bluuebunny/crossref_metadata_2025_split huggingface dataset:
Stress Redistribution Analysis in Multiple Eccentric Packers During Completion Operations
Authors: Zhang Yuan , Samuel Robello 
Published: June 2014

Abstract
Advancement in multiple zone completion has been quite rapid in recent years but it poses numerous operational challenges that adversely affect the efficiency of the completion process. In addition to increasing the number of activities involved in horizontal drilling, a lot of packers are used during completion which results in various problems during pulling out and running in. These problems include increased torque and drag and buckling. The increasing complexities of wellbore geometry imply an increasing potential for damage when running packers for completion operations.
In addition, hole diameters vary frequently during the drilling process. When the diameter of the casing changes, even though the production tubing size remains the same, the packer usually becomes eccentric. Current methods are not modeled properly and severely underestimate stress values and pick-up loads when completion strings are run in.
Normally, a packer is designed for central symmetry. When a packer is in an eccentric position, the stress in the packer gets redistributed to suit the eccentric condition. In addition, the pressure limitation is also changed. This study describes a new analytical model for estimating the stress distribution in eccentric packers by assuming that the packer material is elastic. This study concludes that when the packer is run into an eccentric wellbore, the stress distribution in the packer changes and the pressure limitation of the packer decreases. A methodology and a mathematical model have been developed to calculate the stress and the pressure limitation of a packer with an eccentric profile.
A Novel Forecasting Model for Chemical Flooding Enhanced Oil Recovery
Authors: Mollaei Alireza , Delshad Mojdeh , Li Zhitao 
Published: June 2014

Abstract
Chemical enhanced oil recovery (EOR) method includes the injection of a mixture of chemicals to improve sweep efficiency and produce residual oil saturation left behind in the swept volume after waterfloods. The way chemical flood works is by the synergistic effect of polymer to improve mobility (slow down the movement of water to match that of the oil, i.e., mobility ratio of 1) and surfactant (with or without alkaline) to reduce the interfacial tension between oil and water to displace the discontinuous trapped oil remained in reservoir after the waterflood. Surfactant flooding uses the same concept as using detergent/soap to remove oil. The primary objective of surfactant/polymer (SP) or alkaline/surfactant/polymer (ASP) flooding is to reduce the interfacial tension between oil and water to values on the order of 0.001 dyne/cm or less in order to displace the trapped oil from rock pores.
We present a novel method to predict the results of the chemical EOR processes using an analytical and robust forecasting model. This fast and simple analytical approach will aid to screen chemical EOR projects where numerical simulations are not feasible due to either lack of data or the time and expertise required conducting such studies.
The proposed forecasting model is based on a general approach for predicting the performance of isothermal EOR processes. The model incorporates fundamental principles of material balance, segregated flow and fractional flux while with effects of mobility ratio, chemical slug size, miscibility and reservoir heterogeneity. The permeability heterogeneity is modeled using Koval fractional flux model with its applicability to wide range of permeability and degree of heterogeneity. The forecasting tool has been successfully validated against numerous SP/ASP field and numerical simulation results.
We also developed correlations to describe the model variables as functions of mobility ratio, slug size and reservoir heterogeneity based on the experimental design methodology and numerical simulation. Successful history matching against numerical simulation results and the strength of the developed correlations proved the ability of the model to predict SP/ASP results when field results are not available.
The forecasting tool provides key results to assess the flood performance. These include average oil saturation, cumulative oil recovery, oil cut, oil production rate, recovery efficiency and volumetric sweep efficiency as functions of time. An estimate of volumetric sweep efficiency helps in a better design and increases the chance of successful field projects.
Fully Integrated Approach Using Temperature Measurements to Describe Complex Reservoirs: Case Study from Saudi Arabia
Authors: Al-Mutairi Saad , Alghazal Mohammed , Alhuthali Ahmed , Cole John 
Published: June 2014

