bluuebunny/crossref_metadata_2025 huggingface dataset:
Integrated Downhole Fluid-Identification Applications for Complex Reservoir Development
Authors: Ferraris P. , Carnegie A. J.
Published: December 2007

A UAE offshore operator drilled a pilot well in a complex layered Middle Jurassic formation to confirm where to land a high inclination production drain.(fig. 1)

The reservoir underwent gas injection EOR. Reservoir simulation (fig. 2 & fig. 3) predicted possible gas fingering that required further confirmation before committing to drill the production drain. The objective was to positively identify all the intervals where liquid hydrocarbons could be produced avoiding the dry gas zones.

The petrophysical analysis was complicated by rock heterogeneities and fluid mixture including gas, heavy and light oils plus water.

A traditional approach based on standard logs was not conclusive.

The addition of NMR data versus depth allowed carbonate texture differentiation and a derivation of a simultaneous multi-fluid solution that highlighted the zones with possible oil production.

This initial information was used to select suitable intervals where to perform nuclear magnetic resonance stations with diffusion editing sequences designed for maximum sensitivity in the gas to light-hydrocarbon region.

Several stations were acquired with success and processed in pseudo real time making use of a VSAT link to share data with wellsite and predict the most likely downhole fluid composition.

With integrated depth and stationary information available, a few sets of sampling stations with real time downhole fluid identification were chosen to verify dynamically which formation fluid would finally flow.

Sampling was achieved using either a single probe or dual packer, depending on rock permeability. The fluid was analyzed in-situ using an innovative downhole fluid separation technique and some samples were taken to surface for a final PVT confirmation.

The combined information proved to be very consistent and provided a detailed reservoir description inclusive of fluid types.(fig. 31, fig. 32 & fig. 36)

The immediate impact was the change of the target drain location to a deeper zone in the reservoir structure. In fact, the zone a priori selected would have produced dry gas, due to the poor miscibility of injected gas and relatively viscous hydrocarbons in place.

The methodology used was well communicated to the various operator departments and had a broad acceptance, opening the way for a systematic similar approach in the future.
Reservoir Study Considering a TLP and Dry-Completion Development for a Deep Offshore Heavy Oil Field
Authors: Branco C. M. , Santos R. L. A. , Peres A. M. M. , Prais F. , Pinto L. A.
Published: December 2007

The continuous search for new oil resources is driving the major companies to start considering the development of offshore heavy oils (OHO) fields. Although not as heavy as inland heavy oil fields, where thermal methods are usually employed, development of these fields imposes extra technical difficulties as waterflooding might be the only feasible economical alternative for increasing recoveries. The process is used in association with long horizontal production and injection wells carefully placed in order to take advantage of the geological setting. OHO projects may face several production related problems during their lifetime, such as early water breakthrough and increasingly fast water rates. Other problems may also arise: strong water-oil emulsions, flow assurance problems related to hydrates, poor gas lift efficiency opposed to a less reliable satellite wells electrical submersible pumps (ESP) technology. Moreover, most offshore developments are based on FPSO production systems and satellite wells where one has limited (and highly expensive) well access.

The reservoir study described in this paper quantifies the worth of reservoir management actions that would be feasible in a TLP production system equipped with drilling and workover capabilities. This work focuses on the optimization of a development plan using different technologies such as side tracking existing wells, multilateral wells, ESPs, etc. A thorough discussion on the impact of operational efficiency factors (downtime factors) is also offered. The methodology described in this paper is applied to a full scale reservoir flow model that was continually history matched with oil/gas/water flow rates and measured downhole pressure data, gathered by a one well pilot production system for over a year period.

The results of the study are interpreted in terms of the scenarios more suitable for TLP developments. The benefits are directly related to the complexity of the reservoir geology which, in turn, governs the possibility of field development by phases. Other aspects such as the existence of pipeline infrastructure nearby the field and use of innovative artificial lift systems may either help or impair the use of dry completion wells concept. Although the present study reveals the FPSO option as the best economical alternative, for the particular field investigated, this work sets a standard for future OHO development studies.
Development and Application of Methodology for Assisted History Matching
Authors: Maschio C. , Schiozer D. J.
Published: December 2007

Proposal

History matching is a difficult task due to a high level of complexity caused by factors such as nonlinearities and a large amount of variables present in the process. Besides the complexity intrinsic to the process, there are other difficulties in manual procedure, such as managing a large amount of data, many simulation runs, comparison between observed and simulation data, manual modifications in the data file, etc. Therefore, the manual process is more susceptible to errors and usually requires more human resources. Assisted history matching allows the automation of part of the process, keeping the main decisions to be taken by the professionals involved in the process.

