bluuebunny/crossref_metadata_2025 huggingface dataset:
Fatigue Life of Coiled Tubing With External Mechanical Damage
Authors: Padron Tomas , Luft Bernard , Kee Emmanuel , Tipton Steve M.
Published: December 2007

Coiled tubing (CT) is used in a rough and dynamic environment that renders it susceptible to mechanical damage on its outer surface. Such damage can adversely affect the fatigue life of CT by causing localized concentration of stresses and strains, or inducing microcracks from severe localized plastic deformation, that can lead to premature fatigue failure of the pipe.

Failure statistics based on detailed failure examinations by BJ Services Company rank mechanical damage as the leading cause of CT failures accounting for 35% of all investigations. Repairs of the damaged pipe by welding or grinding are not always practical or even possible; therefore it is important to be able to estimate the remaining fatigue life of the damaged pipe so that the well servicing job can be completed with minimum risk of failure.

Research efforts by the Coiled Tubing Mechanics Research Consortium at Tulsa University to determine the fatigue de-rating factors for damaged CT produced an algorithm ("Flexor TU4") that can predict the remaining fatigue life of the CT based on specific damage geometry, tubing characteristics and operating parameters. However, the majority of the testing for this algorithm has been conducted in air on artificial defects (i.e. machined) introduced on new and pre-fatigued tubing samples. Little previous research has been conducted to compare "Flexor TU4" predictions with the remaining fatigue life measured on CT with real defects (i.e. damage caused during service). Also, the effect of mechanical damage on the fatigue life of coiled tubing when exposed to sour environments (i.e. H2S) has not yet been reported in the literature.

This paper describes the effect of different types of damage on the material and fatigue life of CT and presents a comparison between "Flexor TU4" predictions and the fatigue life measured for strings with external mechanical damage incurred during service. Also a comparison between the sour fatigue life and that in air is presented in terms of percentages of sweet life (i.e. non-sour) for coiled tubing fatigue samples containing artificially induced mechanical damage on the external surface prior to being exposed to sour environments.
Drilling With a Positive-Displacement Motor and a Rotary-Steerable System on 3½-in. Coiled Tubing in the San Juan Basin
Authors: Pink Tony , Neves Maria , Seyler Chuck , Allcorn Marc , O'Leary Jim , Noynaert Sam , Hartensteiner Fred
Published: December 2007

As the demand for oil and gas increases, operating companies have begun to explore alternatives to drilling with conventional rigs. One promising approach is to drill wells with coiled tubing rather than drill pipe. While great successes have been achieved with coiled tubing in small diameter re-entry projects with Orienters and Positive Displacement Motors (PDMs), their use for large diameter, directional wells has never been explored. Schlumberger and BP evaluated the feasibility of this concept by drilling a series of wells for BP America using a combination of Rotary Steerable System (RSS) and PDM in the San Juan Basin.

BP's projects in the San Juan Basin are gas wells, of between 2500 and 7500 ft. depth, depending on the target formation. The coiled tubing was used in two different applications. Firstly, to drill 6 ¼" hole to 2500 ft. to explore the shallow coal-seam gas and secondly to drill the 8 ¾" section to 4000 ft. as the intermediate section for deeper wells.

This demonstrated that drilling with the RSS and PDM assembly, in conjunction with Coiled Tubing, has several advantages over conventional drilling. The major benefits observed when drilling with coiled tubing are increased ROP due to the elimination of connection time, elimination of the need for controlled drilling and the ease of directional steering for different well profiles.

This paper discusses the pre-job engineering, the lessons learned whilst executing the job and the conclusions reached as to the benefits and capabilities of such a system.
Application of Lateral Entry Guidance System (LEGS) Technology in Western Kazakhstan Oilfields
Authors: Pumnea Doru , Hunt Anthony , Mennilli Giuseppe
Published: December 2007

The Lateral Entry Guidance System technology is an intelligent method of navigating through the junctions of a multilateral well using Coiled Tubing.

The technology works equally well in cased and open-hole junctions without the need of sophisticated and expensive selective entry jewellery. The tool is slender enough to pass through production tubing and most completion restrictions and functions in all typical casing/liner diameters.

As LEGS technology itself has been presented in different forums before, the sole purpose of this paper is to present the particular conditions encountered in the Western Kazakhstan oilfields and methods used to make this technology work at depths over 5000 m.

The reasons behind the unsuccessful attempt to stimulate one well followed by a very successful stimulation of another well using LEGS bottom hole assembly will be showcased.

The result was a verification of a well design and operating philosophy against the alternative techniques of completion based selective entry. The outcome was the best producing well of the Karachaganak oilfield to date.

