bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of Multiphase Pumping Stations Based on Reliability Analysis and Monitoring of Process Conditions at Huyapari Field - PetroPiar, Orinoco Belt
Authors: Mendoza O. Moreno , Johnson S. Rivas , Sierra J. Díaz , Gil J. 
Published: June 2014

Summary
The Huyapari field currently produces 160,000 BPD of 8.5 ° API extra heavy oil in cold production method. Blending naphtha of up to 60° API to obtain finally diluted crude of about 15.2° API.
Twin-screw multiphase pumps (MPP) are responsible for transporting the fluids from the well pads to the "Centro Operacional Bare" (COB), where the produced fluids are treated. The production is in charge of 21 pumps geographically distributed in 10 multiphase pumping stations, strategically located in the field.
In order to keep surface pressures controlled as low as possible and therefore contribute to achieve production commitments and business plan in the JV PetroPiar, an integral monitoring methodology has been designed. This work helps to evaluate and provide real-time recommendations for reaching optimum operating conditions contributing to maximize daily production as well as identifying opportunities for reliability improvements.
This monitoring program is linked to a reliability study conducted on a quarterly basis, which contributes to the execution of the work plans of the departments supporting the operation, with focus on reducing Lost Production Opportunity (LPO) with grater effectiveness.
The continuous evaluation and optimization of the performance of the MPP stations in real time according to operational changes (surface pressure, diluent injection rates, diluent quality, water cuts, and gas production rates, among others) allow for improving the reliability of this equipment and help to meet the production plan, which is currently over 96%.
This work also describes the results from the failure analysis conducted in the last three years to identify the main factors affecting the LPO. Additionally, the methodology to continue with the operational performance of each MPP station and its influence in the production system of the whole field is included.
The results of this work have shown a reduction of the LPO from 244 BPD in 2012 to 100 BPD in 2013 (annual average, reduction of 59 %). Other benefits are represented in the more effective contribution to the management of the resources for the equipment maintenance. The identification of opportunities for improvement based on root cause analysis has allowed for influencing on all the departments involved for accurate decision making with regards to the surface facilities operation in the field.
Development of a Fully Coupled Two-phase Flow Based Capacitance Resistance Model CRM
Authors: Cao Fei , Luo Haishan , Lake Larry W. 
Published: June 2014

Abstract
The capacitance resistance model (CRM) has become a popular complement to real time reservoir analysis and improved oil recovery in water and CO2 floods. However, the current CRM model is based on a material balance of the total fluid and only the pressure propagation equation is considered. Saturation changes are also important, especially when the water cut is small. To overcome this limitation, this paper proposes a coupled CRM model based on two-phase flow by incorporating an oil material balance and fractional flow theories.
In the coupled CRM model, we construct material balances on both total fluid and oil. Pressure and saturation equations are updated at each time step to account for changes of total mobility. By semi-analytically coupling the pressure and saturation in a producer-based control volume and using constrained multivariate nonlinear regression, the new coupled model can quantify the inter-well connection as well as the oil saturation. As a result, the coupled CRM model can be applied to the whole time frame of water and gas floods, not limited to late time (large water cut) cases as was the current CRM model.
This new CRM model is validated in heterogeneous synthetic fields using a conventional reservoir simulator. Case studies show that the saturation profile from the coupled CRM model matches very well with the simulation results. The connectivities obtained from the coupled CRM model correspond well with the field geology and the time constant for each producer is also changing reasonably with the total mobility. Validation of both total production and oil production rates showed that relative errors are very small. With estimated parameters from a waterflood, the model found an optimal injection strategy to maximize the field total oil production.
By incorporating the saturation variations to model two-phase flow, the coupled CRM model successfully overcomes the limitation of the previous version. It is able to extend the CRM model from mature water floods to immature water floods, which makes the CRM model more adaptable to different field cases. The coupled CRM model also improves the quality of the prediction of the oil rate significantly, especially for immature water floods. This work can lead to a more informed workflow of optimizing injection scheme, and serve the goal of improving ultimate oil recovery.
Forced and Spontaneous Imbibition Experiments for Quantifying Surfactant Efficiency in Tight Shales
Authors: Roychaudhuri Basabdatta , Xu Junyi , Tsotsis Theodore T. , Jessen Kristian 
Published: June 2014