In this paper, three main topics related to assisted history matching are developed and applied: (1) use of independent objective function, separating the problem in several sub-domains where a minimum value of the objective function is searched, through an optimization process for each of sub-domains, started and performed simultaneously and independently; (2) use of heuristics to start the search with a higher probability to find the better solution using less simulation; and (3) development of a new direct search method of the optimization algorithm.

In order to validate the methodology, a synthetic field is used. Afterwards, it is applied to a real field. Results showing the benefits, limitations and effort reduction are presented and discussed.
Evaluation of Polymer Injection Projects in Brazil
Authors: De Melo M. A. , de Holleben C. R. C. , da Silva I. P. G. , de Barros Correia A. , da Silva G. A. , Rosa A. J. , Lins A. G. , de Lima J. C.
Published: December 2007

Petrobras has implemented three polymer injection pilot projects during the last two decades, in the onshore fields of Canto do Amaro (Rio Grande do Norte state), Carmópolis (Sergipe state) and Buracica (Bahia state), all of them in Northeast of Brazil. The first one is in the middle of the operation and the last two are already finished.

Polymer flood in oil reservoirs has been performed for several decades around the world. The polymers act basically increasing the viscosity of the injected water and reducing the porous media permeability, allowing for an increase in the vertical and areal sweep efficiency of the water injection, and, consequently, increasing the oil recovery.

The main drive for the pilot projects in Petrobras was to gain practical knowledge of the process, for a possible future expansion for other reservoirs and even for offshore fields.

This paper describes the experience of Petrobras in implementing and managing those polymer flood pilot projects. The laboratory tests, the designing and programming of the field operation, as well as the analysis and interpretation of the results, were all carried out by Petrobras personnel and are covered in this paper. The tracer injection for reservoir characterization purposes, which preceded the polymer floods, is also described.

In this work we performed a technical evaluation of the whole polymer injection process, investigating the reservoir response in terms of oil recovery and time. The economical study will be made hereafter in another work.
Reduction of Water-Environment Hydrocarbon Pollutions with the Use Of Porous Glass
Authors: Macuda Pawel , Zawisza Ludwik , Macuda Jan , Rogowska-Kwas Renata
Published: December 2007

Owing to their properties, oil-products are environmentally noxious, especially for the ground-water environment. In the case of a break-down with an uncontrolled leakage to the environment, only part of hydrocarbons can be removed; a predominant amount of them infiltrate the soil, polluting ground- and surface waters. This results in organoleptic changes in water quality. Besides such leakages have a negative impact on flora and fauna. They accumulate in tissues of the living organisms and hardly undergo treatment.

The physicochemical properties of modified porous glasses Na2O-B2O3-SiO2 are presented in the paper along with the results of experiments on their application to removing hydrocarbons from the environment. It follows from the obtained reduction of pollutions in laboratory samples, that porous glasses can be used as adsorbents for liquidating hydrocarbon pollutions from ground- and surface waters.
A Methodology to Evaluate the Gas Migration in Cement Slurries
Authors: Gonzalo V. , Aiskely B. , Alicia C.
Published: December 2007

Gas migration represents 25% of the primary cement jobs failures.For this reason, studies have been done in order to evaluate several properties of cement slurry like fluid loss, permeability, static gel strength, and others. However, the study of these variables has not shown separately a method to prevent the gas migration and which of these properties of cement slurry have to be controlled to avoid such problem.This paper describes a methodology to control the gas migration.The results of this study were validated with field experiences.

The methodology consists of the next three steps: the first one is the evaluation of the Flow Potential Factor (FPF) which predicts severity of the problem.Then, the static gel strength is measured as a function of time, obtaining the transition time of the cement slurry.Finally, pressure reduction due to static gel strength versus time is simulated with the Fluid Migration Analyzer (FMA), validating gas migration through cement slurry.

Three wells were study in Santa Barbara and San Joaquín fields located in Eastern Venezuela. In each well, pore pressure of the gas zone, temperature, gas zone depth and the annular space across the gas zone were used to determine the FPF.

