bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.