Abstract
Reservoir heterogeneity and inter-reservoir communication due to fracturing pose major challenges for our industry in terms of reservoir characterization and fluid flow modeling. Improved understanding and representation of their role in static and dynamic models is becoming a pivotal component for effective field management. Normally, multiple sources of both static and dynamic information are integrated to generate models used to simulate reservoir performance in order to identify optimal practices for efficient production and recovery.
This paper presents a thorough reservoir study focused on the investigation of the use of temperature measurements to inform on fluid flow within and between reservoirs. The study addresses mainly the communication that exists in the reservoir beyond the well-bore, attributed to fracture corridors and faults. The interpretation of temperature measurements are integrated with other sources of dynamic and static information such as open-hole logs, production profiles, fluid losses, and pressure transient analysis. The study area covers a portion of an oil field that has been under peripheral water flooding for more than 30 years, producing mainly from the upper of the two reservoir units. As expected, the injected cold water imposes a significant variation in temperature profile across the reservoir which helps to describe the flood performance and understand the underlying geology. Additionally, we found that the rate of change of temperature with respect to time over the entire area shows that increasing temperatures are correlated with locations showing high structural relief. Our existing mapping shows these areas as being more densely fractured, with high fluid flow capacity. The coincidence of these factors with the temperature anomalies we observed strongly suggests that the faults and fractures in these areas may be responsible for mass and heat transfers between the two reservoirs.
The outcomes of this study are used to optimize development and production plans such as balancing the off-take between high-structure and down-dip areas to prevent undesired water flood advances. They are also fully integrated with other sources of information to construct geological and flow simulation models in order to assess sweep performance and recovery estimation.
The Condition of Capillary Condensation and Its Effects on Adsorption Isotherms of Unconventional Gas Condensate Reservoirs
Authors: Li Baoyan , Mehmani Ayaz , Chen Jinhong , Georgi Daniel , Jin Guodong 
Published: June 2014

Abstract
Traditionally, Langmuir isotherms are used as the adsorption isotherms of coal bed methane and shale gas. To model the adsorbed multi-components of hydrocarbons, the Langmuir isotherm for the single component is extended to the Langmuir isotherm for multi-components. A Langmuir isotherm is simple, but it is based on the assumption that the adsorption is a single molecule layer adsorption. Its adsorption mechanism is adsorption-site filling.
For shale gas reservoirs, the adsorption of gas could be multi-layer adsorption, because of the small sizes and wettability of nanopores in the kerogen source rocks. Particularly for gas condensate reservoirs, such as the Marcellus shale gas reservoir, capillary condensate could exist, due to the confinement of kerogen pores, i.e., the adsorbed gas becomes condensate to fill the pores at the pressure below the dew-point pressure. For capillary condensation, therefore, a Langmuir isotherm is not valid.
The conventional Kelvin equation can be used for computing the isotherm of capillary condensation. However, it is limited to the single component. We introduce a method, which is based on the generalized Kelvin equation, to compute the adsorption isotherms of capillary condensation for multi-component hydrocarbons.
This new computation method enables us to investigate the condition of capillary condensation and relation between pore size and condensation line. Furthermore, we check the capillary condensation effects on the adsorption isotherm caused by fluid composition, pore-size distribution, temperature, and pressure. We predict the phase behavior for the Marcellus shale reservoir. The computation results show: When the temperature is less than pore critical temperature (lower than the cricondentherm temperature), capillary condensation can occur.For shale gas formations, if the hydrocarbon composition includes some heavy components, capillary condensation can occur, depending on pore-size distribution, composition, and pressure.Large standard deviation of pore size will smooth the adsorption isotherm for capillary condensation.As pore size increases, capillary condensation occurs at pressures close to the dew-point pressure.Capillary condensation can occur in the Marcellus shale formations.
Managed Pressure Drilling, Casing and Cementing Enables Success in Conventionally Undrillable Wells in the Harding Field
Authors: Mashaal Mohamed A. , Fuller Tom , Brown Chris J. , Paterson Robert 
Published: June 2014

Abstract
Managed Pressure Drilling (MPD) has been used around the world to help drill wells where there is a tight mud weight (MW) window, due to the ability of the technology to more accurately control annular bottom hole pressure (BHP) while drilling, tripping and during connections. This paper presents the case history of the Harding PNE2a well design and execution in 2012, with particular focus on the planning process, design methodology and execution particulars associated with the use of MPD as the enabling technology to drill, case and cement the well. The team also employed a novel Fluid Pressure Transmission Pill (FPTP)i, composed of a cross-linked polymer, to maintain hydrostatic pressure while tripping BHAs and during deployment of the liner and sand control equipment.
Earlier attempts to drill Extended Reach Drilling (ERD) wells from the Harding platform to the PNE4 and PNE2 reservoir targets resulted in drilling issues including packoffs and severe lost circulation due to BHP departing from the tight window of useable mud weights between the pressures at which the formation is expected to collapse or fracture. Use of MPD on the PNE2a well directly contributed to achievement of the well's objectives, and the operation was able to provide good control of BHP throughout the well construction process, in both 12-1/4" and 8-1/2" sections. This led to the long unstable shale sections being maintained with no cavings being observed while drilling, a first for the field, and the cementation of the long 9-5/8" liner being performed without losses despite the tight operating window and the use of conventional cements.
Production Analysis in the Barnett Shale – Field Example for Reservoir Characterization Using Public Data
Authors: Pratikno H. , Reese D. E. , Maguire M. M. 
Published: June 2014

