bluuebunny/crossref_metadata_2025 huggingface dataset:
Existence of Flow Barriers Improves Horizontal Well Production in Bottom Water Reservoirs
Authors: Zhang Peng , Wen Xian-Huan , Ge Lizhen , Li Bo , Yang Qinghong , Lan Lichuan , Zhou Dengen , Liao Xinwu , Zhang Fengli , Wei Michael S.
Published: September 2008

In developing heavy oil from thin bottom water reservoirs, horizontal wells are mostly used in Bohai Bay, China. To maximize oil production and avoid early water coning/cresting, horizontal wells are usually placed near the top of pay sands and wells are initially produced with small pressure drawdown. However, the production responses from different wells display significant variations even though they are operated under similar conditions. Some wells show premature water coning and rapid water cut rising although high quality sands are targeted, while others show much delayed water breakthrough and slower water cut increases.

A series of reservoir simulations have been conducted to investigate the observed differences. The simulation results reveal that the existence of thin low permeable flow barriers with limited lateral extension/continuity between the wellbore and water/oil contact plays the most crucial role impacting the water coning characteristics. Wells with such flow barriers display later water breakthrough with steady increase of water cut after breakthrough, while wells without such barriers show quick water coning with water cut reaching more than 90% rapidly. The existence of low permeability barriers between the water/oil contact and horizontal wells could slow down water coning and result in much favorable production performance. This phenomenon is then verified by simulations and actual field data from QHD32-6 field. The accurate predictions of production performance rely on the knowledge of physical distribution of flow barriers relative to the wellbore location. In practice, lateral thin flow barriers are usually at sub-seismic scales, and thus hard to identify for a green field. However, for infill drilling in mature fields with many vertical wells drilled, it is possible to predict/correlate the spatial distribution of such flow barriers from the logs of existing wells. Based on such analysis, we can optimize the locations of horizontal infill wells to make full use of the flow barriers for improving production.

A number of horizontal infill wells were optimized and drilled in QHD32-6 field, Bohai Bay, China after identifying flow barriers from the nearby vertical wells. These wells display good production performance having significant higher oil production with delayed water breakthrough and slower increase of water cut.
Analysis of Multiphase Production through Hilly Terrian Pipelines in Matzen Field—Austria by CFD
Authors: Ragab A. , Brandstaetter W. , Ruthammer G. , Shalaby S.
Published: September 2008

Oilfield production pipelines follow normal hilly terrain variations including horizontal, uphill and downhill sections. Therefore, in the same pipeline it is possible to find several types of flow regimes at the same time at different position along the pipeline. Most of the possible flow regimes are not dangerous except slug flow. The slug flow is the most problematic flow regime since this may pose serious problems to the designer and operator of multiphase flow lines and production facilities.

In this work, simulation of a full scale field pipeline is presented using Computational Fluid Dynamics (CFD) and the Volume of Fluid (VOF) method as a surface tracking model. The aim of the study was to investigate the type of flow regimes existing in Ma-VI pipeline system of Matzen field in Austria. A comparative study for different pipeline diameters has been performed and finds an optimum pipe diameter. The transient flow behaviour occurring in a pipeline with two different diameters has been simulated. Since the pipeline under consideration is nearly 2 Km long, the corresponding computational models would involve grid cells with very large aspect ratios which invariably would lead to solution instabilities in the CFD analysis. So, the pipeline system was sub-divided into different sections, and each section was investigated separately. Transient boundary conditions have been prescribed and the respective flow pattern, liquid-gas volume fraction and pressure drop have been estimated.

The results show that the liquid slugs do not maintain a constant length along each section and the dissipation of slugging in up-hill sections mainly depends on the length, the angle and the diameter of the next downhill section. Various slug characteristics such as slug length, slug frequency, slug velocity and pressure drop have been studied and the computed liquid hold-up has been compared with eight correlations from literature. The ultimate aim of this work was to gain a deeper understanding of multiphase flow phenomena in pipeline systems and to develop guidelines to improve the design of pipelines and separation facilities.
Continual Advancement of Casing-While-Drilling Technology
Authors: Guna Shanmuganathan , Won Shao Wang (Keith) , Tan Ming Zao
Published: September 2008

A world record was created when drilling the longest and deepest 13 3/8-in. casing with drill shoe on one of Talisman Malaysia's offshore wells during March 2007. Meticulous planning and job execution for this casing-while-drilling operation were also essential in achieving this significant milestone.

The goals when using casing drilling technology include the reduction of "flat" time (such as nonproductive time [NPT] and time for reaming and wiper trips) and the resolution of potential problems to achieve overall savings in well construction costs. Drilling with casing (DwC™) technology uses the casing string as the drill string, drilling down the hole with a drillable bit. The bit is left in the hole after reaching the targeted depth. The cementing process can take place without tripping out the assembly. Eliminating the casing installation process helps reduce flat time and saves significant rig costs, especially important for operators when they consider the high daily costs associated with offshore rigs.

