bluuebunny/crossref_metadata_2025_split huggingface dataset:
Environmental and Transport Effects on Core Measurements of Water Saturation, Salinity, Wettability, and Hydrocarbon Composition
Authors: Misra S. , Torres-Verdin C. , Sepehrnoori K. 
Published: June 2014

Abstract
Unaltered portions of whole core provide the most reliable measurement of rock properties for hydrocarbons-in-place, reserves, and reservoir-development calculations. However, core cutting and core surfacing operations can significantly alter the water saturation, salinity, hydrocarbon composition, and wettability of the whole core, among other rock core properties. It is necessary to correct laboratory measurements of rock core properties to their in-situ values, and to identify the unaltered volume of whole core that is representative of in-situ reservoir properties. To that end, we have developed a numerical simulator based on an equation-of-state compositional method that models three-dimensional time lapse variations of multiphase fluid saturation, water salinity, phase composition, and wettability of a whole core during core cutting and subsequent core surfacing operations in a vertical wellbore. The UT Coring Simulator (UT-CS) quantifies mudcake growth, mud-filtrate invasion, miscibility of invading filtrate with connate fluid, wettability alteration due to surfactants in invading mud filtrate, phase transition and fluid expulsion during core surfacing. UT-CS delineates four distinct fluid flow mechanisms that occur within whole core during coring, namely, compressibility-driven concurrent flow, capillary pressure-driven countercurrent imbibition, axial flow, and surfacing-induced fluid phase expulsion. During core cutting, we observed that at the center of a whole core water-base coring mud could cause relative changes in fluid saturations, up to +/−100%, and in salinity, up to +/−15%. More importantly, measurable changes in in-situ core properties can also occur during oil-base mud (OBM) coring owing to countercurrent imbibition flow. We show that mudcake quality is critical towards preserving core properties during core cutting. On the other hand, during core surfacing (when mudcake is nonexistent), alteration of core properties is minimized by reducing the speed of core surfacing after reaching the depth at which there is an abnormally large increase in the gas volume fraction in the whole core.
A Milestone in Production Optimization in the Niger Delta Using Intelligent Completions
Authors: Chinwe Uchendu , Nnanna Erasmus , Okpokpor Obaro , Yahaya Ibrahim , Friday Otutu , Agbonaye Cardinal 
Published: June 2014

Abstract
With increasing energy demand, cost optimization and environmental challenges; using smart techniques to produce multiple reservoirs in a single well is a much welcomed concept. Intelligent completions have been proven to be an efficient reservoir management tool and Shell Nigeria (SPDC) has tapped on this innovative technology to optimize production enhancement in one of its fields.
In this paper an overview of the deployment of the first onshore intelligent well technology in one of the largest field in the Western Swamp area in Nigeria will be reviewed. The well is a part of the Nembe Creek Phase-1 campaign and serves as a pilot for the Phase-2 Smart Well campaign planned for 2013. This paper in detail describes the innovative techniques deployed and benefits of this smart completion are discussed with particular reference to Well A-1
SPDC's 1st smart completion was completed in May 2012. It consists of three (3) intervals - having one of the longest intervals perforated in SPDC (374ft cum length) which was perforated in a single trip system. This well also sets a trend worth replicating as it recorded the best completions installation time amongst competition in Nigeria. This was achieved by effective team work & thorough upfront planning.
The paper will highlight details of the well design, installation/surface equipment hook up in addition to the well clean up and performance monitoring strategy. The paper also highlights lessons learned at each phase of the well project and describes how those lessons will be applied to ensure the next phase of intelligent completion system planned in the field will be implemented to ensure sustained success in smart well technology in Shell Nigeria.
Successful Exploration Drilling in a Very Narrow Mud Weight Window with Crossflow Using Automated Managed Pressure Drilling: a Case History in Mexico East
Authors: Rodriguez J. , Dominguez A. , Villalobos S. , Chavarria M. A. , Morales J. A. , Beltran J. C. , Ruiz C. A. , Rojas J. 
Published: June 2014

