bluuebunny/crossref_metadata_2025 huggingface dataset:
Integrated Reservoir Study of Shushufindi Field – Dynamic Modeling
Authors: Ohen Henry A. , Erian Adel , Ali Liaqat , Guzman Daniel , Guerrero Olga , Ochoa José , Valdivieso Luis
Published: December 2007

Shushufindi is the largest field in the Oriente Basin of Ecuador that was discovered by Texaco in 1970. It has produced about one billion barrels of oil over a period of 30 years. Early in the life of the field, peripheral water injection was implemented and was discontinued in 1999 based on the results of a previous reservoir simulation study carried out in late 90’s. Currently, the field is producing significant amount of water under very active water drive mechanism. The field consists of three main stacked reservoirs: Basal Tena, U and T and have produced from about 185 completions. This paper is focused on the reservoirs U and T. Historically, most of the wells in the field were produced commingled from these two reservoirs. This paper presents the results of an integrated reservoir study that was performed to optimize the field performance for effective reservoir management.

A 3D reservoir simulation model was constructed to optimize the performance of the field and to find opportunities to increase oil production. A successful history match achieved helped understanding the reservoir behavior and field performance. Since many wells produced commingled from the reservoirs U and T, dynamic fluid allocation was also performed by means of full-field history matching process. Distribution and location of remaining oil after accounting for the incremental oil recovery due to the workover wells helped delineating the locations of infill and step-out wells to increase production.

The results showed that reservoir pressure behavior was very erratic in both U and T reservoirs. However, the level of scatter was more pronounced in Reservoir U than in Reservoir T. Observed reservoir pressure trends seem to follow the channels observed from 2D seismic especially in reservoir U. However, local changes in the pressure trends could have been caused by the water injection. Some observations from the reservoir performance evaluation suggest that the erratic pressure behavior could also be attributed to the change in the formation compressibility due to fluid withdrawal and water injection.

The results also show that the effect of peripheral water injection was very limited and infill water injection could improve sweep efficiency of the reservoirs.
Measured Z-Factor of CO2–Dry Gas/Wet Gas/Gas Condensates for CO2 Storage in Depleted Gas Reservoirs
Authors: Adisoemarta P. S. , Frailey S. M. , Lawal A. S.
Published: December 2007

In support of the research project at the Center for Applied Petrophysical and Reservoir Studies in geologic storage of carbon dioxide in depleted gas reservoirs, the PVT laboratory at Texas Tech University performed compressibility factor (z-factor) measurements at various composition of CO2 with hydrocarbon (HC) gas mixture. For the sole purpose of the measured Z-factor data, three temperatures of 100°F, 160°F and 220°F and pressures ranges from 50 psia to 5000 psia are selected as representative of the depleted gas reservoirs (DGRs). In order to analyze the various phase behavior to be encountered in gas reservoirs (dry gas, wet gas and retrograde gas), the median gas compositions for dry, wet and retrograde gases are specified by gas type. The gas types are categorized by representative compositional analysis for the three types of gas reservoirs (dry gas, wet gas and retrograde gas). The measurements of z-factors for CO2-hydrocarbon mixtures in varying proportions and at the three specified temperatures for various pressures are performed on the median gas compositions of the type gases. The results of the z-factor measurements of CO2-hydrocarbon mixtures are used to interpret the expected phase behavior to be encountered in the geologic storage of CO2 in gas reservoirs. Also, the z-factor measurements of CO2-retrograde gas mixtures are used to quality the benefits of enhanced gas and condensate recovery in gas reservoirs.
Coiled Tubing Erosion During Hydraulic Fracturing Slurry Flow
Authors: Shah S. N. , Jain S. , Zhou Y.
Published: December 2007

The pumping of fracturing slurry through coiled and straight tubing can cause considerable wear of tubing and is an issue of industrial concern, both from safety and economic considerations. In hydraulic fracturing operations employing coiled tubing, the tubing wall is affected by non-uniform erosion for the section of the tubing spooled on the reel. The non-uniform wall erosion is caused by the centrifugal forces when pumping sand slurries at high rates. In spite of the large number of fracturing jobs performed in the industry today, research in this area of investigating and evaluating erosion has been limited.

This paper discusses the erosion phenomena and the mechanisms leading to the erosion process. The factors affecting erosion such as pump rate, slurry concentration, and fluid properties are investigated. Newtonian (water) and non-Newtonian (fracturing gel and slurry) fluids have been investigated. The results from the Computational Fluid Dynamics (CFD) simulations for the flow of these fluids in straight as well as coiled tubing are provided. The velocity profiles and sand concentration profiles for each case are presented which provide insight into the particle migration/segregation phenomenon associated with the erosion process. It is found that the fluid properties, flow velocity, and sand concentration all have major influence on the erosion process.

