bluuebunny/crossref_metadata_2025 huggingface dataset:
All in One for Casing while Drilling Technology: Numerical, Analytical, and Experimental Results and Field Observations
Authors: Salehi S. , Karimi M. , Shahri M. P. , Aladsani A. , Ezeakacha C.
Published: June 2014

Casing while Drilling (CwD) is an efficient method by which to increase the fracture gradient in narrow pore-fracture pressure sedimentary basins and deep offshore applications. It offers hydraulic improvements and the ability to plaster cuttings to the wellbore wall, which can enhance the wellbore's hoop stress by wedging the created fractures. Although successful field applications of increasing wellbore integrity have been reported, uncertainties remain regarding the mechanisms and how to operationally capture the maximum attainable wellbore pressure. These uncertainties include the hydraulic complexities of fluids, role of Particle Size Distribution (PSD) and how it relates to the plastering effect, type of drilling fluids, borehole shape, role of lost circulation materials (LCM), and casing eccentricity.

This paper presents numerical, analytical and experimental methods to study the contributing factors in CwD applications. Laboratory experiments were conducted to evaluate the Particle Size Distribution (PSD) and filtration rate of the mud mixed with cuttings from a recently drilled well. Several tests were conducted using Permeable Plug Testing (PPT) equipment to evaluate the role of different LCMs, to fill the PSD gap and to capture the strengthening effect.

In addition, advance finite-element methods were used to model the near wellbore area and hoop stress changes with consideration of the formation's poro-elastic properties. Furthermore, the frictional pressure lost during the CwD operation was evaluated using Computational Fluid Dynamics. Analytical models were used to investigate different boundary conditions when applying finite-element analysis.

The numerical simulations and laboratory experiments in this work were based on a recently drilled well in South Louisiana, where severely depleted sections were drilled successfully. Previous drilling records in this area report multiple problems with lost circulation, tight holes and other wellbore stability issues. Results from the numerical models and laboratory experiments agree well with field observations. The analysis presented in this paper indicates that an optimum PSD can significantly mitigate lost circulation and minimize the need to add LCM.
Rubble Zone Below Salt: Identification and Best Drilling Practices
Authors: Saleh S. , Williams K. E. , Rizvi A.
Published: June 2014

A joint-industry project (JIP) from 2005 through 2009 involved acquiring, analyzing, and documenting more than 100 subsalt wells in the Gulf of Mexico (GOM), from shelf to deepwater. The result of this unique study culminated in the compilation of a large and comprehensive database of pertinent petrophysical, geophysical, and drilling data. This database was used to develop a set of suggested best practices for pore-pressure estimation below and around salt bodies. An analysis of the wells in the subsalt JIP indicated that the majority (64%) of the wells studied demonstrated evidence of a subsalt gouge or rubble zone. Sufficient data for this analysis was obtained from 87 JIP wells. Statistical analysis of this large database allowed a wide range of correlations to be established for the subsalt rubble-zone occurrence with salt body structural and geological features. An early diagnostic of rubble zones using logging while drilling (LWD) tools can trigger certain drilling practices to be employed.

This paper presents the diagnostic criteria for a subsalt rubble zone and several other confirmatory criteria. The diagnostic identification for a subsalt rubble zone is small-scale discordance between the gamma ray and the resistivity log in the interval immediately below the salt. The relationship between rubble-zone occurrence and salinity changes is discussed.

Drilling subsalt rubble zones can be challenging. This paper documents current industry methods for drilling subsalt wells based on the analysis of multiple sources of data. In addition to the subsalt database, data was compiled from an industry questionnaire designed to capture current practices for drilling subsalt wells, a survey and reviews on subsalt drilling-related published literature, and personal interviews with industry professionals.

