bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimized Fracture Stage and Perforation Placement in Horizontal Wells using a New Calibrated Pulsed-Neutron Log Workflow
Authors: Dahl Jeff , Samaripa James , Spaid John , Hutto Erek , Buller Dan , Johnson Bill , Mcilroy Chris 
Published: September 2015

Abstract
Evidence continues to mount to indicate that the geometric placement of fracture stages and perforation clusters in horizontal wells results in variable well production, with many clusters contributing little or no production. Any engineered completion design should require stages to be segregated by similar petrophysical and mechanical properties. The authors propose to reduce the cost per barrel of oil equivalent (BOE) and to improve estimated ultimate recovery (EUR) by using a novel log-derived completion method to better select perforation clusters and stage location to provide better fracture placement.
A low-risk, pumped down, cased-hole pulsed-neutron log (PNL) is used after the well is cemented before completion. Using readily available geosteering software, the geologic projection of vertical well log measurements and the interpreted formation properties along the horizontal well enable a rigorous calibration method for PNL interpretation. Inelastic pseudodensity, neutron porosity, and resistivity-sigma calibrations can then generate a cased-hole triple combo. Elemental yields for silica, calcite, and potassium are used with additional clay inputs for a basic mineralogy interpretation. These inputs, within a specialized workflow, calculate a “production index” and “frac index” used to generate custom staging designs.
Experience in a major unconventional play has shown a dramatic reduction in the number of stages and the completion cost per well. In addition, data from producing wells, using a software-derived stimulation design, has been matched to geometrically staged wells in the area. The addition of PNL data to interpret the position of the lateral well has been observed to reduce uncertainty when compared to the logging while drilling (LWD) gamma ray (GR) alone. The completion results for stages also provide good evidence that the overall efficacy of the stimulation treatment was increased by the perforation placement. The conclusions from this work show substantial completions cost savings per well while maintaining overall EUR in a difficult unconventional shale play. Based on pressure observations during stimulation, it is believed that stimulation efficiency has been increased. Using fewer stages to target the more productive rock and perforation clusters to target the sweet spots for stimulation has provided a substantial cost/BOE reduction.
Although the technology for using a PNL log in the horizontal well has been attempted previously, there was not the benefit of a rigorous calibration method. The geologic projection of vertical wells is a novel approach to calibrate thousands of feet of logged PNL data. In addition, the custom staging design uses a novel, unbiased approach to select the optimum stage and perforation placement to minimize completions cost while maximizing productivity.
Novel use of Electro Coalescence to Enhance, Optimize and Debottleneck Oil Separation Trains
Authors: Amarzguioui Morad , Jacobsen Per Christian 
Published: September 2015

Abstract
Many challenges are encountered when separating oil and water in onshore and offshore production trains. The challenges include presence of stable emulsions, increased water cuts, small water droplets due to high shear or pressure drops, and/or high crude viscosities. These issues can have a significant negative impact on the separation efficiency if not addressed properly. The conventional way of addressing these issues usually involves a combination of high process temperatures, high chemical dosages, large vessels and/or increased number of separation stages. Conventional solutions often demand increased energy consumption, higher material costs, larger operating costs, more weight and/or larger space requirement for the production facility. Furthermore, conventional solutions are not always practically feasible, due to restricted energy availability or space restrictions.
Early stage implementation of electrocoalescence through VIEC (Vessel Internal Electrostatic Coalescer) technology allows for a much more efficient and cost effective means of resolving the challenges in the separation train. The VIEC technology was the OTC “Spotlight on new Technology” award winner in 2004 and has since then been implemented in several major projects.
The VIEC technology applies high voltage electrical fields to promote droplet-droplet coalesce, thus greatly speeding up and enhancing separation efficiency. VIEC technology combines fully insulated electrodes with a low voltage feed and distribution inside the separator shell. Due to these characteristic features, the VIEC technology can tolerate any water cut and presence of gas, as opposed to conventional electrocoalescers. Consequently, the technology enables use of the powerful mechanism of electrocoalescence in any three-phase separator to speed up separation efficiency and resolve emulsion problems.
VIEC Technology will reduce the BS&W out of a given separator, increase capacity of an existing separator or enable a more compact separation solution for a given throughput of crude. Additional benefits include production at higher viscosities and at lower temperatures and improved level control due to reduced emulsions layers. Furthermore, consumption of demulsifier is often seen to be reduce significantly, when electrocoalescence is applied compared to conventional separation.
The paper will give a detailed presentation of the mechanism of electrocoalescence and how it is implemented in the VIEC technology. The paper will focus on how to predict electrostatically enhanced separation performance by combining laboratory testing with separation modelling, to give representative predictions of separation benefits and allow for designing solutions custom-fitted to specific separation challenges. A specific case from the Gulf of Mexico will be presented, where an existing TLP was retrofitted with VIEC technology to increase its capacity and enable a tie back from a nearby reservoir.
Modelling with Multidimensional Matrices for Project Economics, Portfolio and Business Plan Generation and Analysis
Authors: Tahirov Tahir 
Published: September 2015

