bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Concept of Wellbore Boundary Condition for Modeling Liquid Loading in Gas Wells
Authors: Limpasurat A. , Valko P. P. , Falcone G. 
Published: June 2014

Abstract
A new formulation of the wellbore boundary condition in multiphase reservoir simulation is suggested, allowing automatic determination of the direction of the flow at any time instant. It is particularly useful in coupled transient modeling of the liquid loading phenomenon in gas wells. The traditional Inflow Performance Relationship (IPR) uses a common well-block productivity index, but determines the inflow/outflow of the individual phases through a wellbore connection in an otherwise detached manner. The new approach takes into account that all phases should flow in the same direction and should have a common zero flow condition. The restriction leads to the definition of a new state variable: the multi-phase zero-flow pressure (MPZFP, P°). According to the new formulation, the flow direction at the connection is determined by the sign of the difference between this grid-block variable and the wellbore flowing pressure. Some advantages of the new formulation are: the flow is always co-current through a single connection (but multiple connections can lead to cross-flow); the meaning of well-block productivity index is preserved; the phase composition of the connection stream is determined by the upstream condition; when wellbore pressure is far from the MPZFP, the traditional (detached) IPRs are recovered; and - last but not least - previous numerical convergence problems are completely eliminated during coupled dynamic simulation of the wellbore/reservoir system in the presence of significant capillary pressure. Examples illustrate the application of the new wellbore boundary condition in coupled modeling of the complex phenomena under liquid loading conditions.
Fluid Profiling for Reservoir Evaluation - Two Norwegian Case Studies
Authors: Pfeiffer Thomas , Kretz Vincent , Øpsen Daniel , Achourov Vlad , Mullins Oliver C. 
Published: June 2014

Abstract
Today's climate of a general lack of resources and people, high prices and limited rig availability forces the oil industry to plan for efficient production and secondary recovery. This puts more weight on understanding reservoir architecture and fluid complexities, the main drivers of recovery. Improving confidence in reservoir architecture has taken center stage in risk management especially in high cost environments. Data availability to increase this confidence will always be limited by budget and/or operational constraints. This puts the strike on maximizing the value of acquired data and integrating all available data to help this cause.
Recent advances in sensor technology and petroleum science allows using downhole fluid analysis data to improve confidence in reservoir architecture. Mapping composition, gas oil ratio (GOR) and density across the field is common practice. These properties are based on the amount of solution gas in the liquid phase and their equilibrium distribution can be predicted by (typically) cubic equations of state (EOS). Evaluating the relative asphaltene distribution is based on different physics: the suspension of solids in the liquid phase. It is robustly assessed by the latest generation of downhole fluid analysis (DFA) tools and recent breakthroughs in science now also allow predicting equilibrium distributions by EOS. Consequently, two equations of state are used to analyze two separate fluid gradients, GOR and asphaltenes, yielding a robust method of reservoir evaluation. This new independent workflow is especially valuable when used in concert with PVT reports, well test data, static pressure gradients and other common techniques to assess reservoir architecture.
This paper presents two real-life case studies from the Norwegian continental shelf that use available DFA data to support the assumptions made from other data on reservoir architecture between wells. It shows the validity of the concept, but also highlights the limits and constraints of such a data set. These case studies lead the way to planning the data acquisition to include a more comprehensive DFA data set to address connectivity and other reservoir concerns.
A New Method for Modeling Multi-Phase Flowback of Multi-Fractured Horizontal Tight Oil Wells to Determine Hydraulic Fracture Properties
Authors: Clarkson C. R. , Williams-Kovacs J. D. 
Published: June 2014