Abstract
Surfactants have been used extensively in well completion practices and have been shown to favorably alter the wettability of a formation from highly water-wet to intermediate-wet, resulting in increased water recovery and in a reduction of water blockage around the wellbore. Spontaneous imbibition and contact angle measurements are the most popular methods for studying the efficacy of a given surfactant. Forced imbibition experiments on fractured cores under confining pressure provide a more realistic representation of the actual formation settings, but have not been used extensively to measure the effect of surfactant solutions. They are commonly avoided due to their additional experimental complexity when compared to their spontaneous imbibition counterparts. The forced imbibition data reveal information about the porosity and provide an estimate of fluid flow values under different confining pressures of the micro-fracture network and the core matrix from the imbibition rate. Compined with the pure water invasion rates, forced imbibition experiments with surfactants reveal potential impacts that the surfactant may have on a given formation.
In this work, 1 in by 1 in shale core plugs have been used to study the efficacy of a surfactant towards increased load recovery. Each core plug undergoes two forced imbibition experiments lasting 24 hr in succession: One experiment is carried out with pure water while the second experiment employs a surfactant solution. The permeability and porosity of the samples are measured before each experiment to be able to account for any changes to the cores as a result of the forced imbibition experiments. During forced imbibition, the fluid is injected at a pressure of 3500 psi. We observe an increase in water recovery of approximately 60% for a low (ppm-level) concentration of a surfactant solution. We argue that spontaneous and forced imbibition experiments provide more realistic observations of the capillary pressure effects at play than do contact angle measurements, and that they should be used together for direct quantification of surfactant efficacy in these tight porous materials under realistic reservoir conditions.
Unconventional Oil from California's Monterey Formation – Exploitation Results
Authors: Burzlaff Alan A. , Brewster David P. 
Published: June 2014

Abstract
There is a heightened interest in the exploitation of the California Monterey Formation as a source of unconventional oil reserves. Some publications have categorized the Monterey not only as an unconventional reservoir, but as an oil resource play similar to the Bakken and Niobrara. Over the past five years, major and independent oil companies have invested millions of dollars gathering 3D seismic data and have drilled hundreds of horizontal and vertical wells, both hydraulically fractured and acidized, to find the location of and relevant technologies for producing significant quantities of oil from intervals within the Monterey shale. This paper presents a five-year look back of the production results for the renewed industry drilling campaign targeting unconventional oil reservoirs in the Monterey. Relying on public records, this paper presents statistical information on the number of wells, Initial Productivity (IP), gas-oil ratio, water cut, and Expected Ultimate Recovery (EUR) for the onshore Monterey drilling activity during 2009–13 in the San Joaquin Valley of central California. Results show wells that are highly variable in terms of oil IP and gas-oil ratios. Key fields include the Rose, North Shafter, Asphalto, Railroad Gap, Buena Vista and Monument Junction fields. The production and reserves statistics are useful and informative to those interested in the productivity, economics and successful exploitation of the Monterey.
Management of Health and Safety Hazards in Oil and Gas
Authors: Floris Vinio V. 
Published: June 2014

Abstract
This paper reviews the principal health and safety hazards in the oil and gas industry with focus on unconventional gas and oil extraction activities. Risks include exposure to hydrogen sulfide, silica, hazardous chemicals, extreme temperature and fatigue, vehicle/transportation incidents, explosions and fires, falls, confined spaces, and risk of being struck-by/caught-in/ caught-between perilous objects. This discussion is accompanied by occupational health and safety statistics, description of hazards and the creation and implementation of a health and safety culture as a mean to mitigate (if not eliminate) harmful conditions.
A New Semi-Analytical Method for Analyzing Production Data from Constant Flowing Pressure Wells in Gas Condensate Reservoirs during Boundary-Dominated Flow
Authors: Sureshjani M. Heidari , Behmanesh H. , Clarkson C. R. 
Published: June 2014

Abstract
With the current focus on liquid-rich plays in North America, and the importance of gas condensate reservoirs globally, there is an increased importance placed on reservoir engineering methods to analyze such reservoirs. This paper provides a new semi-analytic boundary-dominated flow equation (BDFE) and also adapts the existing BDFE of dry gas reservoirs for production analysis of constant flowing pressure wells producing from gas condensate reservoirs. To analyze long-term production data, these equations are coupled with a modified material balance equation to give gas-in-place and average reservoir pressure obtained from plotting techniques which use iterative procedures. The required input data for analysis are gas flow rate, bottomhole pressure, CVD test data, and a portion of the immiscible gas relative permeability curve. We also introduce a new material balance time function for gas condensate reservoirs. To verify our analysis methods, compositional numerical simulation is used. We also test the practicality of our approach through analysis of field data.
Tensile Failure of Shales: Impacts of Layering and Natural Fractures
Authors: Mokhtari Mehdi , Bui Binh Thanh , Tutuncu Azra N. 
Published: June 2014

