

The new partitioning tracers were qualified via laboratory experiments and are deemed to be very stable at reservoir conditions (213°F and a salinity range of 60-200 kppm). The field pilot was conducted concurrently with a set of non-partitioning inter-well chemical tracer test (IWCTT) to determine reservoir connectivity, water breakthrough times, and injector-to-producer pair communication in an area selected for an IOR/EOR field pilot. An elaborate sampling and analysis program was carried out over a period of 30 months.

This paper reviews the complete design and implementation of the test, operational issues, and the analyses and interpretation of the results. The breakthrough times of the passive and partitioning tracers are reported, and inter-well connectivity between the paired and cross-paired injectors and producers are analyzed. The ROS measured by a majority of the novel tracers is comparable to the saturations obtained via SWCTT, core and log derived saturations.

The combination of conventional IWCTT and the novel partitioning tracers via PITT has been very useful in analyzing well interconnectivity, understanding the reservoir dynamics and quantifying remaining oil saturation distribution in the reservoir. This has led to better reservoir description and an improved dynamic simulation model.
A Case Study of Water Injection Well Stimulation in a Low Permeability Oil Reservoir
Authors: Shaoul J. R. , Spitzer W. J. , Fekkai S. , Sepulveda L.
Published: September 2016

A newly developed oil field requires water injection for pressure support. Due to the relatively low permeability of the sandstone reservoir (10-15 mD), it was decided to perform propped fracture stimulation on all the injection wells before starting up the water injection operations. Performing propped fracture stimulation of water injection wells before starting up long term injection has several benefits, including lower initial injection pressures, less sensitivity to poor water quality and removing the risk of not being able to inject under fracturing conditions using the normal water injection system.

The initial attempts to perform fracture stimulations in the wells were not successful, as it was not possible to initiate a fracture (fracture breakdown) in 2 of the 4 wells, even after re-perforation. In the other two wells, it was possible to perform an injectivity test and a fracture treatment. In order to determine the cause of the problem, the data from the failed breakdown injection attempts for the first 2 wells was used as a welltest, and the pressure during injection and decline was history matched using a simple reservoir simulation model. This modeling confirmed that the reservoir permeability was not the problem, but that there was a significant skin present in the well, even after re-perforating. There was some type of formation damage present around the well which was deeper than the penetration depth of the perforations.

Finally, performing an additional hydrochloric acid squeeze and low rate fracture initiation sequence, it was possible to stimulate all the wells. Post-frac injection tests were performed for all wells, also with the collection of pressure decline data. The injectivity tests were analyzed using a numeric reservoir simulation model which includes an explicit gridded representation of the propped fracture. History matching of the flowing and buildup periods confirmed the propped fracture dimensions and the reservoir kh, which was as expected (or better) in all cases.

In the paper, the mechanisms that can prevent fracture breakdown even at pressures exceeding the overburden stress are explained in detail, as this issue occurs often enough to be of general concern. Methods of analyzing a failed breakdown injection are shown in detail, including how to diagnose whether the problem lies with the completion (no open perforations) or with the reservoir. The analysis of the fracture treatment data is shown, as well as the analysis of the post-frac water injection tests and initial injection data. Recommendations are made on the design of propped fractures for water injection well stimulation.
Leveraging Single Phase Characteristics of Water Injectors to Optimize Reservoir Pressure Surveillance
Authors: Bangkong Sabut A. , Al-Hajri Nasser M. , Al-Ajmi Mohammed D. , Al-Subaie Fehead M.
Published: September 2016

This paper presents a comprehensive field-scale engineering look into the application of single phase average gradient equation to obtain pressure surveys in water injectors. This methodology is sought to optimize well intervention operations in water wells while achieving all strategic master surveillance objectives.

Strategic reservoir pressure surveillance necessitates surveying water wells in a given field. Several key water injectors are surveyed with increased frequency and are drilled in spatially selective locations. The objective of such surveys is to generate representative reservoir isobaric maps in order to guide field development activities and reservoir production/injection management.