The results of this study agree with field experiences, based on quantitative measurements like transition time and FPF.This methodology allows selecting the optimum cement slurry design in a way that prevents industrial accidents and assuring the well life.
Key High-Quality Technologies as Pivots for Hydrocarbon-Reserves Expansion
Authors: Navarro J. B.
Published: December 2007

The digital technology trends to transform the hydrocarbons production dynamic and can potentially increase world oil reserves. Several inherents systems and techniques are right now commercially availables, although the support of specialized hardware is required for completing truly integrated projects.

Five key and high quality technologies-remote sensing, visualization, intelligent drilling and completions, automation and data integration- are a set of tremendous new tools that will enable energy companies see reserves more clearly, plan optimal drilling and production strategies, and manage operations more efficiently.

TheInter-well seismic imaging, 4D optimized seismic and other key technologies in coherence cubes are the most recent advances speciality with great value for reservoir management.

Crosswell seismic imaging is the first technology that fills the information gap between surface seismic and well logs and enhances the profitable management of subsurface hydrocarbon resources.

Reservoir dynamic simulation models, running in conjunction with real time sensors and automated controls, provide high importance information, and the operators can visualizate efficiently subsurface conditions to maximize production and manage efficiently field development.

Scalable 3D visualization technology combined with massive data management capabilities and high-speed networks are drastically reducing cycle times for prospect generation, field development planning, well design, drilling and completion.

This paper shows examples of high resolution crosswell seismic visualization, downhole sensors systems, massive data capture with integral systems, and other technologies supported with digital resources as intelligent drilling and completions, which are generating an increase in the productivity in many scenarios and reservoirs in Mexico and worldwide.
Value of Information for a 4D-Seismic Acquisition Project
Authors: Ballin P. R. , Ward G. S. , Whorlow C. V. , Khan T.
Published: December 2007

The decision of any data acquisition should always involve a cost - benefit analysis. While cost identification is usually easy, the value gained with new data is specialy difficult when there are mostly indirect benefits. This is the case of 4D seismic projects where the main contribution is to reservoir production management. Recently, the interest on 4D seismic and the number of such projects have increased significantly. Despite of the high cost, there is a lack of robust and systematic process to evaluate their value.

Bp TT faced this challenge when analyzing a Life of Complex Seismic (LoCS) project for multiple gas reservoirs in the Greater Cassia Complex, located in the Columbus Basin, Trinidad and Tobago. This Complex comprises many producing and future development fields including Amherstia, Immortelle Parang, Kapok, Cannonball and Cassia.A significant fraction of present and future potential reserves of several Tcf is under shallow gas, which has detrimental impact on seismic image quality. Such condition required consideration of expensive 4C OBC (Ocean Bottom Cable) seismic acquisition options. Additional benefits from 4D seismic for monitoring dynamic reservoir performance could be foreseen with a permanent installation. A robust and systematic value of information study was developed as part of the LoCS project in order to support the decision about the 4D acquisition options.

This work describes the Decision Tree process used in the LoCS value of information study as well as discusses the main results used by bpTT to make a based decision about the acquisition program.
Economic Evaluation of Oil-Production Project With EOR: CO2 Sequestration in Depleted Oil Field
Authors: Gaspar A. T. F. S. , Suslick S. B. , Ferreira D. F. , Lima G. A. C.
Published: December 2007

This paper presents an economic feasibility study for CO2 coupled with EOR in a small mature Brazilian oilfield. The present study considers two important and complementary reasons: (1) EOR improvement - CO2 displaces residual oil left in place after primary production and secondary water flooding and has been successfully injected in mature fields for forty years, in order to extend the oilfield life; (2) storing this gas in the oil reservoir and, hence, a contribution to reduce its emissions. The physical aspects of this project are described, and a breakdown cost methodology is proposed in order to estimate the main financial determinants of the integrated EOR with CO2 sequestration (cost of capture, compression, transportation and storage). Project evaluation is derived from a cash flow model, regarding reservoir production profile, price and costs, capital expenditures (CAPEX), operating expenditures (OPEX), carbon credits, depreciation time, fiscal assumptions, etc. A sensitivity analysis study was carried out in order to identify the most critical variables. Results indicate that project NPV is around US$ 3.2 million, what is significant for a small mature field. Additionally, it contributes by removing Green House Gases (GHG) from the atmosphere by storing 0.73 million tons of CO2 over a period of 20 years. Project feasibility, as expected, was found to be very sensitive to oil price, oil production, and CAPEX.
Compositional Simulation of Fluid Flow Coupled Stress-Sensitive Reservoirs
Authors: Benavides Y. , Maya G. A. , Gallego J. G. O.
Published: December 2007