Abstract
Unconventional light oil reservoirs are currently a primary focus of exploration and development activity in North America. Operators are seeking new methods to characterize hydraulic fractures generated during stimulation of multi-fractured horizontal wells completed in these reservoirs, particularly early in the well life. One such method is to quantitatively analyze flowback fluids immediately after fracturing operations. In previous studies it has been shown that flowback fluid rates and pressures can be modeled to obtain hydraulic fracture half-length and conductivity.
In this work, we develop an analytical procedure and methods for analyzing pre- and post-breakthrough of hydrocarbons during flowback of light tight oil wells. Flowback of multi-fractured horizontal wells, stimulated with water-based fluids in tight oil reservoirs, often consists of a short period of single-phase (water) flow followed by breakthrough of hydrocarbons, after which multi-phase flow (oil, water and gas) occurs. Our modeling approach therefore accounts for these multiple stages of flowback fluid production. The first flowback regime typically observed is fracture storage/depletion – this stage is analyzed by modeling single-phase depletion of the fracture pore volume from which a pre-hydrocarbon breakthrough estimate of fracture permeability and half-length is obtained. A stress-dependent permeability can be included to account for fracture closure and consequent conductivity loss during flowback. Fracture storage is followed by formation fluid breakthrough, which causes a deviation from the depletion signature. This stage is modeled by assuming transient linear flow of oil and formation water to the fracture, and accounting for consequent multi-phase flow in the fracture. The primary properties adjusted to match pre- and post-hydrocarbon breakthrough fluid production include fracture half-length and permeability, fracture relative permeability, breakthrough pressure and reservoir permeability. We have observed, as have others, that effective fracture half-length may be significantly reduced following hydrocarbon breakthrough.
Our new method for tight oil reservoir flowback analysis is tested against a field example. As with previous studies associated with shale gas, significant uncertainty in fracture property estimation results from the analysis, which we will address in future work.
A New Standardized Laboratory Protocol to Study the Interaction of Organic-Rich Shales with Drilling and Fracturing Fluids
Authors: Zhou Junhao , Jung Chang Min , Pedlow John W. , Chenevert Martin E. , Sharma Mukul M. 
Published: June 2014

Abstract
The two major concerns during drilling and completion of wellbores in unconventional reservoirs are: wellbore instability and proppant embedment. Both of these issues are controlled by the interaction of water-based fluids with the organic-rich shale. Understanding the interaction of water-based fluids with organic-rich shales is the first step towards developing screening tests for their compatibility with the shale. In this paper, we present a systematic approach to investigate the interaction of water-based drilling and fracturing fluids with organic-rich shales.
We performed a series of measurements to determine shale mineralogy, native water activity, swelling parallel and perpendicular to bedding planes, Brinell hardness, P-wave and S-wave velocities and compressive strength. Changes in hardness and acoustic wave velocities were measured before and after shale samples came into contact with water-based fluids. Shale swelling was determined in two directions simultaneously with our unique 2-D strain indicators. The dynamic Young's modulus and Poisson's ratio were calculated based on the wave velocities. It is shown that these measurements can be used to screen drilling and completion fluids that may interact unfavorably with the shale.
The shale mineralogy was obtained using XRD. The shale native water activity was determined with controlled humidity environments. Multi-scale durometers were used to measure the shale hardness. Anisotropic swelling was observed for all shale samples characterized. The results showed a good correlation with the mineralogy, hardness and wave velocities of the shale. In general, the water adsorption was greater with fresh water than with 4% NaCl and 2% KCl. Changes in hardness, P-wave and S-wave velocities, dynamic Young's modulus and Poisson's ratio after shale's contact with water-based fluids can be used as indicators for wellbore stability and fracture conductivity impairment in these shales.
The measurement techniques and procedures presented in this paper can be used as standard screening tests to evaluate the interaction between organic-rich shales and water-based drilling and fracturing fluids. If this testing protocol shows incompatibility of the fluids with the shale, additional fracture conductivity tests should be conducted. The screening protocol presented here minimizes the number of fracture conductivity measurements (that are hard to perform) that need to be conducted to check for shale-fluid compatibility.
A North American Review of Commercial Shale Plays; Have We Learned Anything Besides Serendipity?
Authors: Shelley R. F. , Mullen M. J. , Minner W. A. 
Published: June 2014

Abstract
When evaluating mud rock completions one is quickly struck with the complexity of the task. Mud rock "shales" by their very nature can be problematic to evaluate given the wide variation in geology, rock properties, and reservoir characteristics, not to mention the effect of multi-fractured horizontal well completions. Quite often, the reservoir characteristics between an economic well and an uneconomic well are very similar, further compounding the problem. So, what can we learn by taking another look at North American shale plays to help identify the more productive shales, improve economics and reduce the cycle time bringing this resource to market globally? Sometimes, the simple measurements we make at the wellsite can be very indicative of the things we don't measure very well, like the degree of natural fracturing and the interconnectedness of porosity. The subject material and the information discussed in this review was derived from the study of the characteristics and data from hundreds of completions with production results for shale wells in North America.
The findings presented show the results of formation evaluation and analytical evaluation which have proven to be good indicators of well productivity and hydrocarbon recovery. Many of these methods have been underutalized by the industry for shale evaluation and completion optimization.
Past successes in unconventional resource arenas are sometimes viewed as the result of seredipity. However, that has not been the case – past successes have evolved, in some cases over periods of years. A comparison of learnings from the Bakken and Eagle Ford show some interesting commonalities that help identify economic wells from subeconomic wells, as well as the most productive completion intervals in lateral wellbores. These findings and evaluation methodologies can readily contribute to the global hunt for unconventional reservoirs, and evaluation / optimization of their development strategy..
Design Verification, Optimization and Validation of Ultra-HPHT Completion and Production Tools
Authors: Deng Guijun , Doane James , Ruffo Antonio , Shyu Goang-Ding , Collins Scott 
Published: June 2014