This paper focuses on the following key subsalt (with and without a rubble zone) drilling issues of interest to well-construction professionals: the drilling window, casing setting, loss of circulation, wellbore stability, mud-weight scenarios, and leakoff tests. Highlights of each of the aforementioned drilling issues are presented along with well examples.
A Dynamic Imaging Particle Analysis System for Real-Time Analysis of Drilling Muds
Authors: Brown Lew , Duplisea Matthew , Bowen Steve
Published: June 2014

This paper details a novel new system for real-time analysis of drilling muds. The system uses in-flow digital imaging to capture images of all particulates in drilling mud. Sophisticated image processing algorithms are used in real time to segment each particle from the background, and record over 30 size, shape and gray-scale measurements for each particle. Particle size and shape distributions are produced in real-time, and are used for trend analysis.

This system can be integrated into any part of the drilling flow loop for analysis at any point in the process. Using a unique auto-dilution system, the concentration is automatically adjusted for optimum presentation of the particulates to the imaging system. Since every particle image and its measurements are saved by the system, it creates an ironclad audit trail for how particle size distributions are derived.

While the basic system architecture is very robust and could be used in many different applications, the system presented here has been fully optimized for the analysis of particulates in drilling mud.

Real-world data collected in the field is shown illustrating typical results from the system. A brief description is provided on how the system works in real-time, including how the particle images are acquired and measurements made. Finally the results of the analysis are shown, detailing how the system can be used to monitor particle size and shape distributions from any part of the flow loop. This resulting analytical data becomes an integral part of the real-time operation of the drilling platform, ensuring continuous optimization of the drilling mud particulate content. This optimization is critical to the performance of the drilling mud, for cooling and lubrication of the drill bit, interacting with the surrounding geology and maintaining proper rheological characteristics.

This system represents a new way of proactively monitoring drilling mud content in real-time, and provides more information than prior systems because the system can measure particle size as well as shape. Particle shape information can be used by the system software to automatically classify particulates into different component types.
Modeling Wellbore Transient Fluid-Temperature and -Pressure During Diagnostic Fracture Injection Testing in Unconventional Reservoirs
Authors: Nojabaei B. , Hasan A. R. , Kabir C. S.
Published: June 2014

Diagnostic fracture injection testing or DFIT has gained widespread usage in the evaluation of unconventional reservoirs. The DFIT entails injection of water above the formation-parting pressure, followed by a long-duration pressure falloff test. This test is a pragmatic way of gaining critical reservoir information, such as the formation-parting pressure, fracture-closure pressure, and initial-reservoir pressure, leading to fracture-completion design and reservoir-engineering calculations.

In typical field operations, pressure is measured at the wellhead, not at the bottomhole, because of cost considerations. The bottomhole pressure (BHP) is obtained by simply adding a constant hydrostatic head of the water column to the wellhead pressure (WHP) at each timestep. Questions arise whether this practice is sound because of significant changes in temperature that occur in the wellbore, leading to changes in density and compressibility throughout the fluid column. The paper explores this question and offers an analytical model for estimating the transient temperature at a given depth and timestep for computing the BHP. Furthermore, based on the premise of line-source well, we showed that the early-time data can be represented by the square-root of time formulation, leading to the new modified-Hall relation for the injection period.
The Development of a Geopolymer-Based Pill as an Engineered Solution to Lost Circulation
Authors: Miller Matthew L. , Scorsone Jason T. , Whitfill Donald L. , McDonald Michael , Miller Neil
Published: June 2014

Lost circulation is a common and highly varied drilling challenge. Whole fluid loss can be the result of entry into a highly permeable zone, vugular formation, or natural or induced fracture. Losses are further impacted by variables such as engineering practices, wellbore conditions, type of fluid (drilling, completion, cement, etc.) and formation properties. A variety of materials and techniques have been developed to stop lost circulation and stabilize the wellbore. One of the more common fluid solutions is the use of a dedicated pill formulation. These technologies may be comprised of particulate and/or fibrous material that is completely inert, or may be a chemically reactive solution that is triggered to form a sealant throughout the thief zone. Historically, these pills have proven highly effective, but most function under a narrow set of conditions. Another technical limitation for the materials used as a pill treatment is lack of structural integrity (strength) and a reduced tolerance to higher temperatures.