Abstract
Development of unconventional reservoirs continues to expand in North America and has gained interest worldwide. The first unconventional play to be rapidly developed is the Barnett Shale located in North Central Texas. As of July 2012, the Barnett Shale had more than 13,000 multi-staged fractured horizontal wells (MFHW) with approximately 2,500 of these wells with over five-plus years of production history. In addition to these MFHW, there are approximately 3,000 vertical wells in the Barnett Shale.
Well spacing is a key value driver for field development and needs to be addressed early in the appraisal process. Interpretation of early production analysis from MFHW can provide many insights into the reservoir and fracture characteristics of these wells. However, these interpretations are non-unique until end of linear flow (ELF) is reached. This study used public production data that lacks wellhead flowing pressures. For this study the wells that did see end of linear flow did so in a time period where flowing pressures are expected to be relatively constant and therefore having measured pressures was not deemed necessary. Reservoir permeability, fracture half-length, and original-gas-in-place of the area contacted by the created hydraulic fracture network can be determined once end of linear flow is reached. Once fracture half-length and permeability have been determined, the appropriate well spacing can be estimated using simulation and economics.
A comprehensive review of approximately 2,500 MFHW using public data within two Northern counties of the Barnett Shale found more than 100 wells where end of linear flow could be clearly observed in production characteristics. With the end of linear flow determined for these wells, estimates of permeability and fracture half-length were determined. A single well simulation study feeding an economic evaluation was then used to study well spacing and yield suggested optimum development spacing. This paper will review all of this work, the results and conclusions, and provide observations of some of the trends.
Front Line Leadership in the Oilfield
Authors: Horn Aaron D. 
Published: June 2014

Abstract
The United States has a path to energy independence through the economic development of domestic unconventional resources. At the same time, the oil and gas industry faces a generation gap as many baby boomers in leadership retire. Compounding the generation gap is the industry's general trend to promote people to leadership positions based on technical ability, assuming technical acumen will translate to leadership acumen. This paper puts forth a military-influenced model for leadership in the industry and provides analysis of the results of a survey regarding front line leadership.
Leadership is the art of influencing not only one's subordinates, but also one's peers and superiors in the accomplishment of a common objective. This paper proposes a model for effective front line oilfield leadership as the embodiment of five traits—self-awareness, humility, honesty, courage, and persistence—and the adoption of five habits— leading by example from the front, knowing your people, treating people as they can and should be, communicating effectively, and being decisive (but not in a vacuum). The focus is on leadership at the front line, where technical staff interacts with field staff to accomplish the mission. The oilfield relationship between technical staff and field staff is similar to that in the military, which is central to the author's argument for the proposed leadership model. The paper also summarizes a survey conducted of approximately 100 oilfield personnel, ranging in age, experience, job function, and organization type. The survey results provide insights into the current state of leadership in the industry, using the proposed leadership model as a guide for the assessment.
These findings support the author's three primary conclusions. First, there is a need for collective focus on core leadership principles to obtain the best, safest performance from a generationally lopsided workforce. Second, the survey offers multiple perspectives across a broad demographic regarding the relative importance of the leadership model's traits and habits and how they relate to one another. Finally, an analysis of survey data provides perspective on the conflicting perceptions regarding leadership between different industry demographics, most notably between executives, management, technical staff and field staff.
Should the industry continue on its growth trajectory, the lack of adequately trained leaders has profound ramifications, ranging from decreased capital efficiency to increased accident rates. Focus on the leadership ability of tomorrow's leaders should not wait until tomorrow.
Modeling and Prediction of Frac-Pack Tool Erosion
Authors: Lee Erik , Russell Ronnie , Williams Thomas , Carbone Frederick , Clem Nicholas 
Published: June 2014