The current practice to obtain reservoir pressure data from water wells is through wireline intervention. An extrapolation method of Shut-In Wellhead Pressure (SIWHP) using an average water gradient to calculate Static Bottom Hole Pressure (SBHP) was rigorously examined and proofed accurate in the field. Raw data from more than a hundred strategically placed water wells were analysed and contrasted against measured data obtained from downhole pressure gauges to validate the proposed methodology.

Sensitivity and error distribution analysis of existing data was performed to quantify the effect of different reservoir characteristics and injected fluid quality. Key findings and recommendations were generated in light of the above analyses with regards to the proper selection of candidates to apply this methodology.

The application of this innovative approach has generated a significant cost saving and reduction of man-hours. As for well intervention, the number of wireline operations to obtain SBHP for key water wells was reduced by 75%.
Implementing Technical Improvements of ESP Application in Water Supply Wells for Extending Lifetime and Operation Efficiency
Authors: Al-Kady Alaa A. , Al-Mulhim Abdullah A. , AL-Subaie Fehead M. , Cumings Matthew , Al-Jandal Ahmed A. , Al-Zain Ahmed K. , Mulhem Abdulaziz H.
Published: September 2016

Electric submersible pumps (ESPs) are considered to be a very cost effective artificial lift method by industry standards, particularly in water supply wells (WSWs). In four WSWs, ESP performance had experienced a number of premature failures, which resulted in short average run lives of less than 1 ½ years, high operating costs, and unsustainable water supply required for injection pressure support and field development. To ensure that future ESP application in these wells is successful and improve run life, a multidisciplinary team was formed and conducted a comprehensive review to identify the causes of previous ESP failures and recommend methods to improve current practices based on all gathered engineering data; including, dismantle results of pulled ESP units, well and reservoir data, completion strategy, ESP equipment design, commissioning, and data monitoring.

The analysis indicated that the failures were primarily the results of corrosion and solids, and lack of close monitoring of ESP performance review, which prevented rectification of the problems in a timely manner. Secondary problems were also identified, such as tight wellhead clearance that damaged wellhead penetrators during installation, failure of tubing internal coating, and insufficient wellbore cleanout before making up ESPs during workovers, etc.

This engineering approach has successfully helped to increase confidence in, and reliability of, ESP operations, optimization, sustained field production levels, and reduced capital and operating costs due to improved pump run life.

This paper reviews the performance of ESP systems in WSWs and the challenges faced during the past 4 years of operation. Also, it covers installations, commissioning, dismantle inspection failure analysis (DIFA) results, operation philosophy, optimization methodology, average ESP run life, and ESP technical improvements.
Advancement in Openhole Sand Control Applications Using Shape Memory Polymer
Authors: Wang Xiuli , Osunjaye Gbenga
Published: September 2016

This paper summarizes a game-changing technology using shape memory polymer (SMP) to provide downhole sand control in openhole environments.

An openhole completion maximizes well productivity/injectivity and longevity without the concern of plugging and/or collapsing perforation tunnels that are frequent challenges in cased-hole completions. Conventional openhole sand control techniques include stand-alone-screen (SAS), expandable screens and openhole gravel packing (OHGP). In some cases, the uniformity, size and level of compressive strength of the formation dictate the use of an OHGP completion. This has proven to be a highly effective technique and eliminates the concerns of plugging and erosion associated with a SAS.

However, an OHGP is not always feasible and/or practical for some reservoirs and geographic locations. Some of the challenges of OHGP include lack of deck space and equipment, incompatibility with annular zonal isolation tools, difficulty to gravel pack across shale zones, and unavailability of equipment or fluid design to effectively gravel pack extremely long laterals without exceeding reservoir fracture gradient. The SMP technology can fill the gaps that exist with current OHGP techniques.

The performance of the SMP centers on its inherent glass transition property. It is run into the wellbore in its compacted state and then activated to expand to the openhole size at the target depth when exposed to a catalyst. Once expanded, the SMP conforms to the sandface including washouts and any irregularities within the SMP expansion limit. It is porous in both compacted and expanded states with permeability of over 30 Darcy after expansion. Its filtration capability is equivalent, if not superior, to that of an OHGP application.

