bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multi-Zone Cased Hole Frac-Packs and Intelligent Well Systems Improve Recovery in Subsea Gas Fields
Authors: Burton R. C. , Gilbert W. W. , Nozaki M. , Pandey V. J. , Adams M. D. , Peterson E. M. , Zhou L. , Ray T. W. , Fleming G. , Leitch J. C. 
Published: October 2017

Abstract
A nine well subsea development project has been completed using cased hole frac-packs for sand control and an innovative multi-zone intelligent well system to improve recovery from a series of shallow, low pressure, gas reservoirs. In these wells, cased hole frac-packs have been installed to provide reliable sand control over the long, low net-to-gross, sand/shale target sequence: typically, three to six frac-packs per well. This outer cased hole frac-pack completion is then augmented with a multi-zone intelligent well system, consisting of isolation seals, surface controlled zonal isolation valves and downhole pressure/temperature gauges. The intelligent well system is run as a separate inner string to provide flow monitoring capability and allow shut-off of zones producing high water volumes. This critical water shut-off capability eliminates the risk of one or more high water production zones loading-up and killing adjacent low-pressure gas zones with associated loss of reserves.
To date, a total of nine wells have been completed and are being successfully produced from three subsea gas fields. To maximize recovery from the fields' numerous but relatively thin gas reservoirs, production wells are completed over three to six separate intervals. These frac-packed intervals are then grouped to allow flow control and pressure/temperature monitoring to occur through up to six surface operated Interval Control Valves and associated downhole gauges. This combination of sand control and intelligent well control has provided an ability to perform multi-rate flow tests and pressure build-up tests on each reservoir interval to detect the start of water production or identify other impending production issues. After roughly five years of production service to June 2017, four of the 34 zones completed in the nine well project have had to be shut-in to eliminate high water production. These water shut-off actions performed via the surface controlled interval control valves are estimated to have improved gas recovery factors from 50% to 60% without requiring rig intervention.
This paper will describe the reservoir challenges, completion design and operating practices employed in this successful program.
Investigation of Pressure Profiles of Reservoirs with Wells under Transient, Unstable Flow
Authors: Sousa Pedro Cavalcanti , Garcia Artur P. , Waltrich Paulo J. 
Published: October 2017

Abstract
In this work, to the knowledge of the authors, it is the first time that an analytical solution demonstrates how the pressure profile changes with frequency and when this change takes place. Case studies are also presented to analyze the impact of different pressure profiles on well deliverability. Reservoir pressure profiles associated with steady-state, pseudosteady-state, and transient flow for a constant pressure drawdown were derived decades ago. These profiles, however, may not be applicable near the end-life of a well due to the unstable nature of fluid flow in the wellbore (e.g., liquid loading, slugging), and could explain why certain wells stop flowing before predicted. This paper shows how the flow instability changes the reservoir pressure profile and what consequences that change might bring to well production.
Previous publications have shown numerical and experimental evidences that not only the pressure profile in the reservoir changes when there is an increase in the frequency of oscillation in the bottomhole pressure, but also that understanding this phenomenon is fundamental to reliably predict the time-dependent deliverability of wells.
Rate-Transient Analysis Based on Power-Law Behavior for Permian Wells
Authors: Chu W. , Pandya N. , Flumerfelt R. W. , Chen C. 
Published: October 2017

Abstract
In unconventional reservoirs, the application of many rate-transient analysis (RTA) techniques rely heavily on the identification and analysis of the linear flow regime, which is characterized by a ½ slope on a log-log plot of Δp vs. t. Through our analysis of more than 400 wells with downhole pressure gauges in the Wolfcamp shale of the Permian basin, we observed power law behavior, but with slopes much different than ½ over long periods of time. In many cases, the duration of the straight line with a slope different from ½ lasts for years, without ever converging to ½. In some cases, the slope changes over time but rarely is the characteristic ½ slope observed over long periods. Rate forecasts would be in error if were to assume that the slope would converge to ½ slope at a later time.
In this work, we present examples of Permian Wolfcamp horizontal wells with measured bottomhole pressure (BHP) to demonstrate the characteristic power-law behavior with slopes different from ½. Power-law behaviors are typical in heterogeneous systems and are identified using the Chow pressure group (CPG).
Based on the concept of the power-law behavior, we have developed a workflow to analyze multiphase rate-transient data with high quality measured BHP. Ultimately, the new workflow for rate-transient analysis uses power-law characteristics to evaluate well performance and is a complementary tool to traditional methods such as Arps decline-curve analysis. This paper outlines a power-law analysis workflow scheme and demonstrates that the Chow group is a convenient means to identify the exponents of straight lines. In addition, we present case studies to demonstrate the application of this technique to predict the long-term well performance from choked-back wells, to evaluate long-term performance changes associated with offset frac hits, and to estimate the hyperbolic decline-curve b-factor.
Comparison between Production and Economic Indicators in the Production Strategy Selection for Polymer Flooding
Authors: Botechia V. E. , Schiozer D. J. 
Published: October 2017