Abstract
The live example of modelling and application of interrelated, multidimensional, expandable matrices in E&P (Exploration & Production) business is presented. Efficiency achieved in terms of using multidimensional, linked structure, formulas shared across dimensions is demonstrated. Overall process of easy model construction and modification which saves time and provides opportunity for insightful, value-added analysis for petroleum investment decision-making is explained.
The new approach realised by using matrices based software solution. Dimensions of E&P projects - price scenario, participation, time, etc. shared across matrices of cash flow, profit and loss, work program, economics. Possibility of adding new project (or its version) as a new dimension is realised. In the Project economics module assumption and calculation matrices are separated, hierarchy of assumptions – global (centrally controlled via database link) – country - project is established. Formulas with meaningful mnemonics are placed outside of cells. One easily examined formula shared across dimensions which allows significant reduction of size and enhances transparency of models. Project data flows to database using JDBC (Java database connectivity) and this database used to generate the E&P portfolio module for project selection, ranking, impact analysis and visualisation. For the selected portfolio of projects (country, region, global) in the Business plan module capital investments, cash flow, P&L as well as work program and production reports are generated.
Working economics-portfolio-business plan system serves to address the modern E&P company challenges such as project valuation, risks associated with project (volume, delays, cost increase, etc.), optimal acquisition or divestiture terms, as well as portfolio analysis, resource constrains, project prioritization. The system enables to quickly conduct what-if analysis testing various contractual terms, price scenarios, investment size and schedules, production profiles. Fully customizable and flexible matrix system allows modelling non-standard projects with production sharing agreements, complex acquisition or divestiture terms, gas-to-power option, and specific fiscal terms.
The developed system allows oil and gas companies to get better business insight, save modelling and planning time and go beyond error-prone spreadsheets. Particularly small to medium companies can benefit having solution that address inherent limitations of spreadsheets but at the same time does not require investment in the costly enterprise systems.
New Foam Drilling Hydraulics Calculations by Using Two Foam Flow Regimes
Authors: Edrisi Ali Reza , Kam Seung Ihl 
Published: September 2015

Abstract
In spite of its complexities, foam underbalanced drilling has unique advantages such as reduced formation damage, improved rate of penetration, higher cutting-transport capacity, and lower circulation losses. Recent experimental studies in a wide range of experimental conditions show that foam flow in pipe can be represented by two different flow regimes: (i) the low-quality regime showing stable plug-flow pattern with fine-textured foams and (ii) the high-quality regime showing unstable slug-flow pattern with alternating free-gas with fine-textured foam segments. Such a new concept was successfully captured by a foam modeling technique with five model parameters, reproducing two distinct pressure contours.
This study, for the first time, constructs foam drilling hydraulics model with two foam-flow regimes handling both stable and unstable flow characteristics, and investigates how the model improves current foam drilling hydraulics modeling based only on stable foam flow behavior. The results from three different scenarios (scenario 1: a vertical well, scenario 2: a deviated well with relatively short horizontal section, and scenario 3: a deviated well with relatively long horizontal section) with the transition foam quality between the two flow regimes (fg*) around 75-85% showed that significant differences in drilling hydraulics calculations might occur when the conventional technique was replaced by this new technique. For example, a drilling scenario tested with 10,000 ft deep vertical well (scenario 1) was shown to have as much as 32%, 48%, and 25% deviations in foam density, total velocity, and pressure gradient, respectively, at the bottomhole. Examples from two other deviated well trajectories (scenario 2 and scenario 3) exhibited similar responses, showing even more deviations. These results clearly demonstrate why incorporating two foam flow regimes into the current drilling hydraulics calculations is a crucial step toward evaluating and designing foam drilling practice accurately and reliably.
Rheological Hierarchy Optimization Improves Fluid Displacement and Well Integrity, 3 Worldwide Case Studies
Authors: Shadravan Arash , Alegria Adriana , Castanedo Rodrigo 
Published: September 2015