The paper will help potential users understand the challenges they may encounter and eventually, determine them to tailor their field development strategy in order to eliminate these problems and facilitate the use of LEGS.
EOR Pilot Tests with Modified Enzyme in China
Authors: Feng Qing-xian , Ma Xian-ping , Zhou Li-hong , Shao Ding-bo , Wang Xiao-lin , Qin Bao-yan
Published: December 2007

Micro and macro evaluations were conducted to understand modified enzyme EOR mechanisms using various fluids. Huff n puff tests and flooding tests were carried out with variable modified enzymes concentrations in several reservoirs. Resulted production performances were considerably improved. At reservoir temperature 50–80°C, lab experiment indicated that the modified enzyme solution was adaptable to both light and heavy oil and was not sensitive to minerals water with bivalent cation (1000mg/l) and high salinity (10%). The enzyme working performances were further enhanced with microorganism occurrence in the solution. Micro modeling experiment revealed that spontaneous emulsification and solubilization could take place between the modified enzyme and crude with emulsion particle 2–6μm in diameter, which is produced through striping as a result of solubilization. Core desorption and flooding experiments presented that desorbed crude volume and displacement efficiency were related to modified enzyme concentrations which usually ranged 5 to 10% with the optimum being 8%. In optimal conditions, recovery can be averagely increased by 16.9%. Experiments also proved that the modified enzyme and crude oil could form emulsion but the emulsion was not stable. One specific pilot test with modified enzyme had achieved additional oil production 22,869 bbl.
Water Saturation in Tight Gas Reservoirs
Authors: Crotti M. A.
Published: December 2007

Assuming a non-equilibrium scenario most of the non-conventional properties of gas-tight reservoirs are fully explained.

The model is able to describe, among others, the following typical characteristics of these reservoirs: over-pressurization, "abnormal" low water saturation, unusually small or undetectable capillary transition zones, abnormal pressure gradients, reservoir to reservoir disconnection and absence of identifiable free water level.

After accepting de usual over-pressurization as a direct indication of absence of hydrostatic equilibrium, the usual upscaling of capillary pressure curves results meaningless. It is so because capillary pressure was not originated in hydrostatic columns but in over-pressurization occurred when hydrocarbons were expulsed from the source rock (usually in close contact with reservoir rock).

As a result, fluids distribution is affected by non-hydrostatic equilibrium conditions still acting at the time of reservoir discovery.

A specially designed laboratory routine to measure the water saturation and electric properties directly on cores avoiding the usual water column modeling through capillary pressure curves, is presented. The relative permeability curves validity is also discussed.
Upscaling the Girassol Field: Comparative Tests and Impact of Near-Well Upscaling
Authors: Ding D. Y. , Artus V. , Roggero F. , Berthet P. H.
Published: December 2007

Girassol is a large and complex turbidite and highly faulted field. 3D high resolution seismic was shot, which gives good geological description and high level definition of heterogeneity. High quality seismic data allows constructing detailed stratigraphic model containing several tens of millions of gridblocks, which cannot be directly used for flow simulation. Reservoir properties must be upscaled on coarsen grid in dynamic flow simulation.

This paper discusses the upscaling techniques appropriate for turbidite and highly faulted field such as Girassol field. Upscaling of absolute permeability and geological facies are particularly addressed. Near-well upscaling technique is illustrated.
Modelling and Early Monitoring of Miscible Gas Injection in the Tight El Gassi Field, Algeria
Authors: Hadidi Boumediene , Ovens Jonathan
Published: December 2007

The El Gassi field is a Cambrian age sandstone oil field, located in central Algeria. The field lies approximately 100km south of the giant Hassi Messaoud field and shares many characteristics with its larger cousin. Production from El Gassi began in 1959 and has continued in depletion mode up to 2004. In 2000 a joint venture between Amerada Hess and Sonatrach, SonaHess, took over operatorship of the field. Because of the low permeability and adverse mineralogy for water injection, secondary miscible hydrocarbon gas injection was planned in El Gassi. Early gas injection (EGI) began in 2004 and an extensive data collection program has been conducted.

Between 2001 and 2004, an extensive integrated reservoir study was undertaken, with a view to predicting the likely increase in reserves from miscible gas injection. The study integrated Geophysics, Geology, Petrophysics, Production and Reservoir Engineering and lead to the development of a detailed Full Field simulation model.

This paper presents the main findings from the integrated study, with emphasis on the development and predictions arising from the resulting reservoir simulation model. Results from the ongoing monitoring of EGI indicates a positive response to gas injection. Field data are also presented and compared to the simulation results.
Heavy Oil Recovery by Liquid CO2/Water Injection
Authors: Al-Quraini A. , Sohrabi M. , Jamiolahmady M.
Published: December 2007

Alaska's North Slope reservoirs contain a massive heavy oil resource. There has been some success producing the less viscous crudes in the West Sak formation by waterflooding and water-alternating-gas injection. CO2 injection could also have potential applications as an enhanced oil recovery (EOR) process with the added benefit of providing a solution to the problem of produced CO2 present in the associated gas. CO2 is generally in supercritical state in normal reservoir conditions. However, permafrost causes an unusually low reservoir temperature and as a result CO2 will be in liquid state for these heavy oil fields.