DS 2 drill shoe is the cement-in-place casing drilling bit which is drillable by all other bit types. It is specially designed for drilling a soft formation with confined compressive strength lower than 7,000 psi. The success of Talisman Malaysia's record-breaking offshore project opened up a new frontier for the DS 2 drill shoe's capabilities when combined with DwC technology.

This paper will briefly examine and visually display the planning and implementation process, as well as the results of the longest and deepest 13 3/8-in. casing drilling well in the world to date.
Recent Advances in Surfactant EOR
Authors: Hirasaki George J. , Miller Clarence A. , Puerto Maura
Published: September 2008

Recent advances in surfactant EOR are reviewed. The addition of alkali to surfactant flooding in the 1980s reduced the amount of surfactant required and the process became known as alkaline surfactant polymer flooding (ASP). It was recently found that the adsorption of anionic surfactants on calcite and dolomite can also be significantly reduced with sodium carbonate as the alkali, thus making the process applicable for carbonate formations. The same chemicals are also capable of altering the wettability of carbonate formations from strongly oil-wet to preferentially water-wet. This wettability alteration in combination with ultra-low interfacial tension (IFT) makes it possible to displace oil from preferentially oil-wet carbonate matrix to fractures by oil-water gravity drainage.

The alkaline surfactant process co-injects alkali and synthetic surfactant. The alkali generates soap in situ by reaction between the alkali and naphthenic acids in the crude oil. It was recently recognized that the local ratio of soap/surfactant determines the local optimal salinity for minimum IFT. Recognition of this dependence makes it possible to design a strategy to maximize oil recovery with the least amount of surfactant and inject polymer with the surfactant without phase separation. An additional benefit of the presence of the soap component is that it generates an oil-rich colloidal dispersion which produces ultra-low IFT over a much wider range of salinity than in its absence.

It was once thought that a co-solvent such as alcohol was necessary to make a microemulsion without gel-like phases or a polymer-rich phase separating from the surfactant solution. An example of an alternative to the use of alcohol is to blend two dissimilar surfactants, a branched alkoxylated sulfate and a double-tailed, internal olefin sulfonate. The single phase region with NaCl or CaCl2 is greater for the blend than for either surfactant alone. It is also possible to incorporate polymer into such aqueous surfactant solutions without phase separation under some conditions. The injected surfactant solution has under-optimum phase behavior with the crude oil. It becomes optimum only as it mixes with the in situ generated soap, which is generally more hydrophobic than the injected surfactant. However, some crude oils do not have a sufficiently high acid number for this approach to work.

Foam can be used for mobility control by alternating slugs of gas with slugs of surfactant solution. Besides effective oil displacement in a homogeneous sandpack, it demonstrated greatly improved sweep in a layered sandpack.
The Use of the Industry's First 3-D Mechanical Caliper Image While Drilling Leads to Optimized Rotary-Steerable Assemblies in Push- and Point-the-Bit Configurations
Authors: Sugiura Junichi , Jones Steve
Published: September 2008

It has been widely recognized that poor hole quality causes tight borehole, packing off, high torque/drag, stick-slip, degraded logging-while-drilling (LWD) and wireline log quality, unpredictable directional performance, and consequently problematic casing runs. Conventionally, borehole quality is monitored with LWD standoff caliper logs and caliper images. In wireline application, multi-arm mechanical calipers are used to create such logs. Until today, it is believed that the use of such equipment is the only way to detect 3-D borehole problems, such as borehole oscillation.

This paper presents the industry's first 2-D and 3-D mechanical caliper image while drilling and back-reaming with rotary-steerable systems (RSS). The near-bit mechanical caliper integrated into the specific RSS1,2,3 takes measurements 4 ft from the bit in push-the-bit configuration and 7 ft from the bit in point-the-bit configuration. This pad-contact mechanical caliper provides both real-time and memory-based caliper images.

The advantage of this new type of near-bit caliper measurement is that the sensor measures borehole geometry right at the bit as compared to 50-100 feet behind the bit with conventional LWD sensors. Borehole washout, for example, does not necessarily occur at the bit, but could be caused by string stabilizers far away from the bit. The ability to detect borehole washout in real-time helps the operator take immediate corrective action while drilling to maintain borehole integrity since near-bit washout often affects the steerability of RSS.

In this paper, 2-D and 3-D near-bit caliper logs are extensively examined from different RSS assemblies and bits. The downhole data were gathered through controlled non-commercial field tests, as well as commercial runs. Frequency analysis using the discrete Fourier transform is also applied to the depth-based caliper images to identify the BHA and borehole oscillation issues. The effect of bit selection, stabilizer size/profile/geometry, and spacing on borehole quality is analyzed using the 2-D and 3-D near-bit caliper logs. As a result, this new sensor information helped to improve the RSS assembly performance and resulted in optimized BHAs in both push- and point-the-bit configurations for superior steerability, stability and borehole quality.
Development of Heavy Oil Fractured Carbonate Bati Raman Field: Evaluation of Steam Injection Potential and Improving Ongoing CO2 Injection
Authors: Babadagli T. , Sahin S. , Kalfa U. , Celebioglu D. , Karabakal U. , Topguder N. N.
Published: September 2008

With 1.85 MMM bbl OOIP, the Bati Raman field is the largest oil field in Turkey. After its discovery in 1961, the field was put on stream for primary production until 1986. The recovery factor was only 2% after twenty five year production mainly due to low oil gravity. The well-known immiscible CO2 flooding project commenced in 1986, and the recovery factor reached 5% at the end of 2007.

