bluuebunny/crossref_metadata_2025_split huggingface dataset:
Long-Term Economic Viability of Production From Unconventional Liquids-Rich Reservoirs: The Case of Bakken Field
Authors: Ozkan Sarp , Kurtoglu Basak , Ozkan Erdal 
Published: June 2014

Summary
Long-term economic viability of unconventional reservoirs is evaluated from the profit-maximizing perspective of a producing company. The case of the liquids-rich production from the Bakken field is considered as a representative of unconventional resources. A profit-margin optimization model is constructed for a company to meet the demand it faces from a stock of conventional and unconventional resources given different sets of exogenously determined prices. The model is parameterized using the different production-decline rates of the two sources, physical and economic exhaustibility of the resources, and the ever-increasing marginal cost of adding conventional resources into the company portfolio. The optimal extraction path of oil from the conventional and unconventional reservoirs is assessed, and the long-term economic consequence of keeping the unconventional resource in the ground for different oil-price scenarios is predicted. The model reveals the appropriate composition of a portfolio of conventional and unconventional resources. In the case of a high-price scenario, the optimal efficient extraction path is the pursuit of additional conventional resources before using unconventionals to meet the demand. For the reference-price scenario, the decline of the conventional reserves should be substituted with unconventionals from the beginning. The profitability of the enhanced oil recovery (EOR) applications in unconventional reservoirs and when they should be implemented are also determined. Contrary to common expectation, it is shown that the EOR technology is more justifiable in the case of a lower price forecast.
Effects of Gravity, Foaminess, and Pressure Drawdown on Primary-Depletion Recovery Factor in Heavy-Oil Systems
Authors: Alshmakhy Ahmed , Maini Brij B. 
Published: June 2014

Summary
The unusually high primary recovery factors (RFs) observed in numerous heavy-oil reservoirs are often attributed to foamy oil flow (i.e., the non-Darcy flow involving formation and flow of gas-in-oil dispersion). It occurs when the wells are produced aggressively at high drawdown pressures that led to conditions in which the viscous forces become sufficiently strong to overcome the capillary forces in pushing dispersed bubbles through pore throats. The role of gravitational forces in generating such dispersed flow has not been studied adequately. This work was intended to evaluate the contribution of gravitational forces in primary depletion of heavy-oil formations under foamy flow conditions.
Primary-depletion tests were conducted in a 200-cm-long sandpack that was held in either horizontal or vertical orientation. The results of horizontal depletion tests were compared with the depletion tests conducted with the sandpack in the vertical direction. Vertical depletions showed better recoveries at slower depletion rates compared with horizontal depletions.
The RFs of both horizontal and vertical depletions were correlated against the average drawdown pressure available to move the oil. It was found that the RF shows a strong dependence on the average drawdown pressure. It was also found that the curve of RF vs. average drawdown pressure moves slightly toward higher recoveries in the presence of an added foaming agent (i.e., with increased oil foaminess).
Method for Consistent Valuation of Assets With Multiple Sources of Uncertainty
Authors: Wilkinson David , Bailey William J. , Cou?t Benoît 
Published: June 2014

SummaryA simplified version of the Smith and Nau (1995) integrated solution scheme is applied to the valuation of an oilfield project possessing salvage options and both private and public uncertainties. It is shown that the computed valuation is consistent with the definition of the real option price as the maximum value that could be obtained, without market risk, from an ensemble of projects that sample the private uncertainty. The attainment of this value requires an optimal decision strategy and a hedging strategy, both of which are obtained as a byproduct of the valuation. The interpretation of the obtained value is validated by forward simulation over an ensemble of projects, by use of a fully reproducible worked example.
Industry Analogies for Successful Implementation of Drilling-Systems Automation and Real-Time Operating Centers
Authors: de Wardt John P. 
Published: June 2014

Summary
Industry analogies provide excellent insight to finding the optimal balance among manual, automatic, and remote operations. They also can provide excellent insight into data displays and decision making.
It is very important to define the current state and the future desired state for data acquisition, processing, decision making, and workflow in high-performance drilling operations. Understanding the difference between these two states provides the opportunity to guide the successful implementation of drilling-systems automation (DSA) and real-time operations centers (RTOCs). Aviation and space flight have been offered as appropriate analogies for the future application of drilling-systems automation. Formula 1® motor racing offers a highly competitive analogy for managing data flows combined with control systems.
Various industry analogies are reviewed for their applicability to DSA and RTOCs. The benefits and drawbacks of each are highlighted. An assessment uses insights from other analogous industries to provide the opportunity to define best practices and relevant application for various well types from these analogies.
An advanced application of DSA and RTOCs will change the role of the driller as well as the competency makeup and location of the drilling team. Maximal benefit from DSA and RTOCs can be achieved through carefully planned implementation on the basis of relevant learning from other industries.
Zonal Isolation through Gas Hydrates Offshore Tanzania
Authors: Vølstad J. , Tveit T. , Aguilar P. , Hurtado N. , Bogaerts M. 
Published: June 2014