Because of the every time higher complexity of the petroleum and gas reservoirs, their analysis have become into an intensive job that, to get a real behavior, most of then consider numerical modeling of the different phenomena inside the reservoir.Two aspects that have shown transcendental importance in reservoir fluid flow are the compositional characteristic of the fluid and the rock stress sensitive.Several authors have analyzed independently every characteristic, remarking every time more their importance.

A fully implicit model to study this problem is developed on a cylindrical finite difference, point distributed grid. Compositional modeling is performed by means of a 12- pseudocomponent Peng-Robinson equation of state with volume translation, tuned to actual PVT and field data of a gas condensate fluid.Michelsen's phase stability test is also considered in the VLE calculation procedure.Because of the proper multiphase flow-effective stress law is unknown, and the capillary pressure for the fluid-rock system under consideration is negligible, it is approached to zero in this research.The geomechanical rock deformation calculation is based on the non-linear elastic model.

To comprehend the involved phenomena, this model must guarantee numerical stability.It has to be taken into account that in order to obtain numerical stability the time step (?t) used in the models should be long (opposite to the requirements of non coupled models).It was realized that the influence of geomechanical properties at the bottom hole pressure is evidenced by long production time simulations.The major contribution of this research is that it helps to determine the pressure sensitivity to important factors such as boundary and initial conditions, and compositional fluid presence in the reservoir.

This study identifies the necessary ?t values to ensure numerical stability.The model shows that when c[bc] get values closed to the rock compressibility, c[r], the pore pressure fall is every time higher.Some other studied parameters emphasize both, the complexity of the phenomenon and the strong influence of some variables on it.
Impact of Simplifications in Risk Assessment and Decision Making Process
Authors: Costa A. P. A. , Schiozer D. J.
Published: December 2007

Decision analysis applied to the development of petroleum fields must take into account the risk associated to several types of uncertainties. In this phase, the importance of risk associated to the recovery factor may increase significantly and numerical simulation is usually required to model the reservoir yielding high computation effort. The process is complex due to (1) high investments (2) large number of uncertain variables (3) strong dependence of the results with the production strategy definition. Therefore, simplifications are usually required to quantify the impact of uncertainties. In previous works, it was shown the impact of several simplifications in the process to be used in the decision making process after the risk assessment. The risk due to geological uncertainty is then separated from the selection of production strategy and other types of uncertainties. In this work, some results are presented and a discussion is made to show the impact of some simplifications in the selection criteria of the geological representative models before and after the integration of the production strategy optimization. The process is applied in an offshore field in Brazil and the results shows that it is possible to improve the performance and reliability of the risk analysis process with less computational effort.
Transient Two-Phase-Flow Model for Predicting Column Formation in Intermittent Gas Lift Systems
Authors: Sandoval S. , Solórzano L. R. , Gasbarri S.
Published: December 2007

The intermittent gas lift (IGL) method has experimented a continuous growth due to well depletion and so is expected from its technology.IGL is a periodic transient process with two major stages: firstly, a liquid column or slug is accumulated at the bottom of the well.Secondly, the slug is displaced by pressurized gas lift to the surface. Current models estimate the height of the fluid column based on single-phase behavior due to the lack of multiphase transient models. These models underestimate dramatically the column when the operating gas lift valve is located far away from the perforations. To improve this model a study focused on a two-phase flow behavior during the accumulation stage is required. In order to achieve this objective a special multiphase flow facility was assembled and more than 200 steady and transient tests were run.Continuous and transient tests were performed with flow conditions and fluid properties selected from typical fields.The collected data allowed identifying the variables that govern the phenomena and establishing a methodology to determine the mixture density, pressure gradient and column's height. Since no previous correlation matched, a new correlation for transient hold up was generated using qualitative and dimensionless analysis. As part of the approach proposed here, time was included implicitly into the equations in order to reduce their complexity. The analysis showed that Reynolds's number, homogeneous liquid holdup and dimensionless viscosity govern the phenomenon. The model was validated with field data . The correlation applies to slug and churn flow patterns because those are the expected patterns for typical field conditions. The accuracy obtained with field data suggests applying this approach for designing and optimizing IGL installations.
Local Experiences Obtained During Appraisal of Heavy and Viscous Oil in Deep Water
Authors: Barreto W. S.
Published: December 2007