Abstract
The growing global demand for hydrocarbons is challenging the oil and gas industry to explore and develop deeper and hotter reservoirs, pushing the boundaries of equipment capability beyond traditional High Pressure High Temperature (HPHT) limits into the Ultra-HPHT region. Ultra-HP/HT wells are currently being drilled in the Gulf of Mexico, on the shelf and in deep water. Many of these wells have a total depth of in excess of 30,000 ft, where reservoir pressures and temperatures approach 30,000 psi and 500°F. There are many technological challenges that must be overcome for downhole service and completion tools to operate successfully in the Ultra-HPHT environment. As a result, there are currently few packer-type devices that are considered fit-for-service in these applications.
This paper gives an overview of the latest developments in how advanced finite-element analysis tools are used to develop Ultra-HPHT completion and production tools. These advanced analysis tools enable the designs to be verified before prototype and production to determine if they are functional under complex scenarios that sometimes were impossible to validate by testing. A design process that integrates analysis with design and testing for concept verification, design optimization, and test correlation is discussed in detail.
The technical challenges of multi-physics simulation like thermal-mechanical coupling, buckling, and 3-D multi-body contact with metallic and hyper-elastic material, are also addressed in this paper through a few Ultra-HPHT completion and production tool design examples.
The design process which will be described integrates design verification, design optimization using advanced finite-element analysis techniques, and design validation. It has proven to be a very valuable process in developing state-of-the-art Ultra-HPHT completion packers and bridge plugs for operating conditions as challenging as 500°F and 25,000 psi. Two validation tests were conducted on each of these tools. First, they were tested in accordance to ISO 14310 Grade V0. Then they were tested to a modified grade V3 procedure in as-rolled ID casing, and both passed the tests successfully. A summary of the process and the relevance of each step will be presented, along with conclusions regarding how the process leads to improvements in design and reliability.
Numerical Challenges in Foam Simulation: A Review
Authors: Rossen W. R. 
Published: June 2014

Abstract
We review challenges to accurate simulation of foam enhanced oil recovery, with a focus on numerical issues. Foam responds in an abrupt, nonlinear way to changes in water saturation, surfactant concentration, and oil saturation, in ways that cause fluxes to fluctuate in time and space. As the grid is refined these effects have smaller impact on the overall process but execution of the simulation slows. In addition, in simulations of foam with oil, consecutive grid blocks can lie on opposite sides of a strong foam/weak foam boundary on the composition diagram. Because by definition foam is an interaction between gas and water, the naming of phases (gas or oil) in a compositional simulation of a miscible EOR process can have significant effect on the simulation of a foam flood. Numerical dispersion of surfactant concentration is a problem, but attempts to minimize its effect can lead to other numerical artifacts. Because foam is so sensitive to water saturation and capillary pressure, capillary effects are important, especially in finely laminated formations. "Population-balance" foam simulators, which represent the complex dynamics of bubble creation and destruction along with the effect of foam on gas mobility, face additional challenges with instability and slow run times, especially for models that represent the multiple steady states seen in the laboratory.
We collect and review the various numerical challenges to foam simulation. Some of these problems are largely cosmetic, giving for instance fluctuating fluxes and pressure gradient but no significant effect on final recovery. Others do severely influence the whole progress of the flood. We discuss the origin of the challenges, how to recognize them, how they can be mitigated, and whether they arise from a correct representation of foam physics or the unintended result of attempts to solve other numerical problems.
Flow Assurance Solutions to Mitigate Naphthenates Problems in Crude Oil Production
Authors: Oliveira M. C. , Rosário F. F. , Bertelli J. N. , Pereira R. C. , Albuquerque F. C. , Marques L. C. 
Published: June 2014