In this paper, the SMP’s "engineered" behavior and sand control mechanism will be introduced first, followed by the performance comparison between the SMP and conventional OHGP, activation fluid design and the operational procedures. The last section will be focused on the SMP operating envelopes.
An Effective Utilization of Internal Resources, a Cost Intensive Approach to Develop Technical Competencies of Subsurface Manpower
Authors: Al-Daihani Eisa Hadi , Nandi Arun Kumar , Raza Syed Mohammad
Published: September 2016

Effective competency development of a technical staff is a combination of awareness, knowledge, skills and attitude that must be demonstrated in order to meet the performance standards required of their jobs. A competency model supports effective learning and development of technical work-force besides, helping objective performance appraisal and systematic career growth. These will result in improved job satisfaction, better talent management and employee retention. Such approach of competency modeling of different job families in Upstream National Oil Companies will empower them to achieve their goal with admirable clarity, better hydrocarbon discovery index cum increase in production and field management expertise.

The present paper focusses on an approach to the identification of Senior Employees under different subsurface groups with proven track record with coaching / mentoring abilities and utilizes them to develop not only the new hires but also the mid-career employees as subject discipline experts. It emphasized on a well-defined technical career recognition scheme for their technical contributions and provided them with a career path that offers recognition and reward. The paper emphasizes the need of utilization of these internal resources of discipline experts to develop few in-house courses and workshops for new hires to operational employees (mid-career level employees).

The paper illustrates the utilization of discipline experts as coach / Mentor for in-house OJT programs to upgrade the skill requirement of technical manpower. These discipline experts act as assessor for in-house training courses also. Besides, they help in developing a customized competency matrix based on the critical business need of the company. This is a cost effective approach with win-win situation for the employer and employees.
Use of Flow Control Valves to Increase Potential and Reserves on a Mature Field
Authors: Le-Roch J. F. , Fernagu J. , Marvillet C. , Sofyan M. , Briz-Quintero X.
Published: September 2016

Al-Khalij is a complex carbonate oil field located off the coast of Qatar that has been under production since 1997. Its development is based on long horizontal producer wells crossing several layers and equipped with Electrical Submersible Pumps (ESPs) as artificial lift method. Water injectors are used for pressure support and sweep efficiency. Despite an intensive open hole acquisition program, well behavior monitoring remains challenging due to the reservoir complexity and uncertain water production mechanism. Moreover, wells are mostly equipped with Dual ESPs, making cased hole acquisitions (such as spinner logs or saturation logs) not applicable. In order to tackle the observed continuous oil production decline, a new strategy has been implemented since 2007: installing Flow Control Valves (FCVs) as part of the completion strings.

Since then, 26 producer wells have been equipped with up to 3 FCVs each. These FCVs are hydraulically controlled from surface and packers are used to isolate the completed zones. As FCVs appeared to be reliable (success ratio close to 100%), they have, since 2011, been systematically installed on new wells or during work-overs for ESP replacements. The expected reservoir monitoring benefits were to better understand the well behavior of long horizontal drains with commingled production and differential depletion and to have a partial substitute for spinner log acquisition. The expected reservoir-management benefits were to have more flexibility for controlling the water production and balancing the liquid withdrawal from the reservoir and thus limit interferences between wells.

In the end, the added value from FCV installation on Al-Khalij wells was above expectations. Indeed, in addition to the previously mentioned benefits, the flexibility brought by FCVs allowed reservoir engineers to be more aggressive on perforation strategy and drain extensions for appraising new areas. Consequently, new upsides were identified leading to additional infill wells in the southern part of the field. After a continuous decline observed since 2006, Al Khalij oil production has now been stabilized and the overall water cut of the field has slightly decreased. Following this evaluation the field reserves have been reevaluated and new projects are still to come …
Using Turbine Technology to Run Casing, Liners and Completions to TD in Challenging Wells in Saudi Arabia
Authors: Okot Mike , Chima Jude , Muqeem Muhammad , Hajji Ali , Ramirez-Narino Alfredo , Al-Haj Haitham , Rider John , Wardle Magnus , Prescott John
Published: September 2016

Reactive formations, resulting in wellbore instability, can obstruct the running of casing, liners, and completions. This problem is particularly acute in highly deviated, complex wellbore geometries, and long horizontal sections, where increased exposure time can lead to deteriorating hole conditions.