There are many challenges related to the appraisal of heavy and viscous oil reserves. When this includes a deep-water offshore environment the challenges, including safety issues, increase in complexity. In this paper we share some experiences obtained during the preparation and execution of heavy oil appraisal activities. It is presented a methodology which uses the preliminary results of petrophysical and fluid characterization obtained during the logging phase, as well as prior information from correlated field/wells, in order to design the appropriate configuration and location of the ESP (Electrical Submersible Pump) in the DST (Drill Stem Test) string and the sampler location, which should allow single-phase sampling. During the operation, real-time data interpretation is performed, validating the data obtained and sensitizing parameters such as pump frequency, bubble point pressure, GOR and viscosities, allowing the diagnosis of the operation and consequently appropriate flow conditions in order to provide a optimum picture, supporting decisions regarding sampling time and other specific appraisal objectives. The examples presented illustrate the proposed methodology for integrated appraisal applied to heavy oil, and show its benefits.
Appraisal of Heavy and Viscous Oil in Deep Water
Authors: Barreto W. , Ribeiro C. , Menezes P. , Armacanqui G. , Souza R.
Published: December 2007

Discussions regarding appraisal of heavy and viscous oil in deep water are the subject of this paper. It is destined to new engineers and professionals unfamiliar with DST-ESP-SWT operations in deep water.

It is introduced here a methodology that has been applied locally supporting well testing design and optimization. The process consists in an integrated and fast rock&fluid characterization supporting the DST-ESP-SWT design. During the operation, the optimization of the operation is performed by real time monitoring and lift diagnostic, combined with surface measurements. Our experience related to the application of the referred methodology is illustrated by examples where the benefits of such process are featured. Finally, it is introduced the concept of an integrated appraisal service, which proposes to be a powerful mechanism in order to facilitate the evaluation of complex systems such as heavy and viscous oil in deep water wells.
System for Remote Detection of Pipeline Leakage
Authors: Sadovnychiy S. , Bulgakov I. , Valadez J.
Published: December 2007

This article deals with the development of a remote detection system for early detection of leakages in the oil and gas pipelines. The system is designed to receive data's from various electronic equipments operating in differentfrequency ranges and corroborate the data's with suitable formula's to get the ultimate better yield. Four types of information sensors form the major part of equipment: an infrared camera, a video camera, a laser spectrometer and global positional system. A joint data handling allows to determine the presence and location of leakages.
3D CFD Simulation of ESP Rotary Gas-Separator Performance Under Two-Phase-Flow Condition
Authors: Suarez L. , Kenyery F. , Azuaje M. , Peña M.
Published: December 2007

The performance prediction of a Rotary Gas Separator (RGS) is very important for ESP systems applications. The pump performance is severely affected when it handles high Gas Void Fraction (GVF) at its intake. The function of the RGS is to separate both liquid and gaseous phases, and to expel the gas through a crossover section to the annular area between casing and tubing. Typical designs use separation efficiency values based on an empirical standpoint of view. Also, the literature references regarding an important parameter like the inducer head is very scarce. The performance analysis of a RGS (540 series separator), under two-phase flow conditions, has been conducted using 3D-CFD simulation tools (CFX 5.6). Water-air mixtures were used as working fluid and the mixture GVF was varied from 10% up to 30%. The results shows that the RGS separates efficiently the phases, but the inducer head is insufficient to overcome the friction losses in the crossover and the liquid column static pressure in the annular space. As a consequence, a new inducer design is necessary to create a higher head value to push the gaseous phase out of the RGS and not to be dragged by the liquid phase. The simulation could be an alternative tool for selecting the depth of the downhole equipment as a function of the liquid level. This could help the designer to properly obtain the minimum submergence of the equipment that satisfy the phases separation and gas expulsion of the RGS, getting a lower GVF at the PIP.
Identification of Water-Bearing Layers with Resistivity Image Logs
Authors: Naides C. , Paris M.
Published: December 2007