Abstract
Shale formations present anisotropic characteristics in mechanical, acoustic, and flow properties due to their layering and pre-existing natural fractures. This anisotropic behavior can create a complex fracture network rather than the conventionally presumed planar fractures. Although incorporating anisotropic behavior is essential for optimizing the hydraulic fracturing design and analyzing the post-fracture data, there are limited studies addressing the anisotropic tensile behavior of organic-rich shale formations. The objective of this study is to explore the tensile strength and tensile fracture patterns in shales by conducting splitting tests on variety of shale formations.
Core samples from the Eagle Ford shale in the oil window, its overlying Austin Chalk and the underlying Buda formation, Green River immature oil shale, Mancos shale, and Berea sandstone samples have been tested to investigate the effects of layering, natural fractures, total organic carbon (TOC), maturity and mineralogy on tensile behavior. Having different types of Green River shale, the impact of TOC on the tensile strength was obtained. The anisotropic tensile behavior of Mancos and Green River shales were studied systematically at various orientations between the applied force and the bedding direction providing key understanding on the fracture growth patterns at any direction. Finally, the tensile strength and fracture patterns for several Eagle Ford, Austin Chalk and Buda core samples with extensive natural fractures are discussed.
Sensitivity Study on Storage of CO2 in Saline Aquifer with Fracture-Surrogate Models Based on the Tensleep Formation
Authors: Alvarado Vladimir , Yu Meng , Chang Yang , Marcy Peter , Huzurbazar Snehalata , Lynds Ranie 
Published: June 2014

Abstract
For industrial-scale CO2 injection in saline formations, produced CO2 and pressure buildup can limit storage capacity and efficiency. Sensitivity analysis on operational strategies and reservoir parameters serves to select the optimum injection strategy to increase injectivity, relieve pressure buildup, improve CO2 trapping efficiency, and constrain brine leakage. In this paper, we developed a surrogate model for aquifers in the Tensleep Formation based on features of the the Tensleep reservoir at Teapot Dome in Wyoming. The corresponding oil reservoir model was history-matched using production data from the Teapot Dome. The history-matched simulation model was turned into an aquifer by eliminating the oil phase, but preserving the main geological traits. We then proceeded to investigate operational strategies to achieve an effective tradeoff between higher CO2 trapping efficiency and delayed CO2 breakthrough at producers. A well architecture consisting of two horizontal production wells completed at the bottom of the aquifer downdip and two vertical vertical injection wells completed updip in the reservoir. A 50-point experimental design, aimed at evaluating the effect of depth, porosity and permeability on CO2 storage, was conducted in four models: single-porosity model without solubility, single-porosity model with solubility, dual-porosity model without solubility and dual-porosity model with solubility. The result of the 50-point design shows that compared to single-porosity models, CO2 trapping efficiency is lower in dual-porosity models. In addition, the small variability in trapping efficiency for dual-porosity cases was almost completely explained by depth. This contrasts with the single-porosity models whose large variability in CO2 trapping efficiency was explained primarily by porosity, then permeability, and finally depth. We demonstrated the value of selecting optimum injection rates and well configurations considering effects of natural fractures and solubility on storage capacity. The results of the study provide insights either in selecting the operational strategies for CO2 storage in fractured reservoir systems or analyzing the effect of reservoir parameters on storage capacity and efficiency in saline aquifers in terms of regional considerations.
New Production-Decline Models for Fractured Tight and Shale Reservoirs
Authors: Ali Tariq , Sheng James , Soliman Mohamed 
Published: June 2014

Abstract
Production decline curve analysis is one of our common methods to estimate production rate profile and ultimate recovery of a tight or shale gas reservoir. Because of the long transient behavior of low-permeability gas reservoirs, early production data generally exhibits fracture-dominated flow regimes and late-time flow regimes have not reached yet. These challenges the robustness of production decline curve analysis in such reservoirs, and this also question the validity of several models presented in the literature.
If a well produces at a constant flowing pressure, a log-log plot of rate divided byover cumulative gas production vs. cumulative gas production yields a straight line, and cumulative gas production vs. time yields another straight line as well. Based on these two relationships and real data observations, new production-decline models are proposed in this paper.
The proposed models are verified by a large number of well production data in tight and shale reservoirs. These models are also validated by numerically simulated cases. Under some special conditions, the proposed models can be used to validate some published models. Many real data and simulate data show that the proposed models can be reliably used to estimate production rates and the ultimate recovery in tight and shale reservoirs.
Unique Application of EM LWD Casing Antenna System to Rocky Mountain Drilling
Authors: Hunter J. , Maranuk C. , Rodriguez A. 
Published: June 2014