This paper reviews the use of a novel fluid-powered Turbine Reamer Shoe (TRS) to successfully run 9⅝in casing, 7in drilling and production liners, and 4½in liners and completions through problematic intervals and hole conditions. The downhole turbine provides high speed reamer rotation without rotating the entire string, and requires minimal modification to standard running practices.

The 9⅝in and 7in casing/liner running turbines present a further novel design feature: an unobstructed through bore (at API drift ID of the string on which it is run) for rapid drill out and drilling ahead.

Results from over 30 onshore and offshore wells from the Manifa development, and several other fields, including Berri, Zuluf, Qatif, and Safaniya are analysed.

The TRS is now becoming a technology of choice in the planning of challenging wells, to mitigate the risk of sticking, and to reduce the flat time and HSE exposure involved in conditioning the wellbore and re-running casing, liners, and completions.
Drill Rig Control Systems: Debugging, Tuning, and Long Term Needs
Authors: Pastusek Paul , Owens Michael , Barrette Dave , Wilkins Victoria , Bolzan Alex , Ryan James , Akyabi Khalid , Reichle Melanie , Pais Darren
Published: September 2016

This paper documents some of the key findings on the data required and methods used to detect and correct issues with drilling control systems such as auto drillers, top drive active torsional damping systems, and heave compensation systems.

It has been found that the rig control systems and how they are tuned can have a significant impact on drilling dynamics. Issues related to drilling dynamics have varied widely among rigs, even among those that are in the same field and that have the same equipment and specifications. The standard answer has been that drilling is different on the ‘other side of the road, river, or anticline', or that one rig crew is better than the other. While there are significant differences in the drilling environment and between crews, recognition of the effects of the control systems employed can explain many of these differences and expand the tools and techniques available to improve drilling performance and reduce dysfunctions. Once the fundamental elements of a control system are understood, the performance limiters identified can often be applied to other rigs in the fleet with different systems via effective documentation of the changes made and their results.

Opportunities abound for improvement in oilfield drilling control systems, their basic design, and documentation on how they should be tuned and best used. There are also opportunities in crew training catered to different audiences: Drilling Engineers, Rig Supervisors, Drillers, Directional Drillers, and Rig Electricians. Lastly, there is often a knowledge and communication gap between the software/control/user experience and engineers designing the control systems. Since rig control systems are not usually identified as the source of drilling dysfunction, requests for software or interface redesign have not often been initiated in the past.

Not surprisingly, the best progress has been made when four way work groups were formed with all key stakeholders involved: the operator's drill team, internal technical experts, rig contractor and crew, and OEM control systems experts. Investing the time and personnel in this process and establishing group trust has helped prevent gaps in understanding of overall system performance. It also allows each stakeholder to contribute their expertise, raise concerns, and get buy in from their extended teams. This process takes commitment from all parties to change the way work is done, but the performance improvements are immediate and can be clearly seen.

Challenges for the future are to continue to upgrade rig site manuals, arrange for more crew training, upgrade the control system design, and to incorporate the control system response as part of the topside boundary condition for future drilling dynamics models.
The Thermal Limit of an HMX Perforating System for Through-Tubing Gas Well Operations
Authors: Barker James M. , Davidson John P.
Published: September 2016

For through-tubing perforating operations, it is important to consider jobs with temperatures above 360°F (182°C) at depths of approximately 15,000 ft. In this instance, the wireline conveyance time approaches 1.5 hours, which begins nearing the HMX thermal limit. This may require a switch to a higher-rated explosive, such as HNS, but unfortunately, this comes with an accompanying 20% loss of charge performance.