Traditionally, wellbore images logs have been used to perform structural and stratigraphic analyses. This study presents an approach of the resistivity image oriented to the identification of aquifers, further enlarging the application scope of this tool. From the analysis of borehole resistivity image logs, special image characteristics were observed, which were not related to their traditional application. Consequently, an analysis was carried out integrating well logs and interpreted core data for two different areas and formations located in Argentina in the Neuquén Basin: once at Lower Troncoso Member of the Huitrin Fm (Aptian), and the other at the Sierras Blancas Fm (Kimeridigian). This particular response from resistivity images was calibrated to reservoir zones with high water saturation, corresponding to aquifers.

Certain features were observed in the studied cases which constitute a condition for positively identifying aquifers by means of borehole electrical images. These are as follows: Clastic reservoirs (sand/clay).Reservoirs with good petrophysical conditions.Drilling mud salinity values similar to formation water salinity values.

The high resolution rendered by this image logging tool makes it possible to identify high-water-saturation zones and accurately locate oil-water contacts. No special processing is required, and decisions can be made based on the direct observation of the recorded image.
Use of Quantitative Risk Analysis for Uncertainty Quantification on Drilling Operations-Review and Lessons Learned
Authors: Cunha J. C. , Demirdal B. , Gui P.
Published: December 2007

This paper presents comments and some background on the use of risk analysis methods in the oil and gas industry. Particularly attention is given to applications developed specifically for drilling operations. A literature review emphasizing articles written specifically for risk analysis applications on oil & gas well drilling operation is presented.

Recommendations for procedures related to risk analysis methods implementation as well as an example of application and its results are presented.

A Monte Carlo simulation was run to predict a cumulative distribution function for a well drilling AFE (Authorization For Expenditure.) The simulation procedure as well as the resultant function is presented.
Temperature Behavior in Multilateral Wells: Application to Intelligent Well
Authors: Romero A. , Zhu D. , Hill A. D.
Published: December 2007

Intelligent well completions are being increasingly used in complex wells (horizontal, multilateral, or multibranching). Such completions are equipped with permanent sensors to measure temperature and pressure profiles, which then must be interpreted to determine the inflow profiles of the various phases produced. Distributed temperature measurements using fiber optics in particular are becoming increasingly applied The value of an intelligent completion hinges on our capability to extract such inflow profiles, or, as a minimum, to locate the entry locations of undesirable water or gas entries. In this paper, we develop a model of temperature behavior in multilateral wells. The model predicts the temperature profiles in the build sections connecting the laterals to each other or to a main wellbore, accounting for the changing well angle relative to the temperature profile in the earth. In addition, energy balance equations applied at each junction predict the effects of mixing on the temperature above each junction.

We applied the multilateral wellbore temperature model to a wide range of cases to determine the conditions for which intelligent completions are most useful. Parameters varied included fluid thermal properties, absolute values of temperature and pressure, geothermal gradient, flow rates from each lateral, and the trajectories of each build section. From this parametric study, guidelines for the optimal application of intelligent well completions are represented.
Determining Relative Permeability from Unsteady-State Radial Fluid Displacements
Authors: Toth J. , Bodi T. , Szucs P. , Civan F.
Published: December 2007

The practical interpretation formulae which can be used for determination of the relative permeability data from the production and/or injection performance data are derived based on the formulation of the near-well-bore immiscible fluid displacement process. The formulations for convenient calculation of the relative permeability data similar to the JBN method are provided and validated using the laboratory data obtained by the radial immiscible fluid displacement tests in horizontal porous disks. The applications demonstrate the capabilities of the present interpretation method.
A New Chemical Treatment to Remove Multiple Damage in a Water Supply Well
Authors: Nasr-El-Din H. A. , Al-Mohammad A. M. , Al-Hajri M. A. , Chesson J. B.
Published: December 2007

A vertical well has a history of problems which has contributed to its disappointing performance. A 15 wt% HCl acid treatment was performed in an attempt to remove drilling mud filter cake and improve wellbore to formation connectivity, however the solubility of the formation's cementation material (calcite) was overlooked and sand production resulted after the treatment. A screen liner running operation was then performed, with a need for sand control, and massive mud losses and polymer pills were lost to the formation during the process.