This paper presents a comprehensive summary of the development of a new type of chemically reactive pill based on aqueous alkali alumino silicate as the key component. The aqueous alumino silicate is a low molecular weight, low viscosity solution that is sometimes referred to as a "geopolymer". Set times can range from several minutes to several hours based on the type and concentration of setting agent. By controlling the type, size and quantity of particulate material in the chemically reactive pill formulation, properties such as density, temperature resistance, strength and flexibility can be regulated to suit a wide range of lost circulation challenges.

Models were developed on factors affecting set times, as well as properties of the uncured and cured formulas. These results are utilized to design a lost circulation pill that could be easily pumped through a bottomhole assembly over a wide range of loss rates and downhole conditions. The alumino silicate pill can provide strength properties approaching those of cement with a corresponding tolerance of high downhole temperatures. The environmental characteristics of the system and the economics of its application are also presented.
Production Gains through Reuse of Frac Fluids for Hydraulic Fracturing: A 10-Year Study
Authors: Monroe S. , McCracken D. , Dawson K. , Mouallem S.
Published: June 2014

The rapid expansion in the use of hydraulic fracturing to unlock unconventional hydrocarbons over the last five years has created significant challenges in the management of water. The US Environmental Protection Agency (EPA) estimates that 3.3 billion barrels of water were used in 2010 for fracturing in North America. Costs associated with the management of water, from sourcing through disposal, have been estimated to comprise as much as 15% of the overall cost of a well (Slutz et al. 2012).

Reuse of produced and flowback water to reduce costs has been an area of focus within the industry, but has yet to become the standard practice. While cost-effective technical solutions exist to treat these waters for reuse as an alternative to fresh water, a more fundamental question remains: What is the long-term impact on production by changing from the accepted practice of freshwater use to the use of produced water for hydraulic fracturing?

This paper details a 10-year production analysis from a 48-well project completed in 2001 (Gupta and Hildek 2009). Comparing results using fresh water against those using flowback water for hydraulic fracturing suggests that reuse results in better initial production as well as equivalent production over 10 years.
Mangala Well and Reservoir Mangement: The Journey to 150,000bopd
Authors: Kumar Verma Sumil , Prasad Dhruva , Tandon Rohit , Kumar Pankaj , Kumar Singh Aditya
Published: June 2014

The Mangala field in the Rajasthan state of western India was the first major oil discovery in the Barmer Basin having a STOIIP of over 1.3 billion barrels in multiple stacked fluvial clastic reservoirs. It contains medium gravity (20-28 °API), waxy, viscous crude (9-17 cp) in high permeability (1-25 Darcy) clean sandstone reservoirs. Mangala field is on production since 2009 and is currently producing at 150k bopd.

The field has a comprehensive reservoir Management plan (RMP). As per the RMP, an active reservoir surveillance plan of data acquisition and analysis is being continuously executed in the field. The key data acquisition included Pressure surveys, Production and injection logging, well and network modeling, Reservoir saturation logging, Interference testing, well & artificial lift parameters.

Several challenges and production and injection problems were identified and were addressed in a step wise manner. The well and reservoir performance for ∼ 2 years suggested higher production capacity. Detailed well modeling and surface network modeling was carried out and it was seen that after the installation of Artificial lift, the ongoing production enhancement efforts, continuous reservoir surveillance and management, the field had capacity to produce at a plateau rate of 150k bopd. Simulation studies suggested no detrimental effects on the ultimate recovery.