In this study we consider West Sak reservoir and investigate different injection strategies in which available water and CO2 can be utilized individually or combined for EOR and CO2 storage purposes. A three-phase, threedimensional, black oil simulator was constructed accounting for the oil swelling and viscosity reduction due to dissolution of liquid CO2.

The results indicate that a combination of water and CO2 injection could be an attractive recovery method from the West Sak with higher oil recovery obtained when CO2 and water injection carried out early in the production life of the reservoir. If depletion precedes CO2 injection, CO2 storage is at its maximum. The recovery under liquid CO2 injection was almost the same as that of water flood due to its reduced mobility compared to CO2 gas. Water-Alternating-CO2 injection and Simultaneous-Water-CO2 injection showed significant improvement compared to water or CO2 injection alone. At Water-Alternating-CO2 (volumetric) ratio less than one, lower CO2 is required and higher CO2 storage per standard barrel of produced oil is obtained if CO2 is injected at higher rate for shorter period. Whist at Water-Alternating-CO2 ratio greater than one, reducing duration of CO2 injection favoured oil recovery but lowered CO2 retention factor compared to lowering CO2 injection rate.
Controls on Water Cresting in High-Productivity Horizontal Gas Wells
Authors: Sech R. P. , Jackson M. D. , Hampson Gary
Published: December 2007

It is widely agreed that gas reservoirs with a component of water drive should be produced at high rates to minimize the volume of gas which is trapped at high pressure by the advancing water (often termed ‘outrunning the aquifer’). Yet high production rates are also associated with coning (in vertical wells) or cresting (in horizontal wells) of the encroaching water, leading to early water breakthrough. In vertical wells, the formation of an inverse gas cone means that high gas rates can be maintained post-breakthrough until almost the whole perforated interval is flowing water. However, in horizontal wells, water breakthrough is a serious threat to gas deliverability, because the inverse coning mechanism does not apply and the well rapidly loads with water. Consequently, it is not clear whether producing at high rates is the best strategy to maximize recovery in gas reservoirs developed using horizontal wells.

We investigate the risk associated with producing horizontal wells at high rates by simulating gas recovery and aquifer response over a broad range of reservoir properties and production scenarios. We find that high rates always result in lower gas recovery unless the ratio of vertical to horizontal permeability is very low, in which case water cresting is suppressed. However, there are many instances where accelerating production recovers only slightly less gas over much shorter timescales, so may be economically favorable. Rate sensitivity increases in low permeability reservoirs with thin gas columns, because these conditions increase the tendency for water cresting, and decreases in reservoirs with strong aquifer support, since water breakthrough occurs regardless of the rate at which the well is produced. Our results can be used as a reference framework to rapidly assess gas production behavior and aquifer response within a wide range of field development scenarios.
Data-Driven Interpretation of Array Logs in Vertical and Deviated Wells
Authors: Frenkel Michael A.
Published: December 2007

We present a new method that is designed for accurate formation resistivity Rt estimation using inversion of galvanic or induction array logs acquired in vertical and deviated wells. At the first step, the method generates a near-borehole resistivity structure of a fixed thickness using inversion of the shallow-reading log measurements. At this step, the method does not aim for accurate estimation of Rxo but determines the parameters of an equivalent near-borehole zone that enables explaining (or fitting) only the shallow measurements. At the second step, the method determines the virgin zone resistivity, Rt, using inversion of the deep-reading logs in the model, which includes an equivalent near-borehole zone determined at the previous step. Because at each step the method performs inversion for a single model parameter, it enables fast and stable reconstruction of the Rt. To illustrate how the method can be used in practice, we present two field examples using array induction (2D case) and array lateral log (3D case) data.
Openhole Horizontal Gravel Packing Offshore Brazil: Best Practices and Lessons Learned From 72 Operations
Authors: Farias R. , Li J. , Vilela A. , Aboud R.
Published: December 2007

The challenge of the alpha/beta waves gravel packing open hole in offshore Brazil is how to successfully displace the proppant slurry in a large wellbore with a low fracture gradient formation, deep to ultra-deep water depths, and extended reach horizontal section.

Since 2001, job data from more than 72 open hole horizontal gravel packings have been compiled into a database. This paper reviews the well information and the key gravel packing parameters: pump rate, fluid density, injection proppant concentration, inner/outer annulus area ratio, dune ratio, packing rate, packing time and packing efficiency during alpha/beta waves. The engineering implementations and challenges, the best practices and lessons learned for open hole horizontal gravel packing are also summarized. The data analysis yields a better understanding about the open hole horizontal gravel packing in the Brazil offshore and provides a good guideline for future practice. A historical review is also presented showing how the gravel packing methodology has improved packing efficiency and success rate.