The future plans for the experimental study to understand the erosion in coiled tubing are also presented.
Finite Element Analysis of Coiled Tubing Forces
Authors: Newman Kenneth R
Published: December 2007

This paper will discuss a purpose written fully 3D Finite Element Analysis (FEA) model which analyzes the bending of pipe inside a wellbore. The yielding and residual curvature of CT can be included in this model. The model is also able to calculate the onset of buckling. This paper presents the equations and methodology used in the development of the model. Results from the model are compared with analytical solutions currently in use. Examples studies performed with the model are presented. .
Reverse Circulation With Coiled Tubing - Results of 1600+ Jobs
Authors: Charlie Michel , Rodney Stephens , David Smith , Walter Crow , King George E.
Published: December 2007

Reverse circulation has always been viewed with some level of suspicion and reverse circulation with coiled tubing has often been avoided at all costs. Yet, results of over 1600 CT operations involving reverse circulating in Alaska's oil fields, with just a handful of failures, has proven reverse circulation to be a reliable procedure for a specific range of solids removal that is extremely effective in removing sand fill from wells with very large tubulars and in high deviations. Results from North Sea, Colombia, California and the US GoM are also included. This paper presents the basics of reverse circulation designed specifically for coiled tubing; including necessary surface equipment, BHA nozzle design, pump requirements, fluid rates, and procedures to reduce the potential for problems. The procedures and job overviews contained here were contributed during an ICOTA panel discussion on reverse circulating, held September 18, 2003, in Houston, TX.
IRISS – Intervention Riser Integrity and Safety System
Authors: Newman Kenneth R. , Rodney Stephens
Published: December 2007

This paper describes a system for monitoring the maximum stresses in an intervention wellhead, BOP lubricator/riser, and injector structure. In some offshore cases the wellhead itself may be moving, causing stresses in the intervention structure. In other cases the injector support system may allow some side-to-side movement, causing stresses in the structure. This system measures the bending moment, bending direction, axial load and internal pressure at one or more points in the structure. A real-time finite element analysis is then performed by the system to determine the maximum stress in the structure. The system displays the bending moment, bending direction, axial force, and internal pressure to the operator. It also displays the maximum stresses along the length of the structure, and warns the operator when the stresses exceed a safety limit. This paper describes the development and testing of this system.
Predicting Coiled-Tubing Failure Below Injector
Authors: Zheng Andrew S. , Adnan Sarmad
Published: December 2007

With the increased use of coiled tubing in high-pressure wells, the collapse of coiled tubing between the injector and the stripper has received much attention recently. In high-pressure wells, the failure of this tubing section (typically less than 2 ft in length) usually occurs under the combined loadings of axial compression and internal pressure. Previous analytical models to predict failure under such loading conditions have focused mostly on the buckling behavior of the short coiled-tubing section with minor modification of yield strength to account for the effect of internal pressure. Such approaches underestimate the effect of internal pressure on the collapse failure, especially for higher internal pressure.

In this paper, a new analytical model is developed to predict the collapse of short coiled tubing under the combined loadings of axial compression and internal pressure. The analytical model first analyzes the buckling load of the short coiled-tubing section under axial compression only, and the burst pressure of the coiled tubing under internal pressure only, respectively. Then an interaction failure criterion is used to model the failure locus of the short coiled tubing under the combined loadings of axial compression and internal pressure. Experimental data are used to validate this new model.
Dynamic Excitation Tool: Developmental Testing and CTD Field Case Histories
Authors: Robertson L. , Mason C. J. , Sherwood A. S. , Newman K. R.
Published: December 2007

Weight transfer and helical buckling eventually leading to lock up is an issue that the industry has had to deal with since the outset of the use of coiled tubing. Limitations imposed by this restriction have reduced the number of available applications that can be carried out. The use of larger sizes, improved materials combined with friction reducers and better modelling techniques have gone a long way to understand and extend these limits.

This paper reviews a new dynamic excitation tool, which reduces frictional drag and therefore adds to available options for further extending limits and capabilities of coiled tubing.

The paper follows the tools history from developmental testing in Norway and subsequent successful Coiled Tubing Drilling (CTD) field trials in Alaska.

Results of reverse friction factor modelling are included and parameters that affect the tools ability to create dynamic excitation are also discussed.
Some "Firsts" In Coiled Tubing Inspection
Authors: Stanley Roderic K.
Published: December 2007

Nondestructive evaluation (NDE) of new and in-service CT is leading to higher quality (conformance to specifications), the driver being high pressure, high temperature service work. This paper outlines a number of "firsts" in NDE that have occurred at Quality Tubing. We have installed and operated an electromagnetic strip inspection device and removed many strip surface imperfections, and a phased-array ultrasound (PAUT) system for weld-seam/heat-affected zone (HAZ) inspection of new tubing for the detection of typical seam anomalies. In order to inspect butt-welds quickly and without radiation, we are investigating the use of ultrasound, and have also procedurized bias weld and seam weld prove-up procedures using UT. Further, we have "final-inspected" (i.e. NDE after hydrostatic test) numerous strings for many coiled line pipe (CLP) projects, and more recently "high-exposure" coiled tubing projects such as Sakhalin, Thunderhorse projects.