Abstract
Recent years have seen a wide-world increase in the production of acidic crudes rich in naphtenic acids (NAs). The presence of these compounds in crude may lead to two different problems: i)- the so-called naphthenic acid corrosion (NAC), and: ii)- formation of naphthenates (naphthenic acid salts) which can either precipitate or form interfacial active salts (soaps) that are prone to stabilize emulsions. The formation of naphthenates (NAPHs) during the W/O separation process is promoted by the pH increase of the produced water phase brought about by CO2 degassing.
NAC problems are well-understood and advantages in technologies to mitigate them are abundant. In contrast to this, NAPHs problems which are germane to the topside O/W separation settings are themselves a dimly understood problem. However, the combination of tailored chemicals and changes in the processing parameters is the best solution to keep NAPHs problems at bay.
Taking these points as the main rationale this paper presents:- a description of NAPHs problems in the upstream crude oil sector; - a comprehensive description of the NAPHs problems Petrobras has been facing; - the analytical tools suitable to characterize and quantify the presence of NAPHs in the produced fluids; the suite of lab tests to screen chemical additives for field application; the difficulties in sparking actions to modify oil-processing parameters and to injecting chemical on an outsourced FPSO top-side facilities, and; the concert of solutions that have provided the best field results.
This paper concludes with a suggestion that a comprehensive water and crude oil characterization program (including geochemistry studies) is totally necessary to cope with the macroscopic behavior of NAs in actual field conditions.
Frac-Perforating Charge Maintains Treating Pressure while Increasing Pumping Rate: A Case Study in South Texas
Authors: Brady Thomas , Grace Timothy 
Published: June 2014

Abstract
The amount of horizontal, multistage completions performed globally is rapidly increasing. Unconventional shale gas plays are proving to be both productive and economical when a plug-and-perforate method is used as a gateway for hydraulic fracturing. Historically, deep-penetrating charges were used to perforate multiple clusters with varying shot density. Results, however, did not always correlate with the designed frac job. The limited-entry frac design used was based on published average entry-hole size and shot density, which created a backpressure or choke effect. The choke effect helped increase the chances of all of the perforations breaking down and being stimulated. However, because entry-hole sizes vary in diameter, the effective perforations were not always consistent with the treatment design. Screenouts and high treating pressures were often an unexpected result. These instances became accepted as the norm, often prompting the operator to abandon the stage and possibly move on, consequently resulting in loss of production from that stage.
Obviously, there was a need to minimize the perforation coefficient and deliver a consistent hole size, despite the distance of the standoff. The perforation coefficient needed to be minimal to plan and execute the desired stimulation. Instead of using deep-penetrating charges that were designed for completions requiring no stimulation, a frac-perforating charge was incorporated into the gun system. The frac charge offers reduced a variance of entry-hole size, regardless of the standoff.
This paper demonstrates how less variance with respect to entry-hole size enabled an operator to effectively reach the designed pump rate while maintaining the same treating pressure. Additionally, the results of alternating stages between conventional deep-penetrating charges and a new frac-perforating charge are presented.
Real World Solutions, Effective Fracture Treatment Design in Horizontal Wells
Authors: Sturms Jason M. , Smith Charles H. , Ziane Lynda 
Published: June 2014

Abstract
Horizontal wells have altered the ability to deliver production from marginal reservoirs. Although reservoirs with permeability values in the 0.1 to 0.01 millidarcy range had been identified in many producing basins, these reservoirs could not be exploited until horizontal drilling became a commercial reality. Drilling these reservoirs became an engineering process that could be applied with great success in many different basins and rock types.
The completion of these resources proved to be a different matter, however. Wells that were drilled with excellent vertical control within the reservoir did not exhibit a consistent response to stimulation treatment along the entire traverse of the horizontal sections. Although reservoirs that are considerably different lithologically were always expected to provide a diversity of completion challenges. More troubling, however, are the reservoirs that appear to be homogeneous that do not respond well to similar treatment designs along the length of the horizontal section. Pump-in tests were used in an attempt to understand this lack of consistency. In some cases, pump-in tests followed by treatment designed from that data failed to yield the expected production results. Sometimes, breakdown could not be achieved in the reservoir.
This paper describes how to apply data derived from dipole sonic logs in horizontal sections of a well to establish the anisotropy along the length of the horizontal section. This information is then used to define the brittleness properties of each section of the wellbore. Perforations are selected to take advantage of this brittleness, and effective fracture treatments are designed and pumped.
These case studies are examples of this application in difficult and troubling reservoirs. In each well, the fracture treatment success increased as much as 100% and had reduced breakdown pressures. Production rates were also increased by 20% when compared to production from the nearest offset wells in the same reservoir and of similar horizontal length.