The recent steady decline in production entails the implementation of new development plans and this paper summarizes these efforts. After reviewing the performance of the current CO2 injection, short and long term development strategies were discussed. Short term plans include the continuation of the CO2 project in the areas where it is still viable. Some parts of the field are under WAG process. To improve the recovery in the short run by a better sweep (or displacement), a chemically augmented water injection process was proposed in those areas. Potential chemicals (surfactants and alkalis) were tested for wettability alteration and IFT reduction applying static (spontaneous) imbibition experiments. The best performing chemicals were determined for the field pilot after an economic analysis. In addition, the possibility of steam injection into the field was evaluated for the long run. Due to extreme heterogeneity and fractured structure, crestal steam injection that uses steam as heating rather than a displacement agent was proposed. An analytical study for the optimization of steam injection was provided.

To determine the locations for the above listed processes, an extensive reservoir characterization study was performed using dynamic and very limited static -well- data. Using well recorded primary (1961-1986) and CO2 production data (1986-2007), fracture swarms were mapped. In this process, the changes in the initial production rate and GOR over different time periods were considered. The quickest decline in the initial rate and the lowest GOR areas correspond to highly fractured regions. Highly -vertically- fractured areas (typically the crest) were determined for potential steam injection. This analysis also helped detect high quality matrix areas as candidates for chemically augmented WAG.
Advanced Compositional Gradient Analysis
Authors: Cañas Jesús , Pop Julian , Dubost Francois , Elshahawi Hani
Published: September 2008

Steep gradients are common in gas condensate and volatile oil reservoirs, but they are also present in heavy oils reservoirs. There are numerous publications (Creek, 1985, Lars Høier, 2000, Montel, 2002, Firoozabadi, 1999, Ghorayeb, 2003, Fujisawa, 2004, Elshahawi, 2005, and Kabir, 2006) that have dealt with complex fluid columns showing compositional gradients for columns in thermodynamic equilibrium or under steady state conditions. Montel et al. (2002) discuss processes that arise from recent charging of these reservoirs, which are not in equilibrium but still undergoing for instance a flux of the light components that diffuse.

Formation testers supply a wealth of information to observe and predict the state of fluids in petroleum reservoirs, through detailed pressure and fluid analysis measurements. With the correct understanding of fluid characteristics in the reservoir, reserve calculations and adequate development plans can be prepared. Additionally, flow barriers may then be revealed, as across such barriers, fluid may appear different. In order to test for the existence of such barriers, pressure or fluid differences, in their context must be assessed. Formation tester data must therefore be treated by means of a systematic analysis, so that different sources of information lead to an integrated, preferably, consistent conclusion. Downhole fluid analysis in conjunction with pressure gradient analysis is simultaneously analyzed to reflect and make deductions concerning the correct state of fluids in complex fluid columns. As part of the process, different reservoirs need to be well delineated through appropriate statistical similarity tests of pressure gradients and fluid analysis of the different zones (Kabir, 2006).

In this paper, a novel methodology is presented to account for non-linearity in pressure gradients due to varying fluid density. We examine two field cases in which compositional gradients were observed with both downhole fluid analysis measurements and pressure gradients. An equation of state model is used to describe the fluid column according to a simple fluid equilibrium model. A non-linear pressure gradient regression fit is also examined. The choice and appropriateness of the pressure gradient model that accounts for the observed fluid density changes observed. The result of the modelled fluid and pressure analisis are compared to actual downhole measurements of the pressure profile and insitu fluid logs. In particular, pressures and densities calculated from the multiple sources of information, pressure and fluids, are compared to direct actual measurements. The reservoir architecture is revealed. For both cases, the fluid column is continuous through the hydrocarbon intervals down to the water-oil contacts. Flow barrier locations would be found on the basis of anomalies and departures of the measured data from the modelled pressure and fluid gradients.
Integrated Fracture and Production Modeling Study in the Lower Cotton Valley Sands, Northern Louisiana
Authors: Lolon E. P. , Mayerhofer M. J. , Garcia I. , Durey D. A. , Byrd A. C. , Rhodes R. D.
Published: September 2008

The Lower Cotton Valley (LCV) sands in northern Louisian are a complex reservoir system consisting of multiple, low permeability layers. In this area, wells are hydraulically fractured to achieve economic gas production. However, due to the high-stress environment, fracturing pressures are typically very high, in most cases close to or above overburden stress. This presents significant challenges for stimulation effectiveness.