Abstract
Deepwater cementing becomes increasingly challenging as drilling operations move to greater water depths and to more remote locations. Understanding these challenges and mitigating the associated risks in time has become very important tasks. Before the first exploration well for an operator offshore Tanzania was spudded in a water depth of 2580 m, an extensive analysis was performed to determine all the risks associated with cementing operations, especially in the increasingly challenging and critical surface casing section.
The risks determined were low temperatures at seabed, unconsolidated formations close to seabed, potential shallow gas, and likely presence of hydrates. Because of the remoteness and limited oilfield infrastructure, logistics were also determined to be demanding. To successfully continue to drill further sections, the job objectives were zonal isolation across the shallow flow and hydrate zones, cementing back to seabed to provide a stable wellhead, and good cement around the casing shoe providing isolation for deeper formations.
The cement job was designed to meet these challenges and objectives. Optimized particle-size distribution (PSD) cement slurry with low density was designed to avoid losses and still develop high compressive strength quickly at low temperatures. Low-temperature gas-migration additive and cement set enhancer were included to provide a short transition time preventing gas migration to seabed. Because of the lower cement ratio in the optimized PSD-blend, the slurry did not destabilize the hydrates during the setting process. The cement placement was simulated to confirm the job design would meet its objectives.
Careful preparation and the optimized PSD-sluny system allowed executing the job meeting all objectives. Good zonal isolation and a successful leak off test were achieved, eliminating the contingency liner.
Real-Time Evaluation of Hole-Cleaning Conditions With a Transient Cuttings-Transport Model
Authors: Cayeux E.. , Mesagan T.. , Tanripada S.. , Zidan M.. , Fjelde K.K.. K. 
Published: June 2014

Summary
During a drilling operation, a real-time analysis of surface and downhole measurements can give indications of poor hole cleaning. However, it is not always intuitive to understand how and where the cuttings are settling in the borehole because the transportation of cuttings and the formation of cuttings beds are largely influenced by the series of actions performed during the operation. With a transient cuttings-transport model, it is possible to get a continuously updated prognosis of the distribution of cuttings in suspension and in beds along the annulus. This information can be of prime importance for making decisions to deal with and prevent poor hole-cleaning conditions.
A transient cuttings-transport model has been obtained by integrating closure laws for cuttings transport into a transient drilling model that accounts for both fluid transport and drillstring mechanics.
This paper presents how this model was used to monitor two different drilling operations in the North Sea: one using conventional drilling and one using managed-pressure drilling (MPD). Some unknown parameters within the model (e.g., the size of the cuttings particles) were calibrated to obtain a better match with the top-side measurements (cuttings-flow rate, active pit reduction as a result of cuttings removal). With the calibrated model, the prediction of cuttings-bed locations was confirmed by actual drilling incidents such as packoffs and overpulls while tripping out of hole.
On the basis of the calibrated transient cuttings-transport model, it is thereby possible to evaluate the adjustments of the drilling parameters that are necessary to stop and possibly remove the cuttings beds, thus giving the drilling team the opportunity to take remedial and preventive actions on the basis of quantitative evaluations, rather than solely on the intuition and experience of the decision makers.
Simulation of Single Cutter Experiments in Evaporites through Finite Element Method
Authors: Martinez Ingrid Reyes , Fontoura Sergio , Inoue Nelson , Carrapatoso Carla , Lourengo Affonso , Curry David 
Published: June 2014

Abstract
Single cutter laboratory experiments are used for evaluating the drill bit - rock interaction mechanisms. These experiments can be simulated through numerical methods in order to analyze particular conditions of each borehole drilling operation. This paper describes the use of Finite Element Method for modeling single cutter experiments in evaporites. The constitutive model of Drucker-Prager, calibrated using results of triaxial compression tests carried out in evaporites, was used to model the rock behaviour. Also, an isotropic damage model was employed for modeling the erosion mechanism that represents the rock-cutter interaction. The model demonstrated good agreement with experimental results.
A series of numerical experiments were carried out in order to observe the cutting process under different geometrical conditions. Two-dimensional and three-dimensional simulations were performed to analyze the variation of Mechanical Specific Energy (MSE) required to cut rock by varying three parameters: Depth of Cut (DOC), cutter geometry, particularly the back rake and side rake angles, and confining pressure. It is predicted that MSE decreases when increasing the depth of cut until stabilizing at a certain limit after which it remains substantially constant With regards to the cutter geometry, the results showed that high back rake and side rake angles produce elevated MSE making the process less efficient. The confining pressure analysis showed similar results to the experimental observations found in literature and those performed at our laboratories. The cutting process showed a considerable increase in MSE with the increase of confining pressure.
Advanced Dynamic Training Simulator for Drilling As Well As Related Experience from Training of Drilling Teams with Focus on Realistic Downhole Feedback
Authors: Ødegård Sven Inge , Risvik Bjørn T. , Bjørkevoll Knut S. , Mehus Øystein , Rommetveit Rolv , Svendsen Morten 
Published: June 2014