Abstract
The well used for this study, 301, was originally considered "un-drillable". A steep pore pressure ramp combined with loss zones resulted in a cross-flow environment that was very difficult to control, as the drilling window was effectively reduced to less than 0.09g/cc. The ability to precisely control the pressure profile in the annulus is one distinct advantage of Managed Pressure Drilling (MPD). In worst case scenarios with very narrow pore pressure and fracture gradient windows, the tight drilling margin may require the use of an automated MPD system. The system can precisely apply surface back pressure to maintain a balance of flow into and out of the well by maintaining a constant bottom hole pressure and replacing the friction pressure losses in the annular space when the rig pumps are off.
During the execution of the well 301, all Automated MPD benefits were applied (Dynamic FIT's, Dynamic Flow Checks and CBHP control) to detect and control kicks, identifying and control ballooning effects and maintaining the bottom hole pressure within the high pressure tight window between 2.426 and 2.451 g/cm3. Proper selection, configuration and continuous calibration of the hydraulics simulations during drilling operations was critical to drill the production section and successfully reach target depth. This paper presents the hydraulics modeling during the planning phase and techniques used during execution with the automated MPD system.
Following two previous failed attempts, the 301 well was the first successful well to penetrate the reservoir in the Camaronero field, proving automated MPD as a successful drilling technique for this field.
Real Time Surveillance and Optimization of a Heavy Oil Field
Authors: Cramer R. , Babbar S. , Brouwer R. , Schotanus D. 
Published: June 2014

Abstract
Data driven well models were constructed for a steam injected field producing 800 m3/d of API 8 bitumen from 100+ beam pumped wells. The modelling technique is known as Production Universe(PU) which gives real time estimates of oil and water flows for each of the wells during steady state and transient operations. PU tracks rates when wells are starting-up, closing-in and for transient flow oscillations, resulting in automatic daily reports of total production and deferment (low and off) for each well.
The deferments reports drive an exception-based surveillance (EBS) process by flagging the engineers of the largest production gain opportunities. EBS analysis and associated well remedial actions have resulted in an 8% production gain. Continuous estimation of well bitumen and water flows has allowed real time optimization of the entire field. This is achieved by continuously maximizing production within the plant water handling and economic constraints. The system knows how much oil and water the wells are producing and recommends rates for each of the wells to maximize production within the water handling capability.
The EBS process has been successfully running for more than a year. The RTO process has just been introduced, hence it is too early to estimate the incremental gain.
This paper will detail the surveillance and optimization techniques, learnings and associated work processes.
Achieving Optimum Placement of Stimulating Fluids in Multilayered Carbonate Reservoirs: A Novel Approach
Authors: Ramondenc Pierre , Lecerf Bruno , Tardy Philippe M. 
Published: June 2014

Abstract
The main challenge in acidizing multilayered carbonate reservoirs is to achieve optimum placement of the stimulation fluid. Optimum placement has often been interpreted as uniform placement of fluid across the producing interval, regardless of the objective of the intervention or its constraints. In addition, the current practice tends to design acid treatments based on information such as damage skin in each reservoir layer, which is rarely accurate. Therefore, a treatment initially designed as "optimal" often does not meet expectations because its design was based on erroneous formation and/or damage properties.
We present an alternative approach to designing and executing matrix stimulation treatments in multilayered carbonate reservoirs. The proposed workflow does not rely on damage skin by layer during the design and the execution phases of the treatment. It instead requires a step of determining where the acid must be injected, at which rate and volume, to meet an objective function. This determination can be done considering an undamaged well, therefore relying on formation properties that can be measured with sufficient accuracy. How damage influences fluid placement is dealt with during the execution phase without relying on indirect parameters such as skin or local skin. Instead, by measuring the rate and volume of fluid injected in each layer, one can take the corrective actions that will ensure the placement of the optimal volume of stimulating fluid in the target layer(s), at the optimal rate determined in the design step.
By using the objective function in conjunction with a fluid placement simulator, we show that different treatment objectives and/or constraints may require radically different strategies and tools for an optimal outcome. In addition, when carrying out a sensitivity analysis on parameters that are uncertain, it is possible to select the treatment that is most robust to variables that cannot be measured with accuracy (i.e., the treatment whose outcome is the least sensitive to uncertainties).
The workflow we present here allows decoupling the questions of optimal placement of a fluid for a given well, the performance of the materials selected, and the treatment schedule considered. By using the optimum design and the objective function as guidelines, engineers can now take full advantage of real-time monitoring capabilities of tools such as fiber-optic-enabled coiled tubing or slickline, not only to take corrective actions during the treatment, but also to ensure that optimum volumes and rates are effectively delivered in the targeted zones to meet the stimulation objective. Case studies will be presented to illustrate this novel approach.
Innovative Technology to Extend EM-M/LWD Drilling Depth
Authors: Rodriguez Ali , MacMillan Clayton , Maranuk Chris , Watson Joshua 
Published: June 2014