For used materials, we have NDE-inspected for cement plugs, weld locations, and typical used-tubing defects, and have assisted in the determination of API derating criteria for in-service materials.

Recently, an untethered robot, capable of inspecting CLP/CT has emerged, and is introduced here.
Real-Time Data Delivery in Coiled-Tubing Well Interventions
Authors: Cabanzo Luis Eduardo , Zhou Wei
Published: December 2007

The application of information technology (IT) tools in the exploration and production industry has extended and enhanced conventional oilfield practices by promoting better communication and technical collaboration between expert personnel and the wellsite. Effective, real-time data delivery has become a key component in improving knowledge sharing, the time-to-decision process, and performance in well interventions.

As the coiled-tubing (CT) industry expands, more-effective communication with the wellsite becomes critical to facilitating successful operations. The availability of job data allows evaluation of the design and its execution as the job progresses; optimization of the treatment; and the making of more accurate, informed decisions during the course of the operation to improve the overall execution and reduce operational costs.

CT operations have shown a significant process-improvement trend and better project economics as a result of real-time supported operations. This paper discusses the concept of real-time supported CT operations and the use of data delivery to improve decision-making in the CT industry, outlines the technology and interface involved in the data-delivery system, details the specifications required to meet the data-transfer definition, and demonstrates its target application and potential impact in the CT industry.
Inflatable Packers in Extreme Environments
Authors: Wilson Stuart , Erkol Zafer , Faugere Aude , Eatwell Bill , Espinosa Frank , Xu Ron
Published: December 2007

Inflatable packers are ideal for through-tubing zonal isolation, but they are rarely used in extreme environments because of the assumed risk of failure. High pressures, high temperatures, high expansion ratios, and chemical resilience are particular challenges. This paper reports on three recent case histories that demonstrate inflatable packer technology can be used in several of these "harsh" wellbore conditions.

The first case history describes a high-pressure cement squeeze job using a 2 1/8-in. packer with an expansion ratio larger than 3:1. The objective was to run the packer through a 2.313-in. restriction and set in 7 5/8-in. casing to permanently shut off a lower water zone before perforating higher in the well. The second study involves an inflatable packer used in conjunction with a butyl acetate furan resin for sand consolidation. The furan resin is known to be extremely detrimental to elastomers, so a full-scale simulation under given wellbore conditions was conducted to demonstrate its compatibility with the packer. The resin was utilized as a screenless sand-control solution that allowed fullbore production. The final case history involves pumping of a viscoelastic acid-diverting treatment fluid, used for matrix stimulation under high-pressure, high-temperature conditions. Used in carbonate formations, the fluid is ideally suited for total zonal coverage matrix simulation and high temperatures. When a through-tubing inflatable packer is used as a treating packer, individual long producing zones can be fully isolated and evenly stimulated.
Experimental Study of Aerated Mud Flows under Horizontal Borehole Conditions
Authors: Zhou L. , Ahmed R. M. , Miska S. Z. , Takach N. E. , Yu M. , Pickell M. B.
Published: December 2007

Extensive aerated mud experiments were performed in a unique field-scale elevated pressure and elevated temperature flow loop (6″ × 3.5″ annular test section, 73 ft length, horizontal configuration without drillpipe rotation). A view port was installed to observe flow patterns in the test section. Two nuclear densitometers were used to measure steady state mean void fraction. During test runs, the liquid and gas phase flow rates were in the range of 50-250 gal/min and 50-150 scf/min, respectively. For all the test runs, measurements of pressure drop and average liquid holdup over the entire annular section were carried out.

The two-phase flow patterns were identified by visual observations through the view port. Stratified and slug flow were the two flow patterns observed over the range of the chosen test matrix. The presence of slug flow does not justify many existing simulation practices, which assume a homogeneous gas-liquid flow.