The plateau rate of the field was increased from approved FDP rate of 125k to 150k bopd, after due approvals and the field has been producing at this rate since April 2012. This paper presents the summary of:

Data acquired during the production phase of 125k bopd Major problems identified in the field and there mitigation Well and Network Modeling Study History of field post plateau rates of 150k bopd. Challenges being faced to maintain 150k bopd
A Successful Trial of Special Downhole Completion for Optimizing Injection Profile in a Highly Fractured Horizontal Well
Authors: Al-Abdulmohsin Yousif A. , Al-Mosa Muhanad A. , Al-Jandal Ahmed A. , AL-Ghafli Hashem A. , Al-Mulhem Abdullah , Kamal Ramy , El-Tonsy Mohamed
Published: June 2014

Uniform injection profile is a reservoir management goal for better sweep efficiency and uniform flood front displacement. Natural and thermal induced fractures in tight reservoirs are difficult to avoid, especially when drilling horizontal wells. Evolving well completion technology has introduced several completion types to delay premature breakthrough by isolating fractures in horizontal wells. In the targeted area where tight rocks and natural fractures exist, several of these completion technologies have been tested on horizontal oil and water wells.

This paper will detail a recent successful trial of a special downhole completion design that provides improved capability for controlling fluid distribution in highly fractured horizontal wells. Also, it will provide information on the reservoir performance after full implementation of this design. The completion design integrates two field proven technologies, inflow control device (ICD) and inflow control valve (ICV) technologies, for maximum reservoir management and control. This unique design was specially tailored to suit a well case in the largest onshore oil field in Saudi Arabia. The primary objective of this completion is to achieve formation compartmentalization and fracture control and isolation in very heterogeneous formations. The completion is also designed to provide intervention capability for future coiled tubing (CT) operations to stimulate or isolate any well section. This functionality will ensure maximum completion performance to achieve even fluid distribution into the induced thermal and natural fractures, thereby optimizing injection profile along the well path, especially for seawater flooding wells.
Environmental Risk Arising From Well Construction Failure: Difference Between Barrier and Well Failure, and Estimates of Failure Frequency Across Common Well Types, Locations and Well Age
Authors: King George E. , King Daniel E.
Published: June 2014

Do oil and gas wells leak to the environment? The great majority of wells do not pollute. The purpose of this paper is to explain basic concepts of well construction and illustrate differences between single barrier failure in multiple barrier well design and outright well integrity failure that could lead to pollution, using published investigations and reviews from data sets of over 600,000 wells worldwide. For US wells, while individual barrier failures (containment maintained and no pollution indicated) in a specific well group may range from very low to several percent (depending on geographical area, operator, era, well type and maintenance quality), actual well integrity failures are very rare. Well integrity failure is where all barriers fail and a leak is possible. True well integrity failure rates are two to three orders of magnitude lower than single barrier failure rates.

When a series of barriers fail and a leak path is formed, gas is the most common fluid lost. Common leak points are failed gaskets or valves at the surface and are easily and quickly repaired. If the failure is subsurface, an outward leak is uncommon due to lower pressure gradient in the well than in outside formations. Subsurface leaks in oil wells are rare and are routinely exterior formation salt water leaking into the well towards the lower pressure in the well.

Failure frequency numbers are estimated for wells in several specific sets of environmental conditions (location, geologic strata, produced fluid composition, soils, etc.). Accuracy of these numbers depends on a sufficient database of wells with documented failures, divided into: 1) barrier failures in a multiple barrier system that do not create pollution, and 2) well integrity failures that create a leak path, whether or not pollution is created. Estimated failure frequency is only for a specific set of wells operating under the same conditions with similar design and construction quality. Well age and era of construction are variables. There is absolutely no one-size-fits-all well failure frequency.
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

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

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

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

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

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

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

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

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

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

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

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.
Engineering Analysis of Coiled Tubing Failure in a Gas Well with Hydrate Plugging
Authors: Hamid Saad
Published: June 2014

Failures provide an opportunity to revisit the existing practices and make necessary improvements in the way operations are designed and executed. Hydrate plug formation in certain operating conditions pose a well-recognized operational hazard. Water can form solid crystalline structure around gas molecules when favorable conditions exist. Very few hydrate formation incidents have been reported in open literature hence limiting the understanding of this subject.