Abstract
A good cement job is the Achilles' heel of sustainable production from oil and gas wells. Improving zonal isolation and the integrity of wells worldwide is the priority of well integrity engineers. Proper cement designs and job execution assure sustainable production with ideal zonal isolation. The US unconventional horizontal well drilling has been increasing over the recent years. There are several solutions and best practices including maintaining the rheological and friction pressure hierarchy of the fluids pumped. Spacer rheological properties modeling computer simulations lead to a smart spacer design and, if correctly executed, yield enhanced fluids displacement efficiency and well integrity. The objective of this paper is to demonstrate the benefits of rheological hierarchy optimization and explain the benefits of the execution of this concept in three case studies worldwide. A predictive rheological model was developed for a micro-emulsion weighted spacer technology which was pumped in these cases.
In the horizontal section of a well and during fluid displacement, density hierarchy would not prevent fluid intermixing and viscous fingering hence to improve the fluid displacement efficiency a rheological hierarchy optimization is essential. This study showcases how by engineering the rheological properties of a spacer fluid the friction pressure Hierarchy in the horizontal section (liner and long strings casings) was designed. Adjusting the proper spacer's viscosifier and surfactant and being able to predict the rheological properties is another key to achieve zonal isolation. A sensitivity analysis was performred with the inhouse cement displacement simulators and fluid compatibility tests were completed in the laboratory. Results presented by the in-house simulators with three dimensional (3D) visualization and bond logs confirm how engineering, planning and optimizing the rheological and friction pressure hierarchy could achieve zonal isolation.
Mechanical Versus Mineralogical Brittleness Indices Across Various Shale Plays
Authors: Kias E. , Maharidge R. , Hurt R. 
Published: September 2015

Abstract
In hydraulic fracturing, it is natural to think that regions of brittle rock are prime candidates for effective fracture network creation or may be relatively easy to fracture. Consequently, various forms of brittleness indices have been introduced, in part, to decide where to place perforation clusters in multi-stage horizontal completions. These brittleness indices are often calculated using correlations between elastic parameters and mineralogical data, primarily because mineralogical information is readily obtained from wireline logs, cores, or cuttings. This presents two unresolved issues. First, while it is likely that a relationship between brittle failure and stiffness qualitatively exists, the efficacy of leveraging these indices in a quantitative manner remains uncertain. Second, there are limited examples comparing direct rock core measurements to indices calculated from mineralogical data, leaving room for ambiguity in what the magnitude of brittleness indices mean to hydraulic fracture initiation and propagation.
This study aims to clarify the definition of brittleness by comparing laboratory-derived rock mechanical properties, mineralogical and mechanical brittleness indices. Shales evaluated include the Floyd, Haynesville, Eagle Ford, and Barnett. Rock properties measured in this study are Young's modulus, Brinell hardness, tensile strength, and compressive strength. The mineralogical content of the specimens was determined by the x-ray diffraction (XRD) technique. A mineral-defined brittleness index is computed from the XRD data, while the mechanical brittleness indices are computed from tensile and compressive strength testing of core from these shale formations. Results show little agreement among the mechanically based indices, but hardness measurement trends coincide with elasticity-based mechanical indices and mineralogical indices. Additional data is needed verify the possible relationship between tensile strength and mineralogy. Strong correlation exists between mineralogical-based brittleness and Brinell hardness in the Eagle Ford and Haynesville shales. The Brinell hardness index could be applied in lieu of brittleness with the added benefit of estimating proppant embedment.
Insights of Wormhole Propagation During Carbonate Acidizing: Constant Pressure vs. Constant Rate
Authors: Gomaa Ahmed M. , Nino-Penaloza Andrea , Cutler Jennifer , Chaudhary Saleem 
Published: September 2015

Abstract
Acidizing of carbonate reservoirs is a common technique used to restore and enhance production by dissolving a small fraction of the rock to create highly conductive channels. Literature review reveals that most acidizing studies are focused on acid injection at a constant volumetric rate (CVR) instead of at a constant injection pressure (CIP). Therefore, the primary objective of the present work is to investigate the benefits and recommended applications of each technique. The study analyzes dissolution patterns, and wormhole propagation rate.
A coreflood study was conducted using different Indiana limestone cores to assess both techniques. Additionally, a 2-D wormhole model was used to mathematically describe the acidizing phenomena. This model describes the reactive transport of acid as a coupling between Darcy scale flows. The algorithm captures the essential physics and chemistry of the acid reaction in a carbonate porous medium.
The study confirmed that all types of acid dissolution patterns (i.e. face, conical, wormhole, and branched) exist for both techniques (CVR or CIP). Unlike in the CVR technique, dissolution patterns during the CIP technique can change, tending toward a branched dissolution regime. The CIP technique required a lower acid volume to achieve breakthrough in the conical dissolution regime and a higher acid volume to achieve breakthrough the branched dissolution regime compared to the CVR technique. In a dominant wormhole pattern, both techniques required nearly the same acid volume for breakthrough. A CT scan confirmed that the CIP technique develops a uniform wormhole at a low initial injection rate. For the CIP technique, the acid injection rate increased exponentially with the volume of the acid injected.
Sand, Resin-Coated Sand or Ceramic Proppant? The Effect of Different Proppants on the Long-Term Production of Bakken Shale Wells
Authors: Hu Kyle , Schmidt Andrew , Barhaug Jessica , Wong Joe , Tian Jiaher , Hall Bobby E. 
Published: September 2015