Abstract
Reservoirs continue to push the envelope in frac-pack stimulation rates and proppant volumes. Consequently, the tools delivering these stimulations must be qualified using testing procedures that replicate actual job conditions, as closely as possible, to ensure the integrity of the tools when deployed in these challenging environments. High stimulation rates and large slurry volumes, which must be replicated in a testing environment, require an investment in assets and logistics on the order of that required for an actual deployment. Therefore, testing parameters must be selected based on those anticipated in the completion for which the tools are being qualified.
Several variables play a significant role in the erosion potential of frac-pack slurry, such as particle density, concentration, roughness and sphericity, velocity, angle of impact, fluid viscosity, and the metallurgy of the erodible material. Changes in each of these variables can produce significant variance in the amount of erosion caused by a frac-pack treatment and in understanding the contribution of each of these variables. While impractical in a full-scale testing environment, these variables can be quantified using numerical methods and complimentary erosion prediction models.
Data sets from lab-scale and full-scale tests have been used to develop and refine erosion prediction models as they relate to conditions typical of frac-pack applications. Results will be presented showing how newly refined erosion modeling can aid in the development of tool designs and further refine the prediction of the erosiveness of frac-pack slurries for applications that deviate from full-scale erosion testing conditions.
Using Connection and Total Gases Quantitatively in the Assessment of Shale Pore Pressure
Authors: Alberty Mark , Fink Kristi 
Published: June 2014

Abstract
Connection and total gas measurements have been used qualitatively for decades in drilling oil and gas wells to identify over-balanced, under-balanced or near-under-balanced pressure conditions (mud hydrostatic relative to shale pore pressure). Results often conflicted with sand direct measured pore pressures and the pre-existing perceptions of shale pore pressure. We propose a technique that allows mud gases to be used in a quantitative manner, given that: (1) there is an increased understanding of the relationship between mud gases and shale pore pressure, (2) the development of the LWD based annular pressure measurement allows real-time monitoring of down hole hydrostatic pressures, and (3) differences between sand and shale pore pressure may exist as a result of the sand's structural position.
This paper presents time-based ECD behavior of block movement, flow rate, and total gas from Gulf of Mexico wells, and explains the relationship to shale pore pressure. These examples are quantitatively analyzed for shale pore pressure. The results are compared to direct formation pressure measurements within the sands.
Six principles guide pore pressure interpreters on the quantitative use of mud gases. The principles define the pore pressure values assignment to specific mud gas observations as a function of recorded annular mud pressure. The pore pressure estimates in shale can be used as calibration points for traditional shale pressure indicators such as resistivity, velocity or Dxc measurements.
The result of this integrated technique yields an improved characterization of shale and sand pore pressures and it can be used as input for well designs to increase reliability, safety and improve drilling efficiency.
High Pressure Multi-Stage Centrifugal Pump for 10,000 psi Frac Pump - HPHPS FRAC Pump
Authors: Pettigrew Dana , Lillies Allan , Limanowka Andy 
Published: June 2014

Abstract
Field use and test results of an HPHPS (High Pressure Horizontal Pumping System), and how it is integrated into a frac fleet of 20 PD (Positive Displacement) conventional frac pumpers to support fracs in the Horn River Basin.
This HPHPS was successfully tested on leases in the Horn River Basin of North Eastern British Columbia to pump Debolt source water (a saline, sour and gassy aquifer) during frac operations in 2010 and 2011. This provided an alternative solution to a $50mm+ water treatment plant for supplementing fresh water volumes used for frac operations.
Fresh water is being extensively used for fracturing operations to stimulate both oil & gas shale wells. Once used for this purpose, the water is either disposed of, or needs extensive treatment to recondition it for further fracture operations. Operators in the Horn River Basin have access to a non-potable aquifer that is available for both source water and disposal use, that is shallower than the shale gas wells requiring stimulation, but much deeper than the fresh water aquifers. Many tests were conducted by numerous operators on the Debolt aquifer to determine how this water source could be utilized to supplement fresh water requirements for fracture operations. Extensive aquifer testing revealed that this Debolt water remains stable if kept above the bubble point pressure, but existing PD frac pumps cannot pump this water at the high suction pressures required to keep the water stable. A high pressure multi stage centrifugal pump configured as an HPHPS for 500 psi suction and 10,000 psi discharge is capable of using raw Debolt water as a fracture fluid.
This paper will review how 3 HPHPS frac pumpers were integrated into a frac fleet of 20 PD frac pumps for evaluation of HPHPS pumping performance on a 10 well pad site during a 2013 frac campaign in the Horn River Basin. This multi-well pad site is scheduled for 252 fracs at 6.3 fracs per day.
The successful integration of HPHPS frac pumps into a standard PD frac fleet enables a Pressurized Frac On Demand (PFOD) system to be used. Untreated sour aquifer water can then be used to supplement fresh water in the large water demand requirement necessary to stimulate shale zones.
These concepts may be applicable in other shale exploitation areas to reduce the demands on the local fresh water resources in their areas too.