This paper discusses well performance evaluations and possible answers as to why wells are not performing as expected. Possible causes of wells exhibiting steep production declines within the first few months after completion and solutions to improve well performance and well completions as well as field development strategies are addressed. The results of fracture modeling and detailed single-well production modeling are presented.

All wells in the study area show evidence of damaged hydraulic fractures. Potential damage mechanisms are discussed including high production drawdowns and large effective stresses on the proppant in conjunction with high temperature, fracture complexity, dipping fractures, and formation collapse.
Counter-Diffusion and Competitive Adsorption Effects During CO2 Injection and Coalbed Methane Production
Authors: Fathi Ebrahim , Akkutlu I. Yucel
Published: September 2008

Previous investigations have shown that carbon dioxide injection and enhanced coalbed methane production (CO2-ECBM) involves several viscous and diffusive transport mechanisms, raising challenging questions related to the chemically and structurally intricate nature of coalbeds. Injection of gas in a network of natural fractures initiates counter-diffusive transport and competitive (and often selective) sorption processes among the gas molecules in coal. Consequently, the incoming CO2 molecules activate and displace the in-place CH4 molecules. Competitive sorption rates, however, could be controlled by the counter-diffusive mass fluxes during the gas injection and production operations. Nature of the multi-component diffusive transport processes should therefore be understood clearly. In this paper, we develop a new one-dimensional theoretical framework suitable for a fundamental level investigation of binary gas storage and transport in coal seams considering a serial multi-continuum porous medium with triple porosity and dual permeability. Total pore volume is due to micro- and macropores and due to a high-density fracture network. Macropores and fractures are characterized by their own effective uniform permeability fields; hence, they are continua for fast viscous/diffusive transport of the free gas. Micropores, on the other hand, are primary pores retaining the bulk of the gas in-place at an adsorbed state. Resistence in the micropores is due to surface diffusion of the adsorbed binary mixture. The generalized Maxwell-Stefan formulation of multi-component transport is revisited and extended to describe gas behavior in bimodal (micro- and macro-) pore structures. We first show that the widely used single-component Langmuir gas behavior is, in fact, a limiting case of the generalized form. The latter includes not only the anticipated binary effects (due to the existence of two components with different molecular size and adsorption capacity) but also additional nonlinear effects due to the direction of diffusive mass fluxes and to the lateral interactions of the adsorbed gas molecules in the micropores. Following, we incorporate the multi-component formulation to a reservoir flow model to consider CO2-ECBM process in between an injector/producer pair. Dynamics of sequestration and production is then investigated varying initial/boundary conditions. It is shown that the counter diffusion and competitive adsorption effects in the micropores could generate nontrivial effects at the reservoir-scale such that methane production is significantly enhanced. The investigation is important for our understanding and the design of CO2-ECBM processes.
Characterization of Oil Water Flows in Inclined Pipes
Authors: Atmaca S. , Sarica C. , Zhang H. -Q. , Al-Sarkhi A. S.
Published: September 2008

The flow of oil-water for different inclination angles (0°, ±1°, ±2° and -5°) was studied through the analysis of high-quality experimental data on flow pattern, pressure gradients, water holdup and phase distribution (Atmaca (2007). A total of 324 tests were conducted in a 0.0508-m. ID 21.1 m. long, inclinable test section using tap water and mineral oil (with a density of 0.85 gr/cm3 and viscosity of 15 cp) with superficial velocities ranging from 0.025 m/s to 1.75 m/s.

Oil-water flow in the petroleum industry is a common occurrence during production and transportation of gas-oil-water in pipes. Facilities design is strongly dependent on the flow behavior. The specific applications include design and troubleshooting of flow lines and wells, separator design, interpretation of production logs, etc.

Non-intrusive high-speed camera technique was used to determine the flow patterns at various conditions. Experimental flow pattern maps were compared against Trallero (1995) and Zhang and Sarica (2006) models. Trallero model predicted the most flow pattern boundaries well except stratified flow pattern. For most of the cases, the pressure gradients were over predicted by the Zhang and Sarica model. Quick closing valves are used for holdup measurements giving phase slippage information. For the low superficial velocities, slippage behavior was observed very clearly for upward and downward flow. For the high superficial velocities, slippage effects were diminished. Representative phase distributions, and interface boundaries were observed for different flow conditions by examining conductivity probe data.