Case histories are provided demonstrating how to deploy the single trip system and pack the extended reach wellbore utilizing ultra-light-weight (ULW) proppant under extreme with improved packing efficiency and the success rate.
Porosity With Nuclear Magnetic Resonance in Naturally Fractured Clastics Reservoirs in the Devonian of the Bolivian Sub-Andean
Authors: Aguirre Omar , Glorioso Juan Carlos , Morales Jeannette , Mengual Jean François
Published: December 2007

We have validated with superior results that the direct measurement of porosity using Nuclear Magnetic Resonance (NMR), in Naturally Fractured Clastics Reservoirs of very low porosity (≍ 3.5%) in the Devonian of the Bolivian Sub-Andean, reveals information till now incoherent compared with core data. As it is well known, when the rock does not have paramagnetic elements, the porosity measured with the NMR is not affected by the minerals within the matrix and the tool answers mainly to the contained fluids in the pores of the rock. This peculiar characteristic of the NMR response in these low porosity reservoirs, with complex and variable lithology, become fundamentally beneficial at the time of determining an immediate porosity value with less uncertainty in comparison to the one from conventional logging tools, such as the Neutron, the Density and the Sonic, where there is a need to assume variable values of density and transit time for the matrix.

To corroborate that the obtained effective NMR porosity, is the best to be easily and truthfully correlated to true formation porosity, core data information are available. The key to obtain a reliable and precise measurement of porosity through NMR in these complex environments is based on the optimum selection of the acquisition parameters for the tool, like the polarization time, the echo-spacing and the use of a fit-for-purpose T2 cutoff time, tailored for this type of reservoirs. Furthermore, it will be demonstrated that the effects of nuclear diffusion on the transversal relaxation time distribution (T2 mode), primarily caused by gas, are not significant in these reservoirs, since an underestimate of the porosity was not noticed with regard to the one from cores.

Additionally with the aim of obtaining a better correlation among cores and NMR porosities, it has been used a specific high resolution acquisition and processing method, achieving continuous porosity measurements with a dynamic vertical resolution of 22 inches, more suitable to the sampling core interval and to the real petrophysical characteristics of our fields.
Realistic History Matching of Cyclic Steam Stimulation Performance of Several Groups of Multilateral Wells in the Peace River Field, Canada
Authors: Koci Paul Frantisek , Mohiddin Junaid Ghulam
Published: December 2007

With 8 billion barrels of bitumen in place and more than 30 years of thermal piloting and demonstration projects, Peace River offers an excellent growth opportunity for Shell's ultraheavy oil portfolio. In support of this initiative, integrated geological and reservoir modeling of two project areas was conducted. The key objectives were to

improve predictive modeling capability of cyclic steam stimulation (CSS) projects by history matching two groups of CSS multilateral wells and develop a history matched physical representation that not only validates empirical models but can be deployed to optimize CSS designs for full field development.

Detailed geological models were created over two pad areas providing a geological framework large enough to have realistic boundary conditions, including impact of surrounding wells. The geological models were imported into CMG's STARS thermal reservoir simulator, and a relatively fine grid was extended over each project area. All available historical production, injection, pressure and temperature data were used in history matching. Steam-induced reservoir dilation, explicit fracturing, and relative permeability hysteresis were important aspects of the overall physical representation. Common physical parameters for dilation/re-compaction, fractures, permeability/porosity transforms, vertical to horizontal permeability ratios, and relative permeability hysteresis were used for both pads. Each pad area maintained its own unique geological, petrophysical, and fluid properties, in line with observed field trends. Excellent history matches (aided by experimental design) of injection and production volumes, injection wellhead pressures, estimated production bottom-hole pressures and temperature profiles were achieved not only for the entire Pad A and B groups of wells, but also for the individual wells.

In summary, a predictive CSS simulation model has been developed and validated by history matching two areas of the Peace River field. The model is suitable for sensitivity studies of geological, petrophysical, and fluid properties. It is also capable of assessing impact of well configuration, spacing, steam quality, and steaming strategy.
Toolstring Impact Sensors
Authors: McLaughlin Stuart , Mclauchlan Alan
Published: December 2007

Since the application of slickline technology for wellbore intervention, the need for a measurement device to determine not only strain on the wire but forces applied to the toolstring at depth has been required.

What stands between a successful intervention and a ‘miss-run’ is the skill of the slickline operator and the surface weight indicator known as a load cell.

This paper will address the lesson learned from applying ‘Impact Sensors’ to slickline toolstrings in over 100 applications since it's launch in September 2005. The paper will also cover a case study that utilized the technology to better understand downhole conditions and their effects on toolstrings of various geometries. Completion technology has altered greatly and the results of directional drilling technology and horizontal completion architecture have proven to enhance the delivery of hydrocarbons to surface.

The application of new technology has been implemented by the Electric Line, Coil Tubing, Drilling, Reservoir Analysis and other groups in the industry, however the application of new technology to the slick line intervention business has been greatly lacking and because of this many completion engineers develop completion installation programs with the least amount of wire in the hole as possible.

Much of this reluctance is due to the perceived risk associated with deploying slick line into the well bore where an ‘unknown event’ may cause irreparable damage to the completion system or at the very least a costly exercise in equipment recovery.