A mechanistic model has been developed for aerated mud hydraulics based on conservation equations and existing two-phase pipe flow correlations. An extensive sensitivity analysis is presented to quantify the influence of mud properties and flow parameters on the bottom-hole pressure. Comparisons between the predictions of the model and experimental measurements show a satisfactory agreement. The present model is particularly suitable for the design of underbalanced coiled tubing applications.
Hydraulics As It Affects Our Tools – The Inflatable Paradox
Authors: Mackenzie Gordon R J , Patterson Andrew E
Published: December 2007

One of the fundamental things we are taught as part of our industry training is how to calculate pressures as they interact with our systems and tools. Any number of training materials have been produced for us both in-house and externally to better understand the concepts of pressure. The tool service providers will provide pressure rating guidelines to allow their end users to very precisely define the limitations of pressure across their intervention devices. In the strictly mechanical arena the calculation of allowable differential pressures, both in terms of pressure reductions (such as drawdown) or applied pressure (such as testing) is a relatively simple process following the basic principles of what we have been taught. The mechanical solution supplies us with a very two dimensional platform on which we have to base our calculations. The paradox comes when the same age old, tried and tested principles are attempted to be utilized when dealing with an inflatable solution to the well operation. A new third dimension is introduced whereby not only must pressure differentials across the device itself be considered, but also differences from the inside of the inflatable element to the outside of the element must be analyzed. One of the biggest precursors to the success of planning an inflatable operation is the understanding and acceptance of this third dimension pressure characteristic and its application to not only the performance of the inflatable tool when the operation is being conducted, but in the case of long term deployments, its performance throughout the cycles of the well while the inflatable element is in situ. This paper will attempt to describe and explain in detail the differences in calculation methods required across inflatable type packing elements and highlight these differences in such a way as to inform as to the criticality of getting these calculations correct and applying them to both the planning and implementation stage of both temporary and long term inflatable isolations.
New Technologies Allow Small Coiled Tubing to Complete the Work Formerly Reserved for Large Coiled Tubing Units
Authors: Portman Lance
Published: December 2007

Coiled tubing has been used as a well intervention tool since the early 1960's. Since its introduction, the diameter of coiled tubing available has steadily increased, driven by demands for higher flow rates as well as larger push and pull forces. However, bigger coiled tubing sizes require larger equipment and in many cases, the simple physical size of the equipment becomes unworkable, particularly for offshore applications.

Some of the most common reasons for not using coiled tubing are:-

The platform and/or platform crane is not big enough for coil tubing size thought to be required. The available or manageable coiled tubing size cannot access the bottom of the well. Insufficient pull or push is available using the available or manageable coiled tubing size. The low fluid rates achievable through the available coiled tubing make the job time too great.

This paper addresses each of the above arguments put forward against the use of coiled tubing. The paper shows how advances in technology have, to a large extent, removed these perceived barriers, most notably for the most common coiled tubing activities, these being fill cleanouts, gas lifting and acidizing/stimulation. Several technologies have emerged recently that enable small, light coiled tubing units to be used where previously larger units were thought necessary.
Field Launch of a Safer, More-Efficient Coiled-Tubing Unit in North Sea for Valhall Stimulations
Authors: Andreassen T. , Langeteig B. , Amaravadi S. , Mallalieu R. , Polsky Y.
Published: December 2007

Safety and efficiency have always been the primary performance measures in the coiled-tubing (CT) industry. This paper describes the feasibility study, development objectives, field test, and launch of a new-generation CT unit in the Norwegian sector of the North Sea. This automated, modular system with its distributed system architecture is designed to improve safety in CT operations, with 15% operational efficiency gain and 30% offshore personnel reduction targeted.

A typical completion on Valhall is a horizontal well completed with 5 to 12 proppant-treated fractures per well in the soft chalk formations. The operations and logistics are complex and involve repeated sequences of perforating with CT, proppant fracture treatment with stimulation vessel, and a combined cleanout/perforating run with CT. On a 24-hour operation offshore, a 13-member crew operate the conventional CT spread comprising the unit, reel, and power stand; well-control equipment; two high-pressure, positivedisplacement pumps; shakers; choke; and a CT tower with the injector head.

The requirements and specifications of the new unit were finalized after a detailed study of operations, platform requirements, and local regulations. Efficiency gains were targeted in the rig-up and rig-down times, and in the overall zone cycle times (operational efficiency). Health, safety, and environmental improvements are achieved by reducing manual handling and lifting operations on board. Distinguishing equipment characteristics are as follows:

Preassembly and integration of components on skids to enable quicker rig-up and reduce manual handling. For example, offshore rig-up typically involves 54 lifts; the new unit cuts this number to 36. Distributed-control architecture to reduce the number of rig-up connections required. For example, the system design allows a total rig-up with only 36 hydraulic connections instead of the usual 84. Ability to run larger and heavier pipe (6,000-m length, 2⅞-in. diameter, 90,000-psi yield) at faster rates enables easier completion of difficult wells and reduces the overall zone-cycle time. It also eliminates handling of friction-reducing chemicals while maintaining cleanout efficiency. Planned reduction in crew through the utilization of automated process control, The benefits of this include the following: ▫ All controls for the choke, shakers, CT unit, and pumps are centralized in the CT unit's control cab. Many equipment controls-related tasks that conventionally were hands-on tasks are performed by the control system to allow the operator to focus on treatment efficiency. ▫ Automated safety features are incorporated into process-control software to reduce safety exposure, particularly in areas prone to human errors. ▫ Cab ergonomics allow the operator to oversee the entire operation and react to any situation quickly and efficiently.
Further Developments for Coiled Tubing Floater Operations
Authors: Lode J. E. , Møller R. , Nesvik K. T. , Buchanan A. , Myklebust J.
Published: December 2007