Abstract
The selection of a production strategy, seeking maximization of field performance according to some indicator, is a complex and important task. Choosing the indicator to be used to complete this task can lead to different results, and this choice must be carefully made to reflect the company objectives. Many companies seek only maximization of the recovery factor, neglecting costs and investments necessary to reach this goal. This may lead to a poor economic performance. Moreover, decisions that require extra investments (for instance, the use of some enhanced recovery technique such as polymer flooding) should be evaluated and taken into account in the analysis, since there are differences in the cash flow of the project options and these additional investments are important to the final decision.
The objective of this paper is to compare the use of production and economic indicators in the production strategy selection, considering that there are not budget constraints or platform restrictions.
The methodology consists of an optimization process using two different indicators: net present value (NPV) and oil recovery factor (RF). Three different approaches are addressed: (A) using only NPV as objective-function (OF) in the whole process; (B) using only RF as objective-function in the whole process; (C) using NPV as objective-function in the steps that the investments are not fixed (the number of wells and platform capacity are not determined yet) and changing the objective-function to RF when the main investments do not vary (number of wells and platform capacity are already determined). The application of the methodology is made in a model that represents an offshore heavy oil field using polymer flooding as recovery mechanism.
The results show that NPV has advantages when considering the whole development of the field in this work conditions (no budget or platform restrictions). In this case, the consideration of the recovery factor as single indicator leads to an overestimated number of wells, resulting in bad economic performance due to high costs, even with higher oil production in relation to the optimization made considering only NPV. The advantage of using NPV is that it considers in its calculation several parameters, such as revenues from oil production, costs from oil and water production, costs from water injection, speed of recovery, and in the case of this work, the cost for polymer injection, which can affect strategy selection, mainly when comparing with other recovery mechanisms. However, when the investments do not vary significantly (number of wells and platform already defined) there is a strong correlation between oil produced and economic return, so that the optimization considering NPV or RF leads to similar results.
Successful Integration of Drillstem Testing, Closed Chamber Testing, and Wireline Formation Testing: A Deepwater Case History
Authors: Azari Mehdi , Khan Waqar , Elshahawi Hani 
Published: October 2017

Abstract
For more than a decade, optimal value testing (OVT) has been advocated as a methodology that, in most cases, can replace conventional drillstem testing (DST) for in-situ permeability measurement. The term OVT refers to any pressure-transient test during which live hydrocarbons do not have to be produced directly to the surface (Elshahawi et al. 2008, 2012). Three primary types of well tests have been considered as part of the OVT toolbox: injection testing, wireline formation testing, and closed-chamber system testing with cleanup and repeat surges, which is a proprietary analysis technique.
This paper reviews the earliest OVT case studies retrospectively, with the benefit of several years of production. These cases include the first successful multicycle well testing/fluid-sampling closed system testing operation with near-emission-free and real-time data transmission to surface in deep water. Operations were conducted from a moored vessel without the use of a subsea test tree, setting a world record at the time for the maximum depth at which any vessel had been moored. The operation successfully gathered all crucial data; the overall test duration was shortened; and most importantly, safety and formation fluid handling were enhanced with no hydrocarbons offloaded or flared.
Data collected during all phases of the testing process were analyzed. These included the perforation, subsequent surge into the testing chamber, initial cleanup of flow/buildup, optimized closed-chamber surge flow, and final cleanup of flow/buildup. Standard techniques were used to analyze the traditional DST, but specialized techniques and software were developed to help plan and analyze the closed-chamber surge testing during perforation and surge testing. Data from the testing phase were used to generate an earth model to forecast production from the field. Several years of observed production confirm the early testing results and validate the OVT philosophy and the closed-chamber testing technology.
This paper discusses the testing protocols, optimized system design, and novel analytical techniques employed. It also compares pressure transient analysis (PTA) results obtained from surge testing, standard DST, and formation tester. The consistency of formation pressure and permeability measurements obtained from the various testing techniques and the agreement with actual production performance lends credibility to the results and confirms their viability for replacing conventional DSTs in many cases. Particularly in deep water, where cost and environmental constraints limit the feasibility of conventional DSTs and where early data gathering is essential, such techniques can provide a powerful complement—and often a viable replacement—to well tests.
Analytical Development of a Dynamic IPR for Transient Two-Phase Flow in Reservoirs
Authors: Sousa Pedro Cavalcanti , Garcia Artur Posenato , Waltrich Paulo J. 
Published: October 2017