Abstract
Proppants and their effect on the production of wells are not thoroughly understood. When selecting a proppant, operators deliberate: “Do I purchase a low-cost proppant to reduce completion costs or do I spend more for higher conductivity to increase long-term production and greater return on my investment?” Good well data can be difficult to obtain and completion designs can vary. Hence, only a few existing case histories provide apples-to-apples comparisons of long-term production performance based on the use of different proppant types.
Continuing our prior research (SPE Paper 169544), we present data that will help operators make informed decisions when selecting proppants for optimizing Bakken wells. To investigate effectiveness of different proppants, researchers tracked long-term production rates of several comparable well sets. For example, in the first study, three wells on the same pad in the Haystack Butte Field in McKenzie County, North Dakota were completed by one operator. A second study included 11 Bakken wells fractured by another operator in the Grail Field in McKenzie County.
All three wells in Haystack Butte Field were hydraulically fractured with similar completion methods. The only significant difference was the proppant type. One well used 100% uncoated sand, another well combined 45% uncoated sand with 55% resin-coated sand, and the third well used 45% uncoated sand and 55% ceramic proppant. The well completed with sand and ceramic proppant did not have the highest initial production rate (IPR), but had, on average, 20% higher production over a 365 day period. The well where sand was combined with resin-coated sand produced a higher IPR. However, over 365 days, that well's production was outpaced by the other two wells with the sand/ceramic well delivering the best long-term production of all three. Similar findings were confirmed among the wells in the Grail Field. This study focused on 11 Bakken wells that used sand with a tail in of 30% to 40% ceramic proppant, sand with a tail in of 30% resin-coated sand, and sand with 50% higher volume. It also indicated that using a high percentage and high volume of ceramic proppant delivers superior long-term economic benefits in Bakken wells.
These findings, in addition to others outlined in the paper, challenge the preconception that wells completed using ceramic proppant should deliver higher initial production rates. Time and again, the findings demonstrated that the long-term production of Bakken wells completed with ceramic proppant significantly outperforms wells completed exclusively with other proppant types. Moreover, data demonstrates that compared to sand-only completions, resin-coated sand helped improve initial production but did nothing to improve long-term production, especially in deeper wells.
Study on Inhibition of High-Molecular-Weight Paraffins for South Eagle Ford Condensate
Authors: Gawas Kiran , Krishnamurthy Pushkala , Wei Fang , Acosta Erick , Jiang Ying 
Published: September 2015

Abstract
The deposition of high-molecular-weight paraffins in crude oil and condensates, especially with an average carbon number greater than 40, is difficult to treat using chemical methods. Expensive physical remediation methods, such as hot oil treatments and pigging, must be used in such cases. This paper describes the development of paraffin inhibitors for the targeted inhibition of waxes having an average carbon number greater than 40. The study was conducted for condensates from the South Eagle Ford shale formation.
The effect of inhibitors on deposition was studied using a cold finger testing method. A testing protocol was developed to target the deposition of high-molecular-weight waxes having an average carbon number greater than 40. The effect of paraffin inhibitors on the deposits was characterized using high-temperature gas chromatography (HTGC) and differential scanning calorimetry (DSC) techniques. The paraffin inhibitors commonly used tend to inhibit smaller chain paraffins and thus increase the relative amount of longer chain paraffins. This tends to form harder deposits, which are difficult to treat. The new class of inhibitors developed in this study showed improved performance with regard to preventing the deposition of waxes containing high-molecular-weight paraffins. HTGC analysis of the cold finger deposits showed more than a 50% reduction in the deposition of paraffins having a carbon number greater than 40 for the inhibitors tested. In addition, the use of inhibitors resulted in softer deposits. Thus, using inhibitors targeted at the heavier paraffins that soften the deposit could reduce the frequency of hot oiling and pigging operations required in field applications.