The number of new subsea-completed wells is increasing rapidly. At the same time, existing subsea field developments are entering more challenging phases of production with wells demanding a higher intervention frequency in order to maintain production and/or increase recoverable reserves. Consequently the demand for performing coiled tubing (CT) interventions in such wells is increasing. As an indication of this trend, one operator in Norway has seen a doubling of CT interventions in subsea wells in 2003 compared to previous years.

Today the most common installations available to perform CT interventions on subsea wells are semisubmersible rigs that are primarily designed for drilling and completion activities. The challenges of interfacing with and performing CT operations from these "semisubmersibles" are well documented (1). Such challenges relate mainly to restricted access and space around the hoisting systems and, even more importantly, to the relative motion (primarily heave) that exists between the "fixed" wellhead/riser and the moving installation.

This paper describes newly introduced equipment and techniques that are now considered field tested to improve coiled tubing, semisubmersible operations by

Reducing personnel exposure to safety hazards Reducing equipment exposure to damage hazards Increasing efficiency and the operational window with respect to heave conditions

Items to be described and discussed in this regard are:

A latest generation lifting frame with integrated stripper crash frame and stabbing guide Revolutionary use of a new slip joint system that effectively cancels out the effect of heave during critical phases of the operations
Coiled-Tubing Drilling Reentry: Case History from East Kalimantan
Authors: Wright H. J. , Aristianto B. , Gan R. G. , Jenie J. R. , Kyaw H. A.
Published: December 2007

As oil and gas developments mature, reservoir depletion reduces field output and fewer opportunities exist to drill new wells. Drilling new wells as the sole means of increasing field production often becomes less profitable, and it presents greater operational risks. Economic risks are also greater as the chance of completing good wells is getting less and the higher capital investment required.

In many fields, operators, either intentionally or unintentionally, bypass pay zones during initial development by focusing only on the best zones. Accessing bypassed thinly laminated formations and low-permeability zones is economically attractive but poses several challenges.

Several techniques were used to achieve sustainable commercial production from the bypassed zones in East Kalimantan. Hydraulic fracturing and underbalanced perforations were tried, with inconsistent results. Drilling new horizontal wells was not economical.

Coiled-tubing (CT) drilling was the solution that provided a cost-effective alternative to the use of a conventional drilling rig. The advantages were a smaller location footprint, shorter trip times, ability to drill underbalanced, competitive rates of penetration, and through-tubing reentry.

Because only a few CT drilling campaigns have achieved both operational and production successes, a campaign was proposed that used conventional well design and drilling programs. Previous lessons learned worldwide were used to reduce the drilling risk and enhance the chance of success. This was especially important in drilling a deviated hole through the coal zone of the subject well.

This paper will describe three wells from the design phase through post-job evaluation. Lessons learned and improvement plans are also incorporated in this paper.
Investigation of Polymeric and Mixed Metal Oxide Fluids for Use in Well Intervention Operations
Authors: Hodder M. , Michel C. , Kellingray D. , Bailey L.
Published: December 2007

This paper describes an investigation into the characteristics of various biopolymer and mixed metal oxide fluids for potential application in well intervention operations. Poor hole cleaning is experienced on many well intervention jobs with coiled tubing and even with hydraulic workover units because of lower circulation rates compared with conventional drilling operations. This can lead to stuck pipe (illustrated by two case histories) and is an expensive problem worldwide. Currently used products are poorly characterised in terms of their viscosity at elevated temperature and at the low shear rates encountered under the pipe in deviated, eccentric annuli.

The investigation involved rheological measurements on xanthan, welan, diutan and scleroglucan polymers on a Bohlin rheometer at shear rates of 0.001–1000 s-1 and temperatures 50-175°C. Two mixed metal oxide fluids were also tested as a comparison. The fluids were tested on a Chan rheometer (with identical geometry to the common Fann 35) to investigate correlations.

These experiments were complimented by hydraulics analysis and by tests to determine the resistance of the various fluids to contamination by cement. A simple suspension test was also performed using material simulating common cuttings produced in well intervention operations.