To guide perforating operations for these conditions, an experimental test-firing program was conducted to determine the performance of a 2.0-in. diameter HMX perforating system using 7.0-g shaped charges as a function of well temperature from 360–440°F (182–227°C). A novel two-step heating ramp was used to "thermally equate" perforating gun tests with shooting fixture tests. This experimental technique was necessary because of the large difference in thermal mass between the gun, which had a relatively small thermal mass, versus a shooting fixture whose mass was much larger for safety reasons.

The two-step heating-ramp tests showed that the temperature inside the perforating gun was still climbing toward the external well temperature even after the simulated 1.5-hr conveyance time. Temperature differences between the external gun surface and a charge located inside the gun ranged from 12–25°F (7–14°C). This thermal delay experienced by the gun worked to the advantage of HMX exposure, as the decomposition reaction for the explosive was also delayed. Taking the thermal delay into account, an upper temperature limit was established when perforating gas wells with the 7.0-g HMX-shaped charges inside 2.0-in. OD perforating guns. In addition, penetration performance for the HMX charge at various temperature levels was generated and then compared to baseline performance data that had been generated at ambient temperature.

The outcome of the test program provided guidelines for: (1) how far 2.0-in. HMX charges can be thermally pushed when perforating gas wells and still undergo proper ballistic functioning, (2) performance degradation of the 7.0-g charge as a function of temperature, and (3) recommendations for when to switch to higher thermally rated systems.
Combining Frequent 4D Seismic and Mechanistic Reservoir Modeling to Improve the Effectiveness of Steam Injection Operations
Authors: Przybysz-Jarnut J. K. , Wills P. B. , Araujo M. G. , Lopez J. L.
Published: September 2016

A permanent seismic monitoring system was deployed in Peace River Pad 31, to monitor areal steam conformance during pad re-development in this heavy oil field in Alberta, Canada. The dataset comprises a two-year monitoring period with seismic snapshots of the reservoir state available daily. These data were used within the Well and Reservoir Management framework to optimize production performance and increase field recovery (reported elsewhere). The field operations included, among other actions, a Cyclic Steam Stimulation (CSS) cycle carried out in an area with little connection to surrounding zones to promote communication with the rest of the pad. In this setting it was possible to perform a detailed mechanistic reservoir modeling study (described in this paper) aimed at explaining the unexpected well behavior observed during CSS. Insights from the combination of detailed reservoir modeling and frequent seismic data resulted in an improved understanding of reservoir dynamics including a pressure response strongly constrained by prior operations on the pad, the injection mainly in the vertical section of a horizontal well and the possible existence of a "patchy" saturation distribution. These learnings facilitated a better management of the pad and illuminate the issues to be expected in similar developments in the future.
Upscaling of Pore Connectivity Results From Lab-Scale to Well-Scale for Barnett and Haynesville Shale Plays
Authors: Davudov Davud , Moghanloo Rouzbeh Ghanbarnezhad
Published: September 2016

This study evaluates impacts of connectivity and pore distribution on gas transport through matrix of Barnett and Haynesville shale plays. Gas molecules are stored as compressed phase in pore space or as a desorbed phase on the surface of the pores. At the early stage of production, gas decompression within networks of induced/natural fractures "immediately" connected to the production stream is the dominant production mechanism; however, after some time (a couple of weeks up to few months) dispersive flux is triggered in response to the pressure drop realized at matrix-fracture interface. In this study, we compare the connectivity between two shale samples at lab-scale and verify the results with the production performance for few selected wells.

Using MICP porosity values measured at the laboratory for different sample size, we evaluate pore connectivity in Barnett and Haynesville shale plays in lab-scale. Next, we develop a new analytical solution to study the contribution of dispersive flux. In this model, we use a new set of boundary conditions as opposed to traditional Dirichlet and Neumann types of boundary conditions. Our transient flow model for gas transport through shale matrix accounts for the volume of connected pores and their abundance in the shale matrix. To verify the pore connectivity in large-scale, we choose few wells from gas producing parts of Barnett and Haynesville shale plays. We used conventional production data analysis (rate transient analysis) to identify the matrix contribution. Using the new analytical model, we compared the matrix contribution of Barnett and Haynesville shale plays for those selected wells.