This paper provides significant insight in phase distribution and slippage behavior. The results presented in this study are applicable not only to oil-water flow but also to three-phase gas-oil-water flow models.
A Mixing Rule of Self-Diffusivities in Methane Hydrocarbon Mixtures and the Determination of GOR and Oil Viscosities from NMR Log Data
Authors: Chen Jiansheng , Chen Songhua
Published: September 2008

A new mixing rule is described for the prediction of the self-diffusivities of gas and liquid hydrocarbon molecules in methane-oil mixtures. Unlike macroscopic fluid properties such as density and viscosity, molecule self-diffusivity is a microscopic parameter associated with individual molecule species. Thus, a self-diffusivity of a binary mixture of gas and oil is non-existent. Instead, the self-diffusivity of each species in the binary system is affected by presence of the other species. For that reason, the commonly used log-mean based mixing rule that applies to macroscopic properties of the mixtures is unsuitable for self-diffusivity when the reference states are pure Component 1 and pure Component 2. We found that it is necessary to introduce two new reference states: one is the infinite dilution of Component 1 in Component 2; the other is the infinite dilution of Component 2 in Component 1. The component can be a single-molecule species or a mixture; as long as its self-diffusivity or self-diffusivity distribution can be measured. Using this approach, the self-diffusivity of each component in the mixture follows the log-mean based mixing rule. This new mixing rule is verified with literature data of methane-hexane, ethane-hexane, methane-octane, ethane-octane, methane-decane, and ethane-decane mixtures over a wide range of temperatures, pressures, and solution gas concentrations.

The new mixing rule is applied, and a detailed procedure is developed, to determine the Gas Oil Ratio (GOR) and the live-oil viscosity for in-situ volatile oils from NMR log data. First, the self-diffusivities and proton fraction of the methane and oil mixture are determined by fitting the NMR-measured diffusivity distribution with a bi-modal distribution. Then, the self-diffusivities for the four reference states are calculated using the mixing rule. Finally, the GOR is calculated from the proton ratio; while the live-oil viscosity is calculated from the self-diffusivity of pure oil and GOR. The calculated GOR and oil viscosities are compared with the PVT measurement of the oil sample taken from downhole and show good agreement. GOR and oil viscosities from this new technique can be used for optimizing testing and sampling programs, for reservoir stimulation studies, and for the design of surface production facilities.
Design, Implementation and Operation of an Advanced Collaborative Environment for Enhanced Performance in Tangguh Drilling and Completions
Authors: Pickering J. G. , Cavanagh D. , Allen S. , Hanneman A. , Bennett C. , Ananta D. , Whiteley N.
Published: September 2008

The Tangguh Project in West Papua Province, Indonesia represents significant challenges in terms of drilling conditions, extreme remoteness, and social and environmental sensitivity. The Tangguh Drilling "Advanced Collaborative Environment" (ACE) was designed to enhance drilling performance and safety. Very positive results were achieved within the first months of the drilling operation. This paper describes the design approach, implementation and subsequent operational experience of the Tangguh Drilling ACE. A number of features of this ACE have since become exemplars for BP's drilling operations globally.

The two-rig Tangguh development drilling campaign of 15 wells faced particularly difficult challenges with total losses, high vibration and the extreme remoteness of a location two timezones ahead of the office. To enhance drilling performance, an ACE was developed based on BP's global design principles covering people, process, technology, physical environment and organisation. The ACE connects each rigsite drilling team to the BP office in Jakarta and the onshore supply base. Real time drilling data in WITSML (Wellsite Information Transfer Standard Markup Language) format and high quality video conferencing were essential components to support the Wellsite Leader in the execution of the drilling plan.

Tangguh drilling commenced in May 2007 with a successful 10 months of field operations. The Wells Manager attributed a significant part of this success to ACE and associated working practices. The drilling ACE made a significant contribution towards reducing the recovery period from major non-productive time incidents and has promoted better connectivity between rigsite and office. This has improved teamwork and the sharing of information. It is consistent with BP's goal for Field of the Future™, "Better Decisions Faster".

Critical to the success of the ACE was engagement and ownership by the Wellsite Leaders and drilling operations management. Significant organisational and interface challenges were overcome, including applying vendor neutral data standards between different service companies. This was a first for Indonesia. A number of other firsts were achieved also:- First BP drilling ACE designed specifically for performance enhancement.First BP multi-rig drilling ACE.First drilling ACE in BP using full time high quality video conferencing over satellite and wireless broadband.
Improved Gridding Technique for Coupling Geomechanics to Reservoir Flow
Authors: Tran David , Buchanan Lloyd , Nghiem Long
Published: September 2008

The application of geomechanics in reservoir flow simulation has increased substantially since it was recognized that the modeling of geomechanical effects was necessary to predict important phenomena such as compaction, subsidence, wellbore failure, etc. However, its application is strongly limited due to the use of a one-grid system for both reservoir flow and geomechanics deformation. In the case of a large field-scale simulation, the use of a one-grid system gives rise to an extremely large number of gridblocks. On one hand, for an accurate modeling of fluid flow, the gridblocks need to be reasonably small around wells and sharp fronts. Yet, these small gridblocks may not be essential for geomechanics computations. On the other hand, accurate geomechanics calculations may require many gridblocks in the overburden, underburden and sideburden (country rock) that are not necessary for fluid flow. In this work, a separate-grid technique is combined with an iterative coupling method to resolve the above problem. In this separate-grid technique, the reservoir flow grid and the geomechanics grid are distinct in order to model efficiently both fluid flow phenomena and geomechanics deformations. A method to couple the two grid systems is described. The use of this grid coupling approach reduces the simulation run time substantially with results that are very close to the one-grid method. A series of examples illustrating the application of this two-grid concept and the corresponding run-time reduction are described.
Fracture Ballooning in Naturally Fractured Formations: Mechanism and Controlling Factors
Authors: Majidi R. , Miska S. Z. , Yu M. , Thompson L. G.
Published: September 2008