We also describe the results of treatments designed to break the viscosity of the various fluids prior to flow through the production separators. Finally, a case history is presented of a successful well intervention operation on a high-temperature well using viscous mixed metal oxide pills.
Sajaa Underbalance Coiled Tubing Drilling "Putting It All Together"
Authors: Pruitt Randal , Leslie Charlie , Smith Bruce , Knight Jeff , Buchanan Richard
Published: December 2007

Introduction

Located in the Emirate of Sharjah, United Arab Emirates, the Sajaa onshore gas field is a Thamama limestone reservoir ranging from 11,000 to 13,000 feet true vertical depth (3350 to 3960 meters true vertical depth). The bottomhole temperature is in the 260 to 310 degrees Farenheight (126 to 154 degrees Celcius) with bottomhole pressures of 1100 to 1900 psi (75 to 129 atmospheres). This paper will discuss the process used in basis of design, selection of bidders, pre tender qualifications, underbalance modeling, pre qualification, assurance testing of equipment, initial rig up, two phase nipple milling, window milling and the drilling of the first six wells in the Sajaa Underbalanced Coiled Tubing Drilling project.

Background

In April of 2002 a Production Technical Limit (PTL) meeting reviewed the wells and reservoir and identified the prize of unlocking additional permeability and height to gain additional rate and reserves. The PTL also identified the work required for sub surface evaluation of the reservoir with the basic questions of how much gas is left and where is the gas located. Idea's were then put forward on various options of snub drilling, conventional underbalance drilling as in the 2000 campaign, and coiled tubing drilling. All the options had one thing in common and that was the use of multi lateral wellbores to connect gas zones not fully connected with the vertical well mother bores. Coiled tubing drilling was evaluated as the best choice because of the need for real time directional steering where mud pulse is not possible due to the two phase fluids being pumped down the coil.

In June of 2002 a Peer Assist was held in Sharjah with invited BP quests and distinquished underbalance/CTD/snubbing experts from Alaska, the North Sea, BP Houston's non conventional wells team, Service Company expertise from BP's experts in Colombia and underbalance consulting firms. The result of the three day meeting was a Risk Assessment with the Underbalance Coiled Tubing Drilling. Key areas of risk were:
Monte Carlo Simulation of Vertical Separators Handling a Network of Intermittent Gas Lift Wells
Authors: Caicedo Sergio , Trujillo Militza , Florez Horacio
Published: December 2007

To the present, most of the research concerning separation process has had a deterministic approach because it is oriented to steady state flow regimes. However, this assumption is far away when many artificial Intermittent Gas Lifted (IGL) wells are connected to the same separator. IGL has a FLOW/NO FLOW periodic condition associated with a long accumulation stage and a short production stage lasting about 20 minutes and 1 minute respectively. A stochastic algorithm was developed to simulate the separation process and the periodicity proper of each IGL well along with the unpredictable delay or synchronization between those wells. The simulation couples the dynamic mass balance equations in the separator and the Monte Carlo method for predicting the gas and liquid rates associated with the superposition of the IGL wells. The input parameters for this simulation were the following: daily gas/oil production and cycle time of each well, oil properties, separator's pressure, and temperature as well as the control scheme. The simulator output matched with less than 10% with field data. The results obtained with the approach suggested in this work could be used as new criteria in design, simulation and evaluation of separation facilities under fluctuating conditions.
Screen and Near-Wellbore Cleaning and Stimulation Tools Evaluation: Recent Experience in Well Operation
Authors: Harthy Aziz , Abdulkadir Ramzi , Sipra Iqbal , Saeby Jan , Raiturkar Avadhut , Bailey Michael , Venditto Jim
Published: December 2007

Proposal

Numerous oil-producing wells in Southern Oman are completed with wire wrap screens (WWS), internal gravel packs (IGPs), and predrilled liners. These wells produce from mature clastic formations where fines migration and subsequent blockage of screens can result in impaired oil production. In the past, conventional treatment using coiled tubing and a jetting tool has been chosen to remove this damage. The gains resulting from these intervention activities were more often than not short-lived. This lack of longevity required frequent well intervention and oil deferment, often resulting in a loss of revenue.

Recently, a systematic approach was undertaken to evaluate the wellbore cleaning and stimulation tools that are currently available in the industry. This approach was implemented as a trial of three cleanout tools in oil-producing wells. This paper describes the results of using these tools for cleanout and stimulation of sand screens.

Excellent success was achieved with a pulse-jetting tool operating on the Principles of Coanda effect. This tool is further described in the following sections, and results of its use in a number of oil-producing wells are presented. The effect of the cleanout procedure is presented in terms of initial production and sustainment of production level.
Slick Water and Hybrid Fracs in the Bossier: Some Lessons Learnt
Authors: Sharma Mukul M. , Gadde Phani B. , Sullivan Richard , Sigal Richard , Fielder Robin , Copeland David , Griffin Larry , Weijers Leen
Published: December 2007

In order to better understand the process of fracturing tight gas sands, a comprehensive data set was gathered and analyzed for the Bossier formation in the Dowdy Ranch field. The dataset collected on the APC Anderson #2 well represents one of the most comprehensive datasets ever collected for a commercial gas well. The entire interval was cored, and a complete set of core analysis was performed across the sands. Stress profiles derived from dipole sonic logs across the pay zone and in the shales below were calibrated with stress tests. The frac jobs were micro-seismically monitored with downhole geophones and included breakdown and mini-frac stages. Post fracture data collection included pressure buildup testing, production logs with multiple passes, and tracer logs with multiple isotopes. Additional data was collected on five offset wells in the field. Results from these wells will be presented in a companion paper.