Abstract
This work presents a new Inflow Performance Relationship (IPR) for transient two-phase flow in reservoirs. This relationship is called Dynamic IPR and it accounts for the flow dynamics at the near-wellbore region and provides a simple but robust solution for transient simulations of two-phase flow reservoirs. The Two-Phase Dynamic IPR not only couples the wellbore bottomhole flowing pressure with oil and gas flow rates, but it also provides the pressure profile within the reservoir. Commercial software are capable of coupling discretized reservoir simulators to wellbore models; however, these are computationally more expensive and complex than the Dynamic IPR. The use of conventional IPRs, on the other hand, is simple and straightforward, but they cannot account for the wellbore-reservoir dynamic, making them inaccurate in fully transient models.
The proposed Dynamic IPR is validated against the results from a state-of-the-art reservoir simulator using finite element methods. The Dynamic IPR shows an agreement of ±8% with results from the discretized reservoir simulator.
Self-Assembling Nanoparticles: A Unique Method for Downhole Sand Consolidation
Authors: Kalgaonkar Rajendra , Chang Frank 
Published: October 2017

Abstract
When the formation is unconsolidated, sand particles can be produced into the wellbore. Such production of sand particles is undesirable as it lowers the permeability of the producing zone, erodes surface and downhole equipment. Costly intervention may be required to mitigate the damage to the well integrity and the reservoir deliverability. The most common methods of controlling this unwanted sand production involve: 1. Filter produced fluids through a gravel pack retained by a screen or 2. Use of consolidating fluids such as resin, a curing agent, along with other chemicals to create a conducive environment for the resin curing reaction to occur. The gravel packing completion requires special tools and equipment therefore higher cost. In the case of sand control by chemical consolidation, the resinous material tends to have relatively uncontrollable setting times, strength, placement, and regained permeability leading to unsuccessful treatment. With both cost and treatment effectiveness in mind, it is desirable to develop an improved material and method to mitigate sand production by consolidating the formation sand without impairing well productivity or injectivity.
The present paper describes the development of a unique chemistry for sand control in unconsolidated formations. This chemistry involves using positive charge modified nanoparticles that can self-assemble over the unconsolidated formation sand particles to form a layer of consolidating material thus preventing any unwanted sand production. The new consolidation treatment material consists of colloidal nanoparticles modified using a cationic modifier and ionic strength modifier that can be placed downhole as a single pill. The pill has high affinity to the solid surface therefore less prone to build up in the pore space. Once cured at reservoir temperature it forms a thin layer of hard gel around the surface of the sand particles, thus cementing the sand grains together at the same time maintaining open porosity to ensure easy flow of produced hydrocarbons or injected water.
The newly developed sand consolidation formulation was studied for their ability to consolidate loose sand and at the same time maintain good permeability. The effect of various ionic modifiers on consolidation properties was studied. The ability of the cationic modified nanoparticles to self-assemble around unconsolidated sand and eventually cure to form a consolidated sand pack was investigated. Regain permeability studies showed good regain permeability of the consolidated sand pack. Furthermore, this paper describes the concentration effect of the cationic modifier on the regain permeability. Finally, it shows that the new product provides a controllable curing time, thus avoiding any premature setting of the nanoparticles in the wellbore.
Development of a Technology Transfer Model in the 2020 Era for the Oil and Gas Industry
Authors: Viscomi J. C. , Schoeling L. G. , Williams T. E. 
Published: October 2017

Abstract
Technology transfer or acceptance is difficult in every industry; however, the oil & gas industry has had it especially hard with volatile commodity prices, variability of technology sources and the regulatory uncertainty. In 1994 in a paper entitled, "Development of a Model Technology Transfer Program to Assist Independent Operators"5 the authors outline a model for independent operators to embrace and utilize new technology with an aim of reducing well abandonment common at the time and increasing overall production for the long term. This paper seeks to expand upon that work updating its methodology for today's more challenging operating environments. It sets the course for companies to continue to take advantage of technology and best practices in ways that optimize operations, improve economics and secure production far into the future.
This paper describes a program that any operator can utilize to get quick access to technology without significant costs while increasing oil production and decreasing operating expenses. This technology transfer program utilizes methods from other technology based industries yet is focused and builds upon past principals established by technology transfer programs like the Research Partnership to Secure Energy for America (RPSEA) and the Petroleum Technology Transfer Council (PTTC). This paper contains several fundamental components including: 1) Technology Leadership guided by industry to initiate and manage the technology transfer process, 2) Problem Identification activities that help create a two-way dialogue between industry and leadership organization, 3) Documented Demonstration Projects rooted in findings from problem identification activities 4) Focused Technology Workshops serving to disseminate demonstration project findings and 5) Regional Resource Centers with Outreach Resources serving as local and online repositories for easy future access by industry.
Additionally, this paper identifies various sources of research and technology development funding illustrating how an effective technology transfer process can improve the time between idea and technology commercialization. In the last few years the landscape of the oil and gas industry has changed dramatically in relation to technology. Many operators, out of necessity, have adopted a manufacturing or mass production mentality regarding their wells while disregarding optimization and the use of technology for long-term production.
This paper specifically addresses the needs of the modern oil and gas operator who does not have, or has limited access to industry research labs, government funding and university programs. It provides a step by step process designed to help operators become engaged in technology transfer in a cost-effective manner with a goal of improving their individual businesses as well as the industry at large.
Using Wireline Formation-Tester Data for Reservoir Characterization and Connectivity Determination in Ultradeepwater and High-Pressure Wilcox Formation in Gulf of Mexico
Authors: Azari Mehdi , Hadibeik Hamid , Eyuboglu Sami , Jambunathan Venkat , Khan Waqar , Ramakrishna Sandeep , Haack Joshua , Bargas Connie , Khan Mashiur 
Published: October 2017