One such incident occurred in Northern Alberta where a coiled tubing string became stuck due to hydrate plug formation in the well bore. Although the coiled tubing operations have become increasingly safer yet the challenging production environment results in greater intervention risks than ever. Coiled tubing failures occurring as a result of operating in these conditions enable us to learn valuable lessons which must be shared with the industry to raise general awareness and reduce industry-wide failures. During this operation, coiled tubing was run for retrieving bridge plug in a 3400m (11155ft) gas well. Restrictions were encountered during the operation, however; coiled tubing safely reached the desired depth. The plug was retrieved successfully but the coiled tubing became stuck close to surface. The pipe was freed up after several attempts and pulled inside the riser section. It was discovered that the pipe had been catastrophically buckled after the risers were opened on surface.

The paper evaluates different failure scenarios in an attempt to analyze the factors that may have been responsible for pipe failure in the given operating conditions while describing the engineering analysis, investigation conducted and lessons learned from it. The paper gives an insight into hydrate prevention techniques in order to avoid stuck pipe conditions hence preventing failures during intervention operations.
The Long Gestation of a Small, Stranded Gas Discovery in the Dutch Sector, North Sea
Authors: Coghlan G. , Westera D. , Ritzema K.
Published: June 2014

F3-FA field is a small offshore gas field in the Dutch sector of the Southern North Sea. The discovery well drilled in 1971 located rich gas in the Jurassic Scruff Greensand Formation. Its constrained size meant field appraisal did not take place for a further decade with two wells drilled in 1982.

Following appraisal, the field struggled to compete for investment capital against other development opportunities and also for pipeline access. Ultimately the original operator exited the field in 2008 - Centrica Energy purchased its equity and field operatorship.

A different opportunity set allowed Centrica and its partner EBN to advance the field development. Uncertainty regarding the dynamic performance of the field and a recognition of limited volumes and therefore producing field life led to the adoption of a Self-Installing Platform (SIP). The platform is a first of its kind at this scale, being the largest mobile production gas platform, 133 meters high and slightly heavier than the Eiffel Tower and designed for re-use on another location to produce some other small accumulation.

The platform was installed in 2010 with full processing and compression facilities in place, tied into the NOGAT pipeline system. Production is from a single, near-horizontal production well. The reliance on a single development well reflected the marginal nature of the development with a range of reserves that reflected uncertainty about the dynamic behaviour of the reservoir that did not have the luxury of any analogues to draw on.

First production was achieved in 2011 and to date the field has performed strongly with no indication of aquifer influx which was an uncertainty going into development. Condensate yield proved much higher than anticipated.

The prolonged time between exploration and first production is a familiar trait for many small developments of recent years in the Southern North Sea, often executed by a new breed of operator. It is also typical of the choices needed to bring such fields to production given modest reserves and unresolvable subsurface uncertainties.
New Insights into Drilling Dynamics through High-Frequency Vibration Measurement and Modeling
Authors: Oueslati Hatem , Jain Jayesh R. , Reckmann Hanno , Ledgerwood L. W. , Pessier Rolf , Chandrasekaran Sridharan
Published: June 2014

Dynamic instabilities of the bottomhole assembly (BHA) such as whirl, stick/slip, and bit bounce have been the focus of the majority of research studies in drilling vibrations. Recently, elevated levels of high-frequency rotational vibrations were recorded in the field with a high-bandwidth downhole vibration monitoring device. New experimental and numerical insights into this relatively unexplored phenomenon of high-frequency torsional oscillations are presented and discussed in this paper.

A suite of laboratory and field tests were conducted to understand and characterize the phenomenon. Computer modeling with in-house drillstring dynamics software corroborated well with the field measurements and validated the research team approach.

The investigation concluded that the drilling process excites BHA torsional vibrations. These vibrations occur at much higher frequencies than drill collar resonance and are significantly dependent on the drilled formation. New insights are gained into drilling dynamics in general and high-frequency torsional oscillations in particular.

The paper presents worldwide field case studies to illustrate the phenomenon. Details are provided of testing where the drilling environment is strategically controlled to characterize the dependence of these high-frequency torsional oscillations on bit design, operating parameters, and formation properties. The implications on drilling performance are also discussed in an attempt to satisfy the quest for efficient and reliable drilling.