The bottomhole treating pressures were found to be higher than expected based on the measured stress profiles. However, the higher treating pressures encountered did not result in excessive fracture height growth. This may be partially attributed to unexpected faulting providing a conduit for fluid leak-off, resulting in low efficiency and narrow fractures. Propped or effective fracture lengths derived from pressure buildup analysis and history matching production data were significantly shorter than designed frac lengths (or those predicted from uncalibrated frac models). The net pressure plots showed some evidence of proppant bridging even at low proppant concentrations, again indicating only limited fracture widths were being achieved. The data collected and analyzed provide valuable insight into the performance of water and hybrid fracs in tight gas formations. Recommendations for the design of future fracture treatments are made based on the findings.
The Trouble Probability Plot: A New Measure of Drilling Maturity
Authors: Kravis S. , Irrgang R. , Scott P. , Lollback P.
Published: December 2007

Drilling performance is usually benchmarked by analyzing the time spent on well construction and the degree to which planned times and budgets are achieved. Learn curve analysis can provide indicators of relative improvement over a campaign, and position on the learning curve can provide a measure of process maturity. However, the variability of the data makes it difficult to obtain a good fit to the model and assess maturity. The principal cause of the discrepancy between planned and actual times is trouble. Trouble is accounted for in planning by a multiplicative contingency factor. This implies that trouble time is dependent on well or well section length. Based on a standardized analysis of drilling performance for a wide range of wells we find that this assumption is not valid and that trouble time is not significantly correlated with well or well section length. However, we do find that the probability of trouble is significantly correlated with length, and that a probability plot of trouble time for a group of wells or well sections provides a robust measure of drilling process maturity. We present results of applying this analysis to a variety of well types and propose some metrics for assessing drilling process maturity.
Subsea HIPPS: A Way to Develop High-Pressure Subsea Fields
Authors: Patni Sandeep , Davalath Janardhan
Published: December 2007

One of the challenges for the development of high-pressure oil and gas prospects in ultra-deepwater is the high CAPEX cost of subsea flowlines and risers. Installing a High Integrity Pressure Protection System (HIPPS) in the subsea system allows the flowline to be designed to just above well flowing pressure instead of well shut-in pressure. Based on flow simulations, pipeline design and economic analysis, this paper demonstrates that installing subsea HIPPS results in: Lower installed cost of flowlines and risersEarly payback with incrementally higher flow of oil and gasSecondary benefits including higher flowing wellhead and flowline temperatures.

Another important benefit from using subsea HIPPS is that the weight of the risers hanging off at the host facility can be reduced substantially. Otherwise, heavy-walled risers may restrict the tie-in of the deepwater prospect to host facilities.

With pressure decline over time, the thick walled flowlines become an overkill and will tend to restrict the well flow rate. With subsea HIPPS, the larger flow area in the subsea flowlines will allow the field to be abandoned at a lower reservoir pressure. This means that that the total recoverable reserves from the field can be increased. The major finding of this paper is that for high-pressure reservoirs in ultra-deepwater, installing HIPPS subsea accelerates cash flow and increases the project Net Present Value. These benefits will be illustrated based on the analysis of a deepwater field development design case.
Multiphase Well Surveillance with a Permanent Downhole Flowmeter
Authors: Webster M. , Richardson S. , Gabard-Cuoq C. , Fitzgerald J. B. , Stephenson K. E.
Published: December 2007

Flow rate and fluid type (phase) are two of the most fundamental parameters needed in characterizing well performance. Traditional methods of estimating these parameters, particularly for real-time detection and diagnosis of production anomalies, have been limited by sampling frequency and data quality. This paper presents field test results of a new type of downhole multiphase flowmeter, which confirm the value of permanent downhole metering. The meter contains only three sensors but is capable of direct multiphase flow rate and cut measurements without slip models, even in highly deviated, recirculating flow. The physics basis and flow loop tests are discussed.
Field Qualification of Four Multiphase Flowmeters on North Slope, Alaska
Authors: Hasebe Brant , Hall Andrew , Smith Bruce , Brady Jerry , Mehdizadeh Parviz
Published: December 2007