The application of impact sensors to the slick line toolstring eliminates much of associate unknown risk factors by supplying the operator with known parameters being applied at depth.
Drilling Performance Management System
Authors: Rahil A.
Published: December 2007

Despite the capital intensive nature of drilling operations, drilling analysis is not routinely practiced as it should be. This is understandable since drilling engineers are principally rewarded for well planning and well construction. Therefore, the need to encourage best practices and continuous learning is a key to drilling improvement. Otherwise, the history will repeat itself "If you always do what you have always done, you will always get what you have always got".

In that purpose, the asset management tools and techniques introduced in this study can be effectively deployed in the analysis of drilling performance, they help to detect new opportunities, quantify and address removable lost time and analyse the major problems in a structured manner.

The aim of this study is to provide drilling team with a significant process to improve drilling performance, and set up a benchmarking process that becomes "a necessity for survival" as soon as the organization realizes there is someone else doing the same thing but better

This paper illustrates a case study of Hassi Messaoud field, it follows these steps:

What is the current performance in terms of time and cost? How do we benchmark with pacesetter in the area? How much this performance could be improved? What is the Road map of managing drilling performance in order to get improved?

The paper ends up with a structured methodology presented in a simple process flow incorporating some of the asset management tools and techniques with the results. It represents the drilling performance management system that can promote drilling efficiency and ensures a continuous learning through systematic analysis of historical data, and thereby, challenge well planning and construction.

Some enablers of the system are listed at the end. Then, conclusion and recommendations for further studies based on the system limitations are finally proposed.
Integration of Subsurface, Surface and Economics Under Uncertainty in Orocual Field
Authors: Rodríguez Rosa , Solano Karen , Guevara Siulenna , Velásquez María , Saputelli Luigi
Published: December 2007

Orocual field is one of the largest growing onshore opportunities in North of Monagas basin, eastern Venezuela. The field is planning to increase its production potential to more than 500% in the next five years. Business plan involve new expansion opportunities with improving field economics. These opportunities include massive development of the shallow heavy oil horizons by steam injection and development drilling in the deeper light and condensate reservoirs. To accomplish such a challenging goal, it was necessary to estimate new requirements for surface facilities while considering both reservoir uncertainties and multiple development scenarios.

This paper presents a unique and innovated method and a case-study for integrating multiple-reservoir forecasts with a surface facilities network, with economics and uncertainty. Subsurface responses from five Orocual formations were obtained from ten different reservoir simulation models with their associated well constraints. One single surface network model was used to gather production information from all the reservoirs and likewise was used to develop alternate production scenarios. An automated workflow handled the integration of reservoir production uncertainty, drilling schedule compliance, workover success, economics and varying surface facilities capacities.

The procedure that we have developed in this effort permitted the visualization of a more realistic asset performance compared to requirements in the long-term. The procedure also identified future needs for artificial lift.

The methodology developed also served as a platform for the exhaustive optimization of wellbore and surface equipment sizing in the presence of uncertainties based on front-end-loading (FEL) methodology. The procedure allowed the evaluation of parameters that affect uncertainty in well productivity, drilling schedule compliance, workover success, and varying surface facilities capacities, such as project execution time, workover success, facilities uptime, and facilities spare capacity.
3D Modeling of Tracer Experiments to Determine Gas Trapping in Foam in Porous Media
Authors: Li Z. , Rossen W. R. , Nguyen Q. P.
Published: December 2007

Foam diversion is used worldwide in acid matrix-stimulation treatments. Gas trapping is a crucial component of foam mobility and diversion. Previous studies have estimated trapped-gas saturation from a fit of coreflood effluent profiles of one or more gas tracers to a one-dimensional (1D) model for tracer mass transfer. A major factor in these experiments is diffusion of tracer between flowing and trapped gas.

We previously reported x-ray computed tomography (CT) images of Xe tracer injected during steady-state foam flow, which for the first time allowed direct visualization of the location of tracer in the core throughout the experiment. Here we extend the study by analyzing the diffusion of tracer through trapped foam in 3D. Cross-sectional CT images show that in this experiment tracer did not flow through the core evenly, but mostly along the top and sides of the core. Within these regions, tracer flowed in pathways separated by distances of a few mm. Modeling suggests that tracer diffused through trapped gas between the flowing gas pathways quickly, while mass transfer between the larger region and foam in the rest of the core was slower.

A three-dimensional (3D) model of flow and diffusion of tracer can fit the effluent data from the previous experiment quantitatively and fit CT images qualitatively. Moreover, the model fits the data well with values of flowing-gas fraction that differ by a factor of 2 (0.25 and 0.51).