We found an excellent match between connectivity results from MICP data and well production performance. Results indicate that higher connectivity, the greater the gas flux, everything else being equal. For that reason, matrix contribution to total recovery of Barnett wells are considerably higher than those of Haynesville. Results indicate that the connectivity of connected pores in the shale matrix has significant effect on the matrix contribution.

The main contribution of this work is upscaling of the pore connectivity obtained in the lab-scale to production performance in well-scale. In general, the pore connectivity can greatly influence long-term productivity of gas wells and the economics.
A Fully Coupled 3D Finite Element Investigation of Hydraulic Fracture Growth in Elastoplastic Rocks
Authors: Pirayesh Elias , Soliman Mohamed Y. , Morse Stephen M. , Emadi Hossein
Published: September 2016

Invaluable to both well stimulation and wellbore stability is the study of fracture initiation and propagation. The literature is rich with fracture tip phenomena theories. In particular, the effect of tip plasticity has been the subject of much debate. However, little has been done to investigate the effect of rock mass plasticity, a potential controlling factor in weak and compactible rocks. This paper advances a 3D dynamic computational model to replicate the growth of hydraulic fractures in elastoplastic rocks.

The proposed model is based on a non-linear Finite Element formulation that couples solid deformation and fluid flow. Rock is treated as a work-hardening elastoplastic material whose plastic deformation can be found using an associated flow rule. This paper features a new computational method to find material tangent stiffness tensor in non-linear Finite Element Analysis. A meshing/remeshing scheme is employed to maintain a high mesh resolution and to reach infinite boundary effect while keeping simulation runtime reasonable. The model tested successfully against analytical solutions for pressurized cracks and radially growing hydraulic fractures.

Due to the action of fracturing fluid pressure on fracture faces, normal stress increases on the fracture faces and a zone of tensile stress forms ahead of the fracture. The size of this zone dictates fracture growth rate. Due to plastic deformation, when subjected to loading, compared to elastic rocks, elastoplastic rocks experience less increase in normal stress on the fracture face and a smaller tensile zone. Combined with typically high permeability of compactible rocks, this results in slower fracture growth, larger fracture widths and higher fracture pressures. Another significant observation is that elastoplastic rocks can undergo shear localization, depending on rock properties, stress state and treatment conditions.

This paper presents a unique method to account for rock mass plasticity during fracturing operations. It showcases a robust 3D computational non-linear Finite Element model with a concrete physical foundation. Simulation results are in agreement with both laboratory and field observations.
A Semi-Mechanistic Model for Predicting Sand Erosion Threshold Velocities in Gas and Multiphase Flow Production
Authors: Shirazi S. A. , McLaury B. S. , Arabnejad H.
Published: September 2016

Sand production causes many operational problems for the oil and gas industry and can cause erosion of production equipment, well tubing, elbows and fittings. Operators would like to predict a threshold operational flow condition below which erosion failure is minimized. The API RP 14 E provides a guide to calculate a "threshold erosional velocity" in multiphase flow production, but this guideline is not intended for sand erosion! As an alternative to API RP 14E, a modified model for calculation of erosion in multiphase flow is presented that considers the effects of particle velocities in gas and liquid phases upstream of the elbow. Local fluid velocities in multiphase flow are used as a basis to determine representative particle impact velocities. Additionally, the effects of turbulent eddies near the elbow walls are considered through a particle Stokes number. Erosion experiments are also conducted on elbows in a 2 to 4-inch large scale multiphase flow loop with gas, liquid and sand flowing in vertical and horizontal test sections. Based on the experimental data for different flow regimes including slug, wet gas and annular flow, a method for improving a previous model has been discussed and is implemented to predict erosion rates in multiphase flow. The results from the model are compared to a variety of data and also to a state-of-the-art Computational Fluid Dynamics (CFD) erosion calculation model for multiphase flow for cases where data is available. The results from the current predictions are also compared to CFD calculation models for larger diameter pipes and higher pressure conditions, and the model predictions are found to be in good agreement with CFD results. The current model is by far much simpler than CFD methods that are utilized by some operators to predict erosion in elbows and tees. Yet the model predictions match CFD results for larger diameter pipes and field conditions. Additionally, this model can be used to determine threshold erosional velocity and thus is a potential candidate to replace the guideline provided by the API RP 14E.
Rate-Transient Analysis for Multistage Fractured Horizontal Wells in Conventional and Un-Conventional Homogeneous and Naturally Fractured Reservoirs
Authors: Kuchuk Fikri , Morton Kirsty , Biryukov Denis
Published: September 2016