Abstract
Certain formations in the Rocky Mountains preclude the use of electromagnetic (EM) telemetry due to their inherent resistivities. A new system has been developed that extends the use of EM telemetry systems where they were previously not usable. The system involves installing a special downhole antenna when surface or intermediate casing is run to improve EM signal to noise ratio. The casing antenna system not only allows operators to take advantage of the benefits of EM logging-while-drilling (LWD) systems but also extends the drilling depth range where data can be provided.
Drilling wells in the Powder River Basin often requires heavy mud weights and the extensive use of lost circulation material (LCM). Unfortunately, these types of muds play havoc on standard mud pulse telemetry systems. Washed equipment and downhole failures related to plugged pulsers often result in multiple trips for failures and excessive nonproductive time (NPT). This new EM LWD system, by contrast, has no moving parts and a through-bore, which allows for higher concentrations of LCM and heavy weighting materials to pass easily through the bottom hole assembly (BHA). The system is combinable with a variety of LWD sensors so the telemetry type proves especially useful in areas that experience high LCM incidents. A key aspect of this system is that it also extends the depth range of where EM LWD systems can operate.
Along with a compensated resistivity tool, a unique LWD spectral azimuthal gamma ray (SAGR) sensor, which provides accurate formation evaluation data, high quality gamma ray images and spectral elemental analysis, was used to help geosteer the well to stay in the zone of interest in the reservoir. This paper will examine a case study where the new system was used in an area where drilling with EM was not previously possible. It will describe the basic system design, key operating parameters, provide insight on the drilling problems, and address formation evaluation challenges and solutions.
Understanding the Implications of Multiple Fracture Propagation in Well Productivity and Completion Strategy
Authors: Mata D. , Dharwadkar P. , Gonzales V. , Sitchler J. , Cherian B. 
Published: June 2014

Abstract
The revolution of the multistage horizontal completions has made low-permeability laminated reservoirs a cost-effective business. The key to success relies on maximizing the surface area contacted, a process that requires an adequate stage isolation technique. From traditional "plug and perf" to efficient sliding sleeves, the application of a particular system is related to the number of fractures that can be propagated during a single treatment injection. This condition varies according to rock and reservoir properties, principal stresses, zonal isolation and stimulation design.
This study introduces a methodology to build predictive, repeatable models that integrate reservoir characteristics (mineralogy, pore pressure, thickness) along with geomechanics (anisotropic Poisson's Ratio, Young's Modulus, and horizontal stresses) and fracture pressure diagnostics (pressure history match, near-wellbore pressure analysis) to predict the likelihood of propagating multiple fractures per stimulation stage. Examples of the application of this workflow to select the suitable completion mechanism are provided using multiple datasets from the Williston Basin. Additionally, a calibrated production model measures the impact of a specific zonal isolation method on well productivity.
Finally, this paper concludes with a series of sensitivities to determine the influence of different reservoir and rock properties in fracture propagation and provides recommendations regarding data requirements to apply this methodology in a particular field.
Nikaitchuq Project Vibration Mitigation Strategy
Authors: Wright James , Borri Luca , Simeone Davide , Longo Joseph , Weber Matt , Barnes Brandon 
Published: June 2014

Abstract
The eni Petroleum Nikaitchuq field is located offshore in the Beaufort Sea within the North Slope region of Northern Alaska. The 12-1/4" intermediate section of the Nikaitchuq wells are drilled with a Rotary Steerable System (RSS) at high inclination prior to landing near-horizontal in the reservoir. The intermediate hole section passes through a very abrasive sand with an unconfined compressive strength (UCS) of approximately 22 ksi called the Lower Ugnu.
Historically, the drilling of the 12-1/4" intermediate section has been drilled with two to three bit runs consisting of various polycrystalline diamond compact (PDC) and tri-cone designs. This was due to the abrasive nature of the Lower Ugnu combined with interbedded soft sand causing ledging, high stick-slip and lateral vibrations which lead to consequential bit/BHA damage and a reduction in drilling efficiency.
With the objectives of drilling the section in one run and to minimize damages to the RSS and MWD, a vibration mitigation workshop was conducted between the Nikaitchuq drilling team and key service company experts. The workshop team focused on four strategies to mitigate vibrational issues:
Bottom Hole Assembly modification. Introducing new technologies and tools into the drill string to capture high density data and mitigate vibration. Mapping and prediction of the hard streaks within the intermediate section. Modification of drilling practices where possible.
BHA and bit vibration modeling, new vibration mitigation tools, Measurement While Drilling (MWD) and multi-axis downhole vibration measurement data, BHA and stabilizer reconfiguration, as well as implementing various drilling parameters were all investigated and applied in both the front end and at the rig site.
This paper demonstrates the systematic approach the Nikaitchuq drilling team implemented to mitigate damage to the bit and downhole tools as well as improve drilling performance by minimizing stick-slip and lateral vibrations.