We test four published methods of inferring flowing-gas fraction against our synthetic data: the method of Friedmann et al., based on early breakthrough of tracer; fitting effluent data with a 1D mass-transfer model, using one or two tracers; and the method of Nguyen et al. (2007), based on a break in a plot of average tracer concentration in a given cross-section as a function of time. None of these methods were able to distinguish between the two cases with different flowing-gas fractions. Using the 1D model fitted to results for two tracers with different diffusion coefficients gave less-accurate results than a fit using the slower-diffusing tracer alone.
Selection Slug Catcher Type
Authors: Vergara Contreras Moises Alfredo , Foucart Nicolas
Published: December 2007

Margarita field is one of the most important gas fields in Bolivia, not fully developed yet. The field development is to be completed in the near future and as part of the facilities to be constructed, it is included the installation of a slug catcher. The slug catcher situated at the end of the pipeline is intended to separate the phases and to provide temporary storage for the liquid received. Slug Catchers should be designed to take care of a slug.

The selection between the "Finger Type" and "Vessel Type" would be thorough the economical aspects and the characteristics of the equipment that best adapts to the conditions of the site.

The slug volume of the Margarita Field, calculated for a gathering system of 13 wells, being the outermost 30 Km. apart from the Plant, resulted in 26,35 m3 with a design pressure of 2025 psig.

The "multiple-pipe" slug catchers ("Finger Type") equipment is the most common equipment to handle slug volume, it is efficient and the operation is well known, however the common practice recomends that for volumes less than 100 m3, it is better to use the "vessel type" (this would be our case with 26,35 m3.) According to the rule of thumb the selection should be "Vessel Type", where 18 MMsm3/d is considered the gas flow for the design, that results in a diamenter of 102 inches by 14 meters long and a weight of 150 tons for the equipment size.

The "finger type" design from the equipment manufacturers could handle the same slug volume but the size is four fingers with a diameter of 40 inches by 10 meters long. The finger type needs 16 field welds and the weight is 80 tons. The equipment results in an easy assembly, of simple operation, smaller and lighter that facilitates transportation.

The Ex-Work delivery Cost and the equipment delivery to the site favors the "finger type" over the "vessel type". The installation cost for the vessel type is cheaper than the finger type but it is not enough as to favor the vessel type because if we add Ex-Work delivery and Installation costs, the finger type saves 30%.. The vessel type does not fulfill the savings expectations.in the Margarita Field Project ("onshore").

Additionally one more characteristic in favor for the finger type is the weight where the finger type does not risk transportation, where as the vessel type has transportation risks because the existing roads have only one lane that allows the passing of equipment less than 90 tons. The vessel type has 150 tons with a pressure design of 2025 psig; and if the pressure design would be 1500 psig, the weight would be of 120 tons.

After taking in consideration all the points in favor of the finger type (the multiple-pipe slug catchers), it is recommended to be installed in the Gas Treatment Plant (GTP).
Maximization of the Exploration and Development Efforts in Petroleum Field and Its Impact on the Hotelling's Model
Authors: Marques J. B. , Trevisan O. V. , Suslick S. B.
Published: December 2007

Many works on dynamic models for the maximization of the Net Present Value (NPV) on upstream projects have been published in recent years, originating in the academy as well as the industry. These models usually treat the effort considering either the exploration stage or the development stage of the petroleum field, but not both together. In this paper, two purposes will be pursued: (1) Investigating of the optimum net present value in the upstream project considering both exploration and development efforts simultaneously, and (2) Comparing the impact of this model against the dynamic models that deal with the sustainability of the exploration of exhaustible resources according to Hotelling's rule (1931). On the first topic, some papers were published by Pakravan (1977), Peterson (1978), Pindyck (1978), Liu and Situnen (1982), and Nilssen and Nystad (1986). The present paper shows a model bearing resemblance to the model proposed by Nilssen and Nystad (1986) but without the simplifications assumed by it. For this reason, the model proposed here may be more realistic. Some of the questions addressed in this work are: (a) What is the optimum exploratory effort for a petroleum field? (b) For how long do the exploratory efforts deserve investment before the beginning of the development stage? (c) What is the appropriate value of the reservoir recovery factor? The maximization of the NPV is represented by an objective function. The influence of the parameters in the calculation of the proposed objective function is shown by means of sensitivity analysis. Among the the companies in the world exploring petroleum, several do not usually adopt a methodology combining the exploration and development efforts. Filling this gap in the methodology is the main motivation for this work, which intends to disseminate the use of the combined model in the analysis of the economic viability project of the upstream area. Finally, in the conclusion section, among other suggested guidelines, indications are given as to which parameters from this model deserve more attention from persons making hard decisions in the upstream projects, and which information from the exploration and development of a petroleum field must be collected from existing data, or specially treated.
Single Step Matrix Acidising With HF–Eliminating Preflushes Simplifies the Process, Improves the Results
Authors: Rae Phil , Lullo Gino Di
Published: December 2007

For over 50 years, mixtures of hydrochloric and hydrofluoric acids have been used for the removal of near-wellbore damage in sandstone formations. Such mixtures dissolve many siliceous minerals, including clays and quartz fines, the materials most frequently associated with particulate plugging of the formation pores. Unfortunately, the dissolution of these minerals is not a simple process and various chemical reactions can result in the generation of voluminous solid precipitates or colloidal gels. The appearance of such precipitates in the near-wellbore, can ultimately cause further formation damage and negate the benefit of the acid treatment.