Abstract
M/LWD (Measurement or Logging While Drilling) data transmission from downhole to surface can be accomplished using several different technologies, but the most popular methods include mud pulse telemetry and EM (electromagnetic) telemetry. Mud pulse uses a downhole valve to restrict fluid flow and create a pressure pulse through which data is sent to the surface via the mud column. EM telemetry uses a downhole transmitter and surface receiver to transmit data through the formation using electromagnetic waves. EM telemetry is often the preferred telemetry method when drilling on land or in an underbalanced environment. Advantages of EM telemetry over mud pulse include: reliability (no moving parts downhole), speed (can often be configured to exceed six bits per second and to communicate independent of flow rates), and tolerance to lost-circulation-materials (not dependent on drilling fluid characteristics). A key disadvantage is depth limitation due to high formation resistivity and signal attenuation.
A new technique has been developed that reduces signal attenuation and enhances the signal-to-noise ratio to increase the operating depth of an EM telemetry system. This method employs an insulated wire that is externally attached to a standard casing string; a borehole receiver typically located downhole and connected to the casing, and a surface transceiver. The borehole receiver picks up the EM signal at the casing connection terminal and transmits it via the external signal wire to the surface transceiver, which decodes the EM signal. The wire exits the casing near the surface and passes through a wellhead modified to accept the cable pass-through. There is negligible attenuation within the signal wire.
This technique extends EM-M/LWD applications into well profiles, including long laterals, where high resistivity and attenuation has previously prevented its use. Of particular interest is pad drilling, where one insulated wire can be installed on the casing string of an anchor well and serve as a receiving antenna for the other satellite wells drilled on multi-well pads.
This paper will describe the engineering concepts underlying the new technique and how it improves EM drilling technology. It also documents testing and summarizes actual field results of multiple lateral wells successfully drilled in highly resistive and attenuative formations with the new technique.
A Tale of Two Flowlines—Paraffin Plugging and Remediation
Authors: Goodman N. T. , Joshi N. 
Published: June 2014

Abstract
Production impairment due of paraffin deposition and plugging is the second most concerning issue in deepwater Gulf of Mexico after hydrates. This paper discusses two separate instances of well flow impacted by paraffin deposition and the comparison of modeling with field observations.
The well being discussed is in 2,315 feet of water depth capable of flowing through two 6.2 mile 4.5" x 7" pipe-in-pipe flowline pigging loop system with insulated SCR (Steel Catenary Risers) and an electro-hydraulic control umbilical. The well is a smart completion of two zones in which the lower zone was flowing initially.
After one and half years of production through one flowline, the well was split to flow through both flowlines to improve the production rate. Approximately one year of successful flow through both flowlines which was maintained at similar pressures, it was detected that one of the flowlines was plugging. This paper discusses the results of the plugged flowline and remediation measures attempted. The paper also presents modeling work to correlate field observations with industry available simulator results.
After the remediation measures, production from the lower zone was routed through a single flowline at a relatively low flow rate, resulting in temperatures below the fluid's wax appearance temperature. The low flowing temperatures resulted in partial paraffin plugging which were observed based on pressure measurements. To mitigate the partial plugging of the flowline, the production zones were switched (lower was closed and upper was opened). With the upper zone open and able to flow at a much higher rate, temperatures above the wax appearance temperature were achieved. This resulted in melting of the deposited paraffin and eliminated further paraffin deposition.
This paper discusses a unique method to mitigate paraffin deposition concerns and a comparison of modeling results to field observations.
Prediction of Two-Phase Flow Splitting in Looped Lines Based on Energy Minimization
Authors: Dabirian R. , Thompson L. , Mohan R. , Shoham O. , Avila C. 
Published: June 2014

Abstract
Looped gas-liquid multiphase flow pipelines are utilized by the oil and gas industry to reduce pressure drop and to increase flow capacity. They can be installed alone as a flow splitter, or they can be combined in series to form a manifold.
Application of looped lines is not unique to the petroleum industry, as they are also applied in other industries such as the nuclear and chemical. There has not yet been a comprehensive fundamental investigation of the flow behavior or predictive methods available for such systems because of the huge complexity involved with respect to several process variables such as flow patterns, fluid properties, phase velocities as well as the pipe geometry. Uneven splitting of the gas and liquid phases between the two looped lines can cause malfunction of the downstream processing equipment. In this study, over 65 experiments at different flow conditions are conducted in a looped system utilizing unequal diameter looped line configurations to investigate the pressure drop during the uneven flow splitting. Most of the experiments were carried out with slug flow at the system inlet, while flow patterns such as slug flow, dispersed flow and stratified flow were observed in the looped pipes. A novel computational algorithm is developed for predicting gas-liquid two phase flow splitting in the looped lines, based on energy minimization. The algorithm predicts the uneven splitting of the two phases as well as the corresponding pressure drop along the loop. Good agreements have been achieved between the measured and predicted flow splitting and pressure drop along the looped lines.
Improve Casing Design for WCD in Deepwater Wells
Authors: Wu Jiang 
Published: June 2014