Abstract
The paper presents a highly advanced training simulator that combines an advanced top-side simulator with a dynamic downhole simulator with an advanced transient integrated hydraulics and thermal wellbore model and a dynamic torque and drag model. The simulator is aimed at drilling and well operations, and is able to handle most of the normal operations, including high pressure high temperature (HPHT) wells, through-tubing rotary drilling (TTRD), extended reach drilling (ERD) and managed pressure drilling (MPD).
The underlying simulator technology is modular, allowing for new modules to be added at a later stage. For instance, MPD control systems can easily be added to the simulator, allowing for training on an MPD operation with both the drilling crew and the MPD supplier. The simulator is able to use pre-programmed scenarios, replay, fast forward and rewind to facilitate efficient training and review sessions
Moreover, the simulator is designed to provide realistic personnel training on emergency procedures and operations such as well control in a safe environment, thereby limiting the human factor in critical operations as well as possibly improving the procedures by frequent use and revision. Also, the simulator allows for integration of HSE in early well planning through simulator training on the actual well to be drilled.
The main innovation is to use dynamic models verified in real-time operations together with an advanced top-side drilling equipment simulator for training on well specific scenarios.
The value added for the industry is to give the drilling and/or engineering teams a possibility to verify and train on identified risk elements prior to drilling a well, as well as retrain during the operation on a "true" virtual copy of the well.
So far more than 60 drilling teams have experience from training, and the feedback has been very positive.
The paper will present the simulator as well as experiences from typical training cases on challenging wells.
Thermal Reactivation of Microfractures and Its Potential Impact on Hydraulic-Fracture Efficiency
Authors: Dahi Taleghani A. , Ahmadi M. , Wang W. , Olson J. E. 
Published: June 2014

Summary
Core studies have revealed the presence of abundant cemented microfractures in many tight formations. Further independent studies have revealed the opening of some of these microfractures on the wall surface of main hydraulic fractures. In addition, early-production well-testing analysis in some of these cases provides estimates for the hydraulically-induced-fracture surface area, which is much larger than fracture dimensions estimated in fracturing design or provided by the location of microseismic events. Opening of small-sized fractures could be a possible reason for this discrepancy. In this paper, we show to what extent thermal stresses induced by temperature difference between fracturing fluid and formation fluid could provide the driving force to open a portion of these small, cemented natural fractures lying on the surface of hydraulic fractures. Moreover, through combination of stress analysis and empirical fracture-distribution models obtained from outcrops, we calculate the increase of total reservoir/fracture contact surface under the condition of microfracture activation. Our thermoelasticity analysis reveals the effect of the pump rate and temperature of the fracturing fluid on the number of activated microfractures. The results show that the volume of the microfractures varies depending on the length of the microfracture, rock properties, and time. At the end of the paper, through an example, we show that activation of only a small portion of these microfractures can increase the total fracture/formation contact area considerably and, consequently, increase initial production. Reservoir-pressure changes caused by production might partially close or reopen these microcracks during production; hence, the effectiveness of these microfractures could be mainly restricted to the early life of the reservoirs.
Planning the Formation Evaluation Program for Development Financing
Authors: Vance Harold 
Published: June 2014

Introduction
During the drilling of a well, certain data must be obtained and interpreted to permit the operator to decide whether or not it will pay him to set pipe in this new well. The money already has been spent to make the hole; if the operator can recover enough production to more than pay completion costs, he probably will set pipe and complete the well.
The purpose of this paper is to show how this same information obtained during drilling can be and is being used to help determine the amount of money a bank will lend the operator, depending upon the income from future production to pay off the loan.

The Banker's Viewpoint
A bank makes most of its money by charging interest on the money it lends. The bank cannot recoup many losses on a 5 to 6 per cent return on the money; therefore, a bank cannot afford to take risks. It should not be expected to take the risks of business because it receives none of the business profits. Some lending agencies do lend money for interest plus an interest in the business after the loan is paid out.
The term "oil and gas loan," as generally used, means a loan secured by a mortgage on a producing property capable of producing future net income from the production of oil and/or gas, with this income being used in whole or in part to payoff the loan while leaving a residue to the borrower. Thus, the primary security is the expected income from the properties; the secondary security is the net worth of the borrower who signed the note.
Thermodynamic Model Improvements for Common Minerals at High Temperature, High Pressure and High TDS with Mixed Salts
Authors: Dai Zhaoyi , Shi Wei , Kan Amy T. , Zhang Nan , Tomson Mason B. 
Published: June 2014