Other byproducts can be formed in sandstones containing carbonate minerals that react with acid and fluoride ions to produce the very insoluble calcium fluoride, CaF2, which is another potential source of formation damage. For this reason, traditional HCl:HF matrix treatments in sandstone formations are always preceded by a preflush, usually consisting of HCl to dissolve these carbonates.

This approach is not always successful and adds to the complexity of the operation. The situation is worse in multistage treatments, which traditionally involve many repeat stages of preflush, main HF-stage, overflush and diverter. In such situations, it is difficult to ensure that the correct acid stage is always entering the appropriate zone and encountering the appropriate mineralogy. The result can be poor zonal coverage, poor damage removal, creation of unexpected damage due to acid/rock incompatibilities and, ultimately, poor stimulation results.

This paper presents the results of a new acidising technique that eliminates the need for preflushes, across a wide range of mineralogies. It describes the background to this approach and reviews the results of laboratory testing and field treatments. It concludes with a matrix acidising methodology that can improve logistics, reduce cost and improve results while, simultaneously, making treatments easier to implement and control, at the field level.
Strategic Deployment of Chemical Systems in Petroleum Development Oman
Authors: Ojukwu K. I. , Al-Sharji H. H. , Al-Kitany N. , Stephenson E. , Edwards C.
Published: December 2007

Over 85% of Petroleum Development Oman (PDO) production is water and without action, this may increase to 95% by 2012. In 2004, a Chemical Profile Control (CPC) team was launched to coordinate a 2-year trial deployment of chemical water-shut-off technologies across the company. The aim being to reduce unwanted water or gas ingress for the purpose of improving oil or gas production while securing target recovery.

The deployment of chemical systems is adversely affected by four major challenges, namely; (1) limited know-how, especially of petroleum engineers & well engineers, (2) lack of multidisciplinary approach to candidate & chemical selection, (3) proof of concept before deployment and, (4) definition & measurement of success.

To tackle this problem, CPC team began by grouping PDO's Water Shut-Off challenges into 8 problem statements and presented it to known global providers. A workshop was organized inviting all contractors to propose solutions to the stated problems and acquaint PDO with available solutions. Based on our findings and confirmatory laboratory tests, the CPC team developed a Heatmap, which is a solution matrix that matches problems with solutions. A multidisciplinary assessment team was also created responsible for reviewing every project and proposing realistic solutions.

Since then more than 33 well trials – mainly in carbonate formations – have been completed at over 52% success rate using 3 existing contractors. Encouraged by these results, the company awarded umbrella contract to 3 other contractors to deploy a wider range of systems expected to boost success rate. The company strongly believes that increased success rate can be achieved by exploiting wider choice of effective systems, as inspired by laboratory trials.

This paper, therefore, presents the strategy, team, methodology, and overall results of the trials to date.
First Application of Novel Microemulsion Technology for Sand Control Remediation Operations—A Successful Case History from the Rosa Field, a Deepwater Development Project in Angola
Authors: Lavoix F. , Leschi P. , Aubry E. , Quintero L. , Le Prat X. , Jones T.
Published: December 2007

This paper documents a novel engineering approach and the operational methodology used to achieve high efficiency remediation on two offshore applications. Results are presented, detailing specific placement procedures, in-situ treatment design and productivity improvements.

Two wells were recently drilled and completed for the Rosa deepwater project, Block 17 offshore Angola, using a Non-Aromatic Oil-Based Mud (NAOBM) weighted with sized calcium carbonate. After installing the Stand-Alone-Screens (SAS) across the production intervals and allowing the wells to cleanup, the Productivity Index (PI) measured on each well was very disappointing. A diagnosis study concluded that the severe productivity impairment on these wells was related to either screen plugging by mud particles while running the screens to bottom in the NAOBM and/or the plugging induced by a mixture of formation sand, mud, and filter cake when draw-down was applied during cleanups.

Based on collaborative laboratory work between the operator and a service company to design a treatment fluid for removing NAOBM filter cake material for water injection wells, a microemulsion spotting fluid was formulated to remediate the damage in the two Rosa wells. The formulation contains a surfactants blend, acetic acid, and brine. The remediation was performed using a Coiled Tubing (CT) equipped with a rotating jet blaster to spot the treatment fluid inside the screen assemblies. Each treatment was allowed to soak. After the placement of the treatment pills on each well, cleanup measurements indicated significant PI improvements close to expected values. Production Logging Tests (PLT) analysis indicates that both wells are producing from almost all screen lengths.