Fracture ballooning observed while drilling naturally fractured formations has often been mistakenly interpreted as influx of formation fluid or the loss of drilling fluids. This misinterpretation leads to costly well control procedures that may make the situation even worse. The main mechanisms and factors controlling the ballooning phenomenon must be well understood to avoid confusing this phenomenon with conventional losses or formation kick. Amongst several mechanisms that are quoted for borehole ballooning, the opening/ closing of natural fractures plays a major role in naturally fractured formations.

In this work, a mathematical model describing the fracture ballooning process is developed and solved numerically using finite difference approximation. The governing equation is derived using principles of conservation of mass and linear momentum for transient radial flow in a single fracture. The effects of fracture parameters (aperture, extension and deformability) have been studied as well as fluid properties and operational conditions. Describing drilling fluid rheology with Yield-Power-Law (Herschel-Bulkley/YPL) allows for the investigation of the effect of drilling fluid rheology on borehole ballooning.

Results show how the rheological properties of drilling fluid such as yield stress and shear-thinning/thickening effect, influence ballooning or mud losses in fractured formations. We conclude that the fluid loss in the fractures could be stopped either because of high yield stress of drilling fluid or limited extension of the fracture. The proposed model is also helpful for detecting and treating ballooning as well as evaluating fracture characteristics. The field potential application of the model is described.
Case History: Expanding the Boundaries of a Hydraulic Workover Unit into New Economic Levels
Authors: Attong D. , Robertson D. , Wyatt M. , Perai S. , Persad S. , Joseph K. , Garcia J. F. , Fleary C.
Published: September 2008

A 600K Hydraulic Workover (HWO) Unit has proven that it has the capability to safely access and deliver offshore gas reserves. This paper identifies the business environment, challenges, learnings, results and the key success factors of a three (3) well project that delivered a total of 250 million standard cubic feet per day (mmsfcd) using a 600K HWO unit. The primary result of the project demonstrated the capability of the HWO unit in handling challenges previously thought better suited for conventional larger rigs. HWO units have proven to be particularly effective in bpTT's offshore operations, however their application had been limited to tubing changeouts, workovers, oil recompletions and short oil sidetracks. This project expanded the capability of the 600K HWO unit to perform high rate uphole gas recompletions. The project consisted of three uphole gas recompletions in 9-5/8 inch casing. Each recompletion was executed at approximately $0.50/barrel of oil equivalent (boe) which made the project extremely attractive and made gas reserves economically viable. Completing the same work with a larger Jackup unit would have cost $3 -4/boe clearly showcasing the economic advantage of the HWO unit. Another major advantage was the ability to move the HWO unit in unfavourable weather conditions when compared to a Jack Up rig. Weather conditions can result in significant and costly delays during the December – April period for jack up units.
New Steel Tooth Cutting Structure Breaks Multiple Records in Australasia
Authors: Bunton Steve , Sim Natalie , Grimes Bobby
Published: September 2008

Approximately 90% of the large diameter holes in Australasia (Indonesia, Australia, PNG and New Zealand) are drilled with steel tooth roller cone bits. A new steel tooth bit design has proven to significantly improve the drilling economics in these applications. This paper describes the drilling challenges posed by these applications, details the new bit design features, and presents case studies showing the performance improvements these new bits provide when compared with conventional steel tooth bits.

The new design bits feature a novel cutting structure with pyramid-shaped teeth, additional rows of teeth, wide grooves between rows, anti-tracking row(s) with tight pitches, thick hardfacing deposits, and a bar trimmer type gauge design. The result is a steel tooth bit that delivers significantly higher ROP and longer life than current designs, with high reliability, and predictable steering behavior for directional applications. Hole sections can often be completed with fewer bits, which further improves drilling economics. These bits achieve ROPs faster than even that of large diameter PDC bits in the Australasian applications, thus the reason that steel tooth bits are primarily used.

An operator in Balikpapan, Indonesia drilled a long S-shaped hole with a new 17 1/2-in. steel tooth bit at 40% higher ROP than the best of nine direct offsets that were drilled with conventional steel tooth bits. Another operator offshore Western Australia conducted a head-to-head comparison of a new 16-in. steel tooth bit against a conventional steel tooth bit in identical hole sections. The new bit drilled over 70% faster and over 25% farther than the regular bit. A third operator in the Northwest Shelf area off Western Australia employed a new 17 ½-in. steel tooth bit to complete a section normally drilled with 12 ¼-in. PDC bits. The new steel tooth bit drilled over 25% faster than the fastest PDC offset run. Additional case studies will be presented further documenting these positive field results.
Avoid Downhole Explosions, Buckled Pipe and Parted Tubing During Snubbing Operations
Authors: Duncan Grant J.
Published: September 2008

Snubbing involves the running of tubing and related completion equipment into a well while pressure is present at the wellhead. This operation requires the use of specialized equipment that provides control of well pressure and associated fluids at all times, and enables the movement of tubulars and equipment into and out of the well.