Abstract
Deepwater turbidite reservoirs have always presented several reservoir characterization challenges. Determining the complex architecture of the sand bodies, correlating them across multiple wells in the structure, and defining the sedimentological facies to determine the reservoir vertical communication and boundaries are some challenges in these Gulf of Mexico (GOM) turbidites. Other formation-related challenges of turbidite reservoir exploration and development include understanding reservoir rock quality and compartmentalization, as well as the identification of fluids. Deepwater exploration and development require innovative, cost effective evaluation technologies—technologies that help manage ultradeep and high-pressure environments. Having a detailed description of reservoir properties, fluids characterization, and a determination of the reservoir connectivity are crucial for understanding the reservoir and optimizing the field development plan.
This study describes the wireline formation tester (WFT) operations performed in a harsh environment [ultradeepwater subsalt formation (&gt; 32,000 ft) and high pressure (&gt; 25,000 psi)] to obtain pressure data, establish gradients, evaluate vertical connectivity using vertical interference tests (VITs), check for compositional variation in different oil columns, and obtain clean formation fluid samples. Downhole fluid analysis was performed to help ensure the quality of formation samples and determine the fluid compositional analysis in real time during pumpout. To obtain high quality fluid samples while minimizing costs, an innovative technology—namely, a focused sampling probe—was used, eliminating the need for long pumpouts. Representative formation fluid samples were captured from three sample depths in approximately two hours per sample depth with minimum oil-based mud (OBM) contamination (&lt; 5%).
All the available openhole log data were integrated to understand the reservoir before running the WFT. Optimizing pressure and sampling depths (most representative intervals) can help reduce uncertainty when determining the number of pressure and sample points in the reservoir. Formation mobility, near-wellbore skin damage, reservoir pressure, downhole compositional fluid analysis, and reservoir connectivity were evaluated in a unique and challenging environment. Reservoir connectivity results from formation testing show good alignment with the presence of fractures and other sedimentary features from borehole image data. A similar methodology can be extended to other deepwater turbidite reservoirs in the GOM.
Haynesville Shale Horizontal Well Completions: What Has Been Learned Through Post-Stimulation Completion Diagnostics and How These Learnings Can Be Employed to Make Better Wells
Authors: Warren Mark N. , Jayakumar Swathika , Woodroof Robert A. 
Published: October 2017

Abstract
The optimistic outlook of the petroleum industry, especially with regard to natural gas, has led to a renewed interest in shale gas plays and more specifically to the Haynesville Shale formation. Through the use of post-stimulation completion diagnostics, insights have been obtained that can be utilized to optimize future hydraulic fracturing completions.
This paper will illustrate the use of post-stimulation completion diagnostics in identifying trends that are associated with effective completions in the Haynesville Shale. Case histories will be presented which illustrate methods that have increased the overall completion effectiveness in relation to proppant placement, wellbore deliverability, and ultimately increased production performance.
A horizontal well database (&gt; 500 wells) was compiled to identify effective completion trends across the Haynesville Shale formation. By employing proppant and fluid-based tracers, hydraulic fracture characteristics, well deliverability, and ultimately production performance were measured to highlight trends that increased overall completion effectiveness. Primary completion results highlighted areas including, but not limited to, effective proppant placement, full lateral production, frac stage length and containment, perforation cluster spacing, wellbore lateral length, and constrained flowback effects.
This paper reviews many of the insights that have been developed through this use of post-stimulation completion diagnostics in the Haynesville Shale formation and which have led to increased completion optimization, production enhancements, and field-wide cost reductions.