Despite the challenging placement of the treatment fluid in the SAS assembly, the diffusion of the microemulsion with acid allowed break up and removal of blocking solids from the completion screens and filter cake residues from the wellbore walls, allowing full production.
Recovery of Heavy Oil by Thermoelectric Stimulation With Cyclical Injection of a Liquid Solvent, Maracaibo, Venezuela
Authors: Colmenares O Carlos E. , Faría Q Edwin R. , Pizzarelli Sergio G. , Chavier Tomas
Published: December 2007

Concurrently in the West of Venezuela, they have come proposing technicians to improve the recovery of oil weighed through of new processes of thermal stimulation that do not use water steam as agent of heating.

In this work it is considered the injection of hot gasoil the reservoir and exists the thermal stimulation process's physical mathematical foundation, based on the several mechanisms of heat transference as convection and conduction, as a whole with the mechanism of transference of matter for liquid diffusion – liquid, which one, it based in: A Balance of calorific energy, through it is determinated distribution of temperature in the reservoir, and the heat losses to the adjacent formations evaluated by the model of Marx and Langengein, besides the model of production defined by Boberg and Lantz. A Balance of matter ruled by Fick's Law of the diffusion oil-solvent, and the equation of difusitivity that governs the transitory behavior of pressure defined by Everdingen and Hurst.

The stability of the simultaneous solution of the differential equations system is acceptable, due the founded solutions are analytical type.

Operationally the efficiency of the stimulation and the field practice, they will be key points that there will allow the successful execution of the planned process, through the wells completation with sand control filters, sensors of pressure and temperature, besides the thermal equipments of completation that requiere the thermal processes.

To illustrate the field application of the proposed technology, there was selected the reservoir Bachaquero-01.

The results obtained in several running of sensibilities, indicate that it is achieved an increase obtains in the mobility factor of the oil at reservoir conditions of 10,5 times superior than the original one. Giving cycles of production of approximately 10 months, for a stimulated average rate with hot solvent of 850 BN/day versus stimulated average day with steam of 380 BN/day, in an arrangement of conformated wells by two horizontal ones in parallel.

The obtained results indicate that the heat solvent injecting technology to the formation is more favorable alternative than the steam alternate injection process, due it is predicted a major optimized recovery of oil by cycle.
Prediction of Recovery by Spontaneous Imbibition in Gas/Liquid/Rock Systems
Authors: Zhou K. , Zhang W. , Li Y. , Li K.
Published: December 2007

An analytical recovery model derived theoretically based on fluid flow mechanisms was applied to predict the production and the recovery by spontaneous water imbibition in gas-water-rock systems. Capillary pressure and relative permeability were included in this recovery model. It was demonstrated that the model prediction data were very close to the experimental data. When all of the fluid and rock properties are available, the analytical recovery model could also predict the production and recovery satisfactorily. Also studied were the effects of permeability, fluid property, relative permeability, and capillary pressure on the recovery by spontaneous water imbibition into gas-saturated rocks.
Heavy-Oil Recovery Mechanisms During Steam Injection in Naturally Fractured Reservoirs
Authors: Hernandez Mateo J.A. , Trevisan O. V.
Published: December 2007

The present work addresses the contributions, in both individual and combined forms, of the driving mechanisms, namely, solution gas, CO2 generation, steam distillation, capillary imbibition and gravitational drainage, for the recovery of oil and gas during the continuous steamflooding of a naturally fractured reservoir containing heavy oil. The investigation is carried out via numerical simulation of the phenomena in representative pattern cells.

Two numerical models were used to represent the matrix heating process. The first describes the heating of a horizontal cross-section of a matrix block surrounded by a fracture, in which the steam is steadily flooding. The second model is similar to the first, except for the position, which is changed to vertical to incorporate gravity effects.

The studies were performed for a fractured rock saturated with live oil. The rock properties are representative of a real fractured carbonate reservoir, as well as the fluid properties referring to the same field case. Also, the operational conditions used for pressure and temperature were the ones observed in the field, conferring to the work and conclusions, the character of a case study. A strategy was adopted to isolate the effects of each recovery mechanism.

The results show that the main mechanisms of oil recovery for the matrix block during steamflooding are the integrated action of steam distillation and solution gas. The first is the dominant mechanism and it is responsible for the quality improvement of the produced oil. The other mechanisms have a minor contribution to ultimate oil recovery. Such results are vital for the design of a steam injection project in similar oil fields.
Estimation of Rock Properties Applying an Alternative Geostatistical Autocorrelation Tool
Authors: Saccomano A. F. , Savioli G. B.
Published: December 2007

We present an autocorrelation estimator based on the dispersion variance (DVA) as an alternative to the classic semivariogram (CSV) used in Geostatistics to determine spatial distributions of reservoir rock properties. We evaluate DVA behavior with 2-D synthetic and field data sets, and we compare its performance to that of CSV. DVA turns out reliable to estimate spatial autocorrelation and anisotropy in two dimensions, it is more efficient than the classic estimator and it is very smooth and easy to fit with a theoretical model. We also use a set of porosity field measurements and a cross-validation technique to validate an autocorrelation model obtained with DVA. We conclude that DVA is a powerful tool to determine spatial autocorrelation.