Abstract
Intermediate casings in deepwater wells are now designed for well integrity under the worst case discharge condition (WCD), a severe casing collapse and axial compression condition. The severe collapse condition is from a reduced casing internal pressure from an un-controlled hydrocarbon fluid flow to wellhead with a possibly increased external pressure by APB - annulus pressure buildup, and the severe axial compression condition is from a casing "de-ballooning" effect by the severe collapse pressure, and from a casing thermal laod by elevated casing temperature on the un-controlled hydrocarbon fluid flow to wellhead. Re-investigation of casing design methodology becomes important and necessary in order to improve the casing design safety under the WCD condition in deepwater wells.
This paper presents triaxial stresses model analyses on casing collapse and axial compression, and proposes an improved casing collapse and axial compression design method for WCD in deepwater wells: (1) to use the direct differential pressure (external pressure minus internal pressure), rather than the prorated differential pressure currently listed in API/ISO documents on casing collapse design, together with an added "equivalent" axial tensile stress equal to the value of casing internal pressure; and (2) to use the effective axial compression load calculated by hydrostatic pressure condition of Pi (internal pressure) rather than the actual axial compression load on casing axial compression design. The proposed casing collapse design method is also supported by full-size casing collapse test data from a recent API work group study.
The proposed casing collapse and axial compression design method has been used in several deepwater projects in the recent years with success.
Meeting the Challenge of Reservoir Simulation in the World's Largest Clastic Oil Field - The Greater Burgan Field Complex, Kuwait
Authors: Ma Eddie , Ryzhov Sergey , Gheorghiu Sorin , Hegazy Osama , Banagale Merlon , Ibrahim Muhammad , Grupinar Omer , Dashti Laila , Filak Jean-Michel , Al-Houti Reham , Ali Farida 
Published: June 2014

Abstract
The Greater Burgan field in Kuwait is the largest clastic oil field in the world. Its sheer size, complex geology, intricate surface facility network, over 2,200 well completions and 65-years of production history associated with uncertainty present formidable challenges in reservoir simulation. In the last two decades, many flow simulation models, part-field and full-field, were developed as reservoir management tools to study depletion plan strategies and reservoir recovery options. The new 2011 Burgan reservoir simulation effort was not just another simulation project. Indeed, it was a major undertaking in terms of technical and human resource. The model size, innovative technology, supporting resources, integrated workflows and meticulous planning applied to this project were unprecedented in the history of the Greater Burgan field development. This paper describes work done to prepare a representative numerical model which could be utilized to optimize the remaining life of the reservoir complex. Right from the onset, representative numerical modeling concerns were identified. These led to a systematic collaboration framework being built in place between the static and dynamic modeling teams. Calibration of the model to the historical observations was executed at three levels, Global, Regional and Wells – the Cascade Approach. The cascade approach was designed to enable a concerted model calibration effort in accordance with the recurrent data quality. For instance, while the total field production history attains a high degree of accuracy, the data at the regional Gathering Center (GC) is of a lower level of certainty, but far more reliable than the data at an individual well. Commercial modeling software have been utilized extensively to produce several utilities such as water encroachment maps, Repeat Formation Tester (RFT) matching tools and aquifer definition and adjustment workflows. Subsequently, synergy in the integrated use of these tools produced a robust model calibration process on all three levels in the cascade approach.
The main goal of the project – development of a predictive simulation model, always remained at the fore of the project team's mind during the model calibration. Check-point prediction models were defined and constructed at regular intervals during the model calibration phase. This approach allowed qualitative assessment on the evolution towards a representative numerical model. Furthermore, it allowed synchronizing simulation workflows and expedited project deliverables. The overall result was a sound full-field reservoir simulation model that achieved a good match of production, pressure and saturation histories, leading to reliable forecasting of oil recovery under different development scenarios.
Production Decline Analysis Lessons from Classic Shale Gas Wells
Authors: Vanorsdale Charles R. 
Published: June 2014

Abstract
The objective of this paper is to expose long-term production data from "classic" Devonian shale wells to modern reserve assessment methods, in particular production analysis techniques such as the Power Law Exponential of Ilk et al. (2008) and the method of Duong (2010). Many of the wells selected for analysis will have been producing for more than 25 years prior to workovers or recompletions. The observations derived from this analysis will shed light on the long-term applicability of these techniques to estimate reserves in contemporary, high-profile shale gas plays. For comparison, the techniques will also be applied to classic Barnett shale wells with more than a decade of production history.