Abstract
Deep water oil and gas production has been challenged due to limited knowledge of thermodynamic properties of minerals under high temperature (150 to 200°C), high pressure (1000 to 1500 bar), and high total dissolved solids (more than 300,000 mg/L). Scale prediction models are limited by lack of experimental data and inadequate understanding of modeling parameters. With a new apparatus, solubilities of barite and calcite were measured at temperatures up to 250°C, pressures up to 22000 psi, and ionic strength up to 6 m NaCl and in the presence of elevated concentrations of mixed electrolytes representing the nealy maximum range of interferences expected in brine. Preliminary measurement of gypsum solubility under high pressures were also conducted. Based on solubility measurements, the temperature and pressure dependence of stability constants and Pitzer coefficients were validated and adjusted. In addition, specific ion interactions are validated and constructed through solubility measurement in synthetic brine with mixed electrolytes. On these bases, our thermodynamic model was improved and can be applied to scale prediction for barite and calcite under extreme conditions usually encountered in the oil field.
Structure, Stoichiometry, and Modelling of Calcium Phosphonate Scale Inhibitor Complexes for Application in Precipitation Squeeze Processes
Authors: Shaw S. S. , Sorbie K. S. 
Published: June 2014

Abstract
Phosphonate scale inhibitors (SIs) applied in downhole squeeze applications may be retained in the near-well formation through adsorption and/or precipitation mechanisms. In this paper, we focus on the properties of precipitated calcium phosphonate complexes formed by 9 common phosphonate species. The stoichiometry (Ca/P ratios) in various precipitates is established experimentally and the effect of solution pH on the molar ratio of Ca/P in the precipitate is investigated. All static precipitation tests were carried out in distilled water, with only Ca2+ (as CaCl2) and SI present in the system at test temperatures from 20°C to 95°C. The molar ratio of Ca/P in the solid precipitate was determined by assaying for Ca2+ and P in the supernatant liquid under each test condition by ICP spectroscopy (Cao and Po are known, but are also measured experimentally). We show experimentally that the molar ratio of precipitated Ca2+/P (or Ca2+/SI; or n in the SI_Can complex) depends on the SI itself and is a function of pH, for all phosphonates tested. It is found that, as pH increases, the molar ratio of Ca2+/P (n in the SI_Can) in the precipitate increases up to a theoretical maximum, depending on the chemical structure of the phosphonate. Our findings corroborate proposed SI-metal-complex ion structures which were presented previously (Shaw et al., 2012c), as discussed in detail in the paper. In addition, the precipitation behaviour of the various compounds is modelled theoretically by developing and solving a set of simplified equilibrium equations. We find that the precipitation behaviour can be modelled, but only if a fraction, β, of "non-SI" of the initial phosphonate SI is taken into account. The quantity β can be as high as 0.2 (i.e. ~20% non-SI), although there is a degree of variability in this factor from product to product. However, good quantitative agreement is shown comparing the predictions of the equilibrium solubility model with experiment. Such models can be used directly in the modelling of field phosphonate precipitation squeeze treatments.
Experimental Study of Friction Reducer Flows in Microfracture During Slickwater Fracturing
Authors: Sun Yongpeng , Zhang Hao , Wu Qihua , Wei Mingzhen , Bai Baojun , Ma Yinfa 
Published: June 2014

Abstract
Tight formations with extremely low matrix permeabilities, such as gas shale, can produce at economical rates is due to inborn fissures and fractures introduced during hydraulic stimulation. Hydraulic fracturing in gas shale can connect/generate these microfractures, causing them to become much more complex fracture networks. These microfractures have much more contact area with the matrix and therefore hold the majority of the productivity potential of gas shale.
Slickwater fracturing has been proved to be an effective method by which to increase the recovery of shale gas reservoirs. Friction reducer is the primary component of this fluid. It can decrease the flowing friction in macro tubing. Lab tests and field applications have addressed this issue thoroughly. However, the flow characteristics of this solution in microfractures are not clear.
The present study will show how this solution flows in microfractures by employing micro-sized fracture model. FR solution is a shear thinning fluid. Rather than reducing flow friction, with the FR fluid in a 1000 μm height, 50 width μm and 4.14 cm length microfracture, the injection pressure did not decrease but rather increased 36%. The impact of FR solution concentration was found to be more obvious at low velocities. At the same shear rate, the apparent viscosity is higher in large microfractures. At the same velocity, large microfractures have higher residual resistance factors. Through the analysis of fluid emulsion particle size and shale matrix pore size, this FR solution will not go into the matrix pores easily, but can block the pore entrance to prevent the fluid from leak off and to protect the formation from contamination during slickwater fracturing.