Petro-Canada chose to create their own snubbing guidelines, and share them with industry, because of situations being encountered that were not adequately described in published recommendations and regulations. The Petro-Canada Snubbing Guidelines are intended to compliment, rather than replace, Industry Recommended Practices on snubbing.

Petro-Canada's Snubbing Guidelines contain the following information: Written guidelines, providing information on snubbing and well control equipment, safety requirements, snubbing procedures, and contingent operations.A procedure for preventing downhole explosions when pulling plugs.Pipe buckling calculations, as related to wellbore pressure.Allowable tensile loads, as a function of internal and external pressures.A snubbing operations checklist.

This paper addresses i) avoiding downhole explosions, ii) preventing pipe buckling in pipe-light situations, and iii) allowable tensile loads as a function of internal and external pressures.
Oil-Based Foam and Proper Underbalanced-Drilling Practices Improve Drilling Efficiency in a Deep Gulf Coast Well
Authors: Sepulveda J. J. , Falana O. M. , Kakadjian S. , Morales J. D. , Zamora F. , Dibiasio M. A. , Marshall E. , Shirley G. , Benoit D. J. , Tkach S. A.
Published: September 2008

A recyclable oil-based foam drilling fluid (OBFDF) system has been developed to expand the benefits of controlled pressure drilling with foam onto water sensitive formations. This paper describes chemical development and presents drilling results for a Gulf Coast well drilled with the oil-based foam system. Not only did results confirm the ability of the foam system to control fluid loss and preserve formation permeability, but also, show the advantages of drilling with foam. Furthermore, a bit trip was saved drilling the reservoir in a single bit run, with a high rate of penetration and reduced gas inflow while drilling. The OBFDF is versatile, stable at high temperature (up to 450°F), compatible with H2S scavengers and reusable. Foam properties were successfully adjusted in presence of gas and condensate inflow. Still, the flexibility of foaming, defoaming and refoaming allowed surface separation and fluids reuse. Therefore, recycling liquid make up hydrocarbon reduced fluids and chemical usage with the associated cost reduction. Onsite modeling showed the controlled pressure contractor modeling software used for water-based foams can be adjusted to properly predict drilling parameters with oil-based foams.
Overcoming Challenges during the Development and Installation of Intelligent Completion Systems in SRI Wells
Authors: Joseph Paul , Going Walter , Eriksen Frank , Hughes Baker , Vinje Lars , Berland Helge
Published: September 2008

In this age of multi-zone and multilateral wells, existing technologies are always challenged to achieve desired results. In the case of Statoil Skinfaks/Rimfaks (SRI) wells, capabilities of intelligent completion systems were stretched to the limit. Some of the challenges included depth, system optimization, feedback monitoring, subsea logic, placement of downhole hydraulic logic switches, hydraulic timing, cross flow design due to limited control lines, development of an auxiliary logic switch, etc. Operational requirements also pushed downhole tools like the flow control valves and logic switches in a novel and previously untried configuration. System operation logic mandated the design of a very complex hydraulic circuit.

Cross flow design with limited control lines proved to be a significant challenge. Each of the wells had three zones to be controlled. The existing subsea trees allowed only three hydraulic control lines. Three balanced piston flow control valves normally require at least four control lines to be operated. A new system was to be developed to be able to control all three balanced piston valves with only three hydraulic control lines.

This paper will present how a combination of analytical modeling, simulation and laboratory testing was used to overcome these and other design challenges during the system development phase. This novel methodology will aid the optimization and reduction in design cycle time of future intelligent completion systems. Four wells in the Statoil Skinfaks/Rimfaks Improved Oil Recovery Project were completed with intelligent systems in 2007. Thorough planning and execution yielded higher operational efficiency which resulted in job completion ahead of schedule. The installation phase will be discussed in the paper with special emphasis on pre-job planning, operational procedures, post-job results and lessons learned.
Polymer Flood Modeling Using Streamlines—Part 1
Authors: Thiele M. R. , Batycky R. P. , Pöllitzer S. , Clemens T.
Published: September 2008

The successful design of a polymer flood relies on the ability to properly model the distribution of polymer concentration in the reservoir while accounting for effects on fluid properties such as water viscosity increases as a function of in-situ polymer concentration and loss of polymer due to adsorption. Despite advances in numerical techniques and computer hardware, the numerical modeling of polymer floods using Eulerian-based approaches such as finite differences remains a challenge: coarse grids tend to excessively smear concentration fronts masking the true benefit of polymers, yet introducing finer grids inevitably leads to excessive run times that make using modern reservoir engineering workflows unrealistic. This problem was already outlined in 1978 by Lake et al.. We revisit the same problem 30 years later in the context of modern streamline simulation techniques.