We investigate the rate-transient behavior of multistage fractured horizontal wells in conventional and unconventional homogeneous and naturally fractured reservoirs, the latter of which can contain any spatial distribution of finite- or infinite-conductivity fractures of arbitrary length and orientation. The number and type of fractures (hydraulic or natural) intersecting the wellbore and self-intersecting is unlimited. We show that there are many factors that dominate the ratetransient behavior of horizontal wells intersected by multiple hydraulic fractures in naturally fractured reservoirs, such as fracture conductivity, length, and distribution, as well as whether or not fractures intersect the wellbore. It is shown that the magnitude of the fracture conductivity is one of the most important parameters that affects the production performance of multistage fractured horizontal wells. It is also shown that, as the space increases between hydraulic and natural fractures intersecting a horizontal well, the fracture pseudosteady-state flow regime tends to disappear.

Using the pressure and flow rate equivalency principle, we show that a production rate and/or cumulative production data set can be transformed into an equivalent pressure or pressure derivative data set. This is also very important for unconventional gas and oil reservoirs, where the boundary-dominated pseudosteady-state flow regime takes years to develop. A new technique is presented for determining stimulated reservoir volume (SRV) and production forecasting.

It is shown that rate derivatives exhibit unusual behavior, from which system identification and flow regime analysis become impossible. The material balance time does not totally correct the unusual behavior of the rate derivative. However, the deconvolved pressure of the cumulative production derivatives behave like pressure derivatives.
Flow-Biased Inflow Control Device Enhances Injection Rates While Still Maintaining Desired Production Resistance
Authors: Snitkoff Joshua , Abdelfattah Tarik , Russell Ronnie
Published: September 2016

Inflow control devices (ICDs) address uneven inflow along horizontals laterals. Heterogeneities in reservoir permeability and/or completion frictional effects are often cited as reasons behind uneven flow profiles along these wells. The configuration of the ICDs is designed to uniformly distribute flow along the lateral. Recently, demand for ICDs in injection applications has risen, leading to design initiatives on the part of operators and service companies that attempt to address more rigorous conditions (i.e., pressure and temperature in acidizing, SAGD, cyclic steam stimulation).

In carbonate reservoirs it is imperative to stimulate wells to enhance productivity and bypass possible induced damage during the drilling and completion phase (SPE 171750MS). The problem with current passive ICDs is that they restrict flow equally in the injection and production direction. Given the emphasis to reduce operational expenditures, rig time could drastically be reduced if the ICDs allowed a larger volume of flow to pass through during injection. This enables reduction in the operational time tied to intermittent acidizing cycles. The design discussed in this paper demonstrates the flow bias phenomenon for fluids flowing in the injection mode. Typically, to achieve this preferred flow a shifting sleeve would have to be activated, which requires an extra trip and introduces operational risk. In addition, the device was designed to withstand said cycles during acidizing while maintaining expected performance during the production phase. As such, the design was tested per an operator's detailed program, which required the device to maintain a certain level of durability and performance throughout the well life.
Use of DME as an EOR Agent: Experimental and Modeling Study to Capture Interactions of DME, Brine and Crudes at Reservoir Conditions
Authors: Ratnakar R. R. , Dindoruk B. , Wilson L.
Published: September 2016