Multiphase metering technology continues to evolve, with significant implications for the oil and gas industry. Current technology is sufficiently capable for some oilfield applications and requires further development for others, particularly low-maintenance measurement of high GVF fluids. This paper discusses a field trial of four commercially available multiphase meters, including the test set-up, meter evaluation criteria, and general conclusions.
A Comparative Study of Mechanical Properties of Density-Reduced Cement Compositions
Authors: Ravi Kris , McMechan David E. , Reddy B. R. , Crook Ron
Published: December 2007

This paper discusses the tests conducted to determine the mechanical properties and the integrity of the cement sheath when subjected to cyclic loads. In addition, lower-density cement systems are discussed in this paper, along with how the density was lowered by incorporating conventional additives such as: Pozzolanic beads (cenosphere)Hollow glass beadsGas bubblesWater-binding additivesSilica fumeFly ash

Primary cementing compositions for oil-well applications are becoming increasingly complex and challenging because of the extremes encountered in well-operating conditions. The stresses exerted on the cement sheath during well operations could be severe enough to damage the cement sheath and negatively affect the safety and the economics of the well.

The results discussed in this paper should help operators design a cement sheath that can withstand the stresses from well operations and thus help improve the safety and economics of the wells.
Optimization of Well Placement with a History Matching Approach
Authors: Özdogan Umut , Roland N. Horne
Published: December 2007

Determining the optimum location of the wells is a critical and crucial decision to be made during a field development plan. The quality of the decision is strongly dependent upon the amount of the information available to the decision-maker at the time the decision is made. Knowing that the development phase of a reservoir is a dynamic period in which different categories of information are added to system from distinct sources, one should make the well placement decisions considering these time-dependent contributions of information. This study proposes an approach that addresses the value of time-dependent information to achieve better decisions in terms of reduced uncertainty and increased probable Net Present Value (NPV). A Hybrid Genetic Algorithm1 (HGA) was used as the optimization method to find the best locations of the wells. A utility framework, that enables the assessment of the uncertainty of the well-placement decisions, was used to find the optimum decisions for different risk attitudes. Through this new approach, production history data obtained from the wells, as they are drilled, are integrated into the well placement decisions. Unlike previous approaches, well placement optimization is coupled with recursive history matching steps. To test the results of the proposed approach, an example reservoir was investigated with multiple realizations, all of which match the history response of the reference. At each step of optimization, a reduction in the uncertainty of the multiple realizations was observed, as production history became available.
Dynamic Reservoir Well Interaction
Authors: Sturm W. L. , Belfroid S. P. C. , van Wolfswinkel O. , Peters M. C. A. M. , Verhelst F. J. P. C. M. G.
Published: December 2007

In order to develop smart well control systems for unstable oil wells, realistic modeling of the dynamics of the well is essential. Most dynamic well models use a semi-steady state inflow model to describe the inflow of oil and gas from the reservoir. On the other hand, reservoir models use steady state lift curves for modeling of the wells. When producing oil from thin oil rims, this description does not sufficiently describe the well behavior observed in practice. For this reason, a model was built that describes both the dynamic flow of oil and gas towards the well bore and the dynamic flow inside the well. The integrated model provides a realistic description of the well dynamics on a time scale of minutes, which is the time scale that is required for development of a control system. As a result, the integrated model allows the development of model based gas coning control or water coning control schemes, as well as model based interpretation of well data.
Hydrate Inhibition in Headers with No Production Flow
Authors: Herrmann B. , Bargas C. , Svedeman S. J. , Buckingham J. C.
Published: December 2007

When deep-water subsea production is shut in for long periods, measures are normally taken to prevent the formation of hydrate blockages in the flowline network. One common inhibition method is to inject methanol into the jumpers, manifold headers, and well bores. This paper presents the result of experiments that were conducted to investigate the distribution of inhibitor injected into a static (no production flow) header or bore that contains oil, water, and gas. The test results were used to help develop a more effective header design and also to shape operating guidelines for inhibiting after shut-in. A test facility was constructed to test various header configurations and production conditions. Tests were conducted to investigate the effect of varying the water cut, gas volume fraction, header inclination angle from horizontal, and the oil density. Experiments also examined the distribution of methanol injected into a vertical well bore.

Results are presented that show the dispersal of oil, water, and gas in the header after shut-in and after injecting inhibitor into the header. In all test cases, uninhibited water remained in the header after methanol injection and no protection was provided against hydrate formation. Either the methanol never came into contact with the water or the diffusion in the static system was so small that the methanol and the water remained segregated.

Test results also show that the maximum amount of inhibitor present in the header after methanol injection depends upon the oil density, header geometry, and the amount of gas trapped in the header. These results can be used to determine the maximum amount of inhibitor that needs to be pumped to inhibit a shut-in header section.

Given the apparent failure of methanol to disperse in such a way as to inhibit water, further tests were run to examine why this common practice of methanol inhibition is successful. These experiments gave some explanation for the success of this procedure and yielded insights to the timing of chemical injection.