In this work, we present the extension of modern streamline simulation to field-scale polymer flooding, which represents a step-change from the hybrid, 2D steady-state models used in the 1970's. We apply the well-established numerical modeling of polymer flooding to captured the displacement efficiency in 1D, and couple it with a three-dimensional (3D) streamline simulator to efficiently capture the inter-pattern sweep efficiency caused by well rate imbalances, reservoir architecture, and reservoir heterogeneity. Because modern 3D streamline simulators account for changing well rates, non-uniform initial conditions, and gravity, adding polymer functionality means that real-field polymer floods can be modeled with sufficient confidence to be useful and with the necessary speed to be used for modern reservoir engineering workflows that center on assessing uncertainty and risk associated with design parameters.

In this paper we proceed to outline the basic architecture of a streamline simulator with a polymer option. We discuss streamline-specific issues, such as the data that must be exchanged between the Lagrangian streamline grid and the underlying Eulerian grid to allow streamlines to be updated as production/injection conditions change. We discuss advantages and disadvantages of the formulation and present numerical experiments in 1D, 2D, and 3D to illustrate our results.
Erosion Study for a 400 MMcf/D Completion: Cannonball Field, Offshore Trinidad
Authors: Healy J. C. , Martin John , McLaury Brenton , Jagroop Raynald
Published: September 2008

The Cannonball Field is a one Tcf gas condensate development offshore Trinidad producing at a sustained rate in excess of 800 MMcf/D from three wells. The completion design selected was 7⅝ inch production tubing with an open-hole gravel pack. The initial well (CAN01) has produced at 333 MMcf/D. These rates are higher than typically experienced which has raised concerns concerns about the resultant potential for metal erosion. As a result, a rigorous erosion study was initiated. The objective was to quantitatively evaluate erosion at various rates over the life cycle of the well to appropriately design the completion and select the appropriate materials.

The erosion nodes within the completion - changes in flow direction (e.g. a tee such as in the wellhead) and/or flow constrictions - were identified as: the tree; a landing nipple profile near the surface; and a formation isolation device (FID) positioned in the gravel pack assembly. The key parameters were defined as particles of sharp sand, with a diameter of 50 microns, at a concentration of 0.1 lbs/MMcf. Erosion rates were calculated using the erosion model - Sand Production Pipe Saver (SPPS) - developed by the Erosion/Corrosion Research Center, University of Tulsa, USA. Erosion rates were calculated over the life cycle starting at initial rates of 280 and 400 MMcf/D. Erosion rates were also calculated with and without a liquid film (a protective layer on the pipe wall that can reduce the erosion rate). Erosion results (without a liquid film) at all nodes exceeded BP's erosion limit; however, the erosion results with a thin liquid film were mostly below the company's erosion limit. Determination of the presence and thickness of the liquid film was critical. A multi-phase pipeline simulation calculated that a sufficient liquid film would exist at all critical areas. Erosion of the tree was further assessed by computation fluid dynamics (CFD) models, which identified several hot spots; thus, additional cladding of all flow-wetted surfaces and rounding of the outlet corner was required. The Cannonball completion design, including the tree, was determined to be capable of sustained rates up to a maximum 400 MMcf/D. The three (3) well development, where initial rates have been as high as 333 MMcf/D, has been on production for several years without any erosion issues.
Prediction Onset and Dynamic Behaviour of Liquid Loading Gas Wells
Authors: Belfroid S. P. C. , Schiferli W. , Alberts G. J. N. , Veeken C. A. M. , Biezen E.
Published: September 2008

As reservoir pressures decrease in maturing gas wells, liquid drop-out forms an increasing restriction on gas production. Even though virtually all of the world's gas wells are either at risk of or suffering from liquid loading, the modeling of liquid loading behavior is still quite immature and the prediction of the minimum stable gas rate not very reliable. Many wells start liquid loading at gas rates well above the values predicted by classic steady state prediction models such as Turner. The loading point is strongly dependent on inclination angle, flow regime transitions and the interaction between tubing outflow behavior and the reservoir IPR. In the paper, the behavior of different natural gas wells and of an air-water test setup are analyzed. Simulations were performed using both commercially available software and dedicated dynamic models. The onset of liquid loading and the dynamic behavior of a flooded well during a restart were predicted. These were then compared to actual production data. The influence of the reservoir parameters and of the tube inclination were of special interest.

The influence of dynamic disturbances on the stability are not taken into account by the classic prediction models. Systems with high permeable reservoirs are less able to cope with disturbances. This leads to higher critical rates for those systems. This corresponds to data from field observations. A maximum in the critical velocity is observed around an inclination of 50° with a critical rate 40% higher than for a vertical well. To solve this, relations found from flooding experiments are used to modify the current prediction models. Based on the current work an adaptation to the Turner equation, which takes the inclination effects into account, is proposed. For the observed natural gas wells and for the air-water experiments the modified Turner equation predicts the observed loading points within 20% accuracy.