Dimethyl ether (DME) is a small, slightly polar component, non-toxic that exhibits nearly ideal behavior with known liquid-state hydrocarbons, and is partially miscible with water/brine. In a multicomponent brine/DME/oil system, it partitions preferentially into the hydrocarbon phase. This unique characteristic of DME makes it a suitable candidate for enhanced waterflood while in essence water can act as the carrier fluid - it has the potential to unlock remaining oil from fields in a mature waterflood state. When DME mixed with brine is injected into the reservoir, it partitions preferentially into the oil phase (hydrocarbon phase) upon contact. As a result, the residual oil swells and its viscosity is reduced.

The amount of swelling and reduction in viscosity depend on how much DME partitions from brine into the oil and as well as the compositional characteristics of the oil. In addition, swelling and property changes are function of pressure-temperature conditions, DME concentration in oil as well as the salinity of the aqueous phase. Therefore, the estimation of the partitioning coefficient is very crucial to evaluate and understand the performance of DME enhanced waterflood (DEW) at reservoir or lab/pilot scale, as it controls the mass transfer from aqueous phase to hydrocarbon (oil) phase. In earlier studies, we presented the Equation of State (EOS) modelling and workflows to characterize the phase behavior of DME/brine/hydrocarbon mixtures that is encountered in reservoir processes, to estimate the partitioning coefficient, and calibrated and compared against the in-house experimental measurements. In this study, we extend the earlier work and perform extensive analysis on sensitivity of DME-partitioning coefficients with respect to pressure, temperature and salinities. In particular, we Present the comparison of predicting capability of the PVT models based on the two EOS: cubic plus association (CPA) [1] and Peng-Robinson (PR78) with Huron-Vidal (HV) mixing rules [2] against experimental data from literature or in-house measurements.Show that the model predictions are in agreement with the experimental observations.Present the extensive sensitivity analysis of DME-partitioning coefficient between oil and aqueous phases with respect to molecular weight of oil, temperature, pressure, salinities and DME concentration in oil phase, that can be utilize in quality check of the new data and preliminary screening criteria.Most importantly, develop an observation-based correlation to estimate partitioning coefficient for DME in brine and hydrocarbons, and to generalize the results for future screening studies where none or very limited PVT measurements with DME are available.
A New Model to Evaluate Two Leak Points in a Gas Pipeline
Authors: Guoqing Han , Zhenhua Rui , He Zhang , Kegang Ling
Published: September 2016

Natural gas is a clean fossil energy and an important sector in the energy consumption chart. Due to the increasingly environmental protection concern and natural gas's efficiency and reliability, the demand for natural gas increases steadily. To accommodate the ever rising in natural gas production and transportation, more gas pipelines are being constructed. Meanwhile, the existing gas pipelines are aging inevitably. One of the critical needs in flow assurance is detecting and locating pipeline leak in a timely manner. A reliable and timely detection of the leakage of gas pipeline can not only reduce the loss of hydrocarbon, but also limit the damage to facilities, possible loss of life, and the extent of environmental pollution. Two or more leakage points in a pipeline were observed in the field. Physical methods were employed to detect these leakages. However, literature review indicates that no mathematical model has been developed to detect multiple leaks in the same pipeline. This study is focused on the detection of two leak points in the same pipeline. Multi-flowrate tests are proposed to evaluate the locations and sizes of leakages in two leak points. This mathematical model is crucial when no physical inspection is available. The proposed model can be used to monitor possible leak in real-time because flowrate and pressure that are utilized to estimate multiple leaks are monitored in real-time and are available almost simultaneously. Therefore, the new method provides a practical, quick, and low computational cost approach to detect multiple leakages. The proposed method is important because existing mathematical models assumed single leak in a pipeline, which limits their applications because the detection will be misleading if there are more than one leakage in the same pipeline. The proposed model can differentiate single-leakage scenario from multi-leakage scenario based on multi-flowrate tests. The identification is critical because it guides the leakage detection to the right direction.