The workover fluids were displaced deep into the formation while loading the hole to maintain well control. The presence of biopolymers in the completion fluids enhanced the activities of sulfate reducing bacteria (SRB). These bacteria further compounded the problem, and the damaged environment was ideal to initiate the production of plugging FeS and biomass in the near wellbore region. Ultimately, the formation was not able to deliver the necessary flow rate to supply the ESP pump when the well was returned to production.

The damage mechanism is a combination of polymer residue, biomass and FeS plugging the screen liner. A three-stage treatment was designed to remove the damaging material. The first stage was based on tetrakishydroxy methyl phosphonium sulfate (THPS) and was designed to remove iron sulfide and hydrogen sulfide, and control the growth of bacteria. The second stage was based on formic acid and was intended to remove FeS and some of the polymer residue in the near wellbore area. The third stage was based on a two-part oxidative treatment and was designed to remove polymer damage deep in the formation. Analysis of well flowback samples before and after the treatments was used to confirm the damaging mechanisms and to evaluate the treatment.

This paper reviews the procedure used to identify the problem, and the unique treatment which successfully restored well productivity.
Hydraulic Frac Stimulations in a Libyan Oil Field - A Case History
Authors: Droegemueller U. , Leonhardt B.
Published: December 2007

Wintershall started in 1994 with the preparation of frac treatments. Between 1995 and 2004 eight wells were fractured. Only one frac was conducted in Libya in the mid 1970s and the challenge was to introduce this technology. Firstly, a service company had to be encouraged to provide the equipment, the service and logistics for chemicals and proppant. Secondly, the National Oil Corporation had to be convinced that application of this kind of technology would be feasible and beneficial for the development of a low-permeable reservoir.

All wells in the subject field produce from a heterogeneous Lower Cretaceous Sandstone at a depth of about 12,000 ft. The drive mechanism is solution gas drive since the underlying aquifer was found to be inactive. Low porosities of 10 to 14 % and poor permeability ranging from 0.1 to 20 mD allow only a low to moderate production, which hampers the economics of a field development.

Today, 80% of the production wells in this field have been successfully stimulated by hydraulic frac treatments. State-of-the-art real-time analysis was performed to evaluate and optimize the frac operation on the fly. Hydraulic frac simulation findings were compared to post-frac well test results obtained from pressure buildup analysis in order to crosscheck the outcome.

About half of the cumulative oil produced to date can be assigned to the frac stimulations. However, they did not only help to improve the productivity of each well, but allowed us to produce longer above the bubble point and even permitted an optimization of production with bottomhole flowing pressures below the bubble point. Hydraulic prop fracs have successfully shown to be an appropriate means of reservoir management in this oilfield.
Scale Inhibitor Application in Injection Wells to Protect Against Damage to Production Wells: When Does It Work?
Authors: Mackay E. J.
Published: December 2007

Prevention of inorganic scale damage in the formation around production wells is usually achieved by batch squeezing the productions wells at risk. However, in Western Siberia protection of production wells is sometimes achieved by application of scale inhibitors in the supporting water injection wells. This technique relies on the effective displacement of the inhibitor across the reservoir from injector to producer. This is not generally considered a viable scale management option due to the extent of chemical retardation that is a necessary result of inhibitor retention on the rock matrix. However, for short inter-well distances, such as may occur in onshore developments, and where fracture conductivity is high enough that inhibitor contact with the matrix rock is minimal, then this technique can provide adequate protection against scale induced formation damage in production wells.

This paper explores the range of reservoir scenarios under which this technique may be applicable, considering inter-well distances, the extent of fracture vs matrix flow, and the potential range of inhibitor retention on various rock substrates that may be encountered in fractured reservoirs. The approach is to use numerical modelling techniques to investigate the range of conditions under which this scale management approach may be applicable. This data may then be used identify when scale control may be adequately achieved using this technique, thereby reducing the need to shut in production wells for treatments, and when this approach would not provide adequate protection in actual field systems. Comparison is made of the potential for performing batch treatments in the injections wells, compared to continuous injection of scale inhibitor in these wells.
Reservoir Study V9 of El Furrial Field, Venezuela
Authors: Acosta L. , Marin E. , Labastidas E. , Bello J. , Jiménez J. , Cordoba P. , Pascual J. C , Auxiette G. , Gou Y. , Thorsen B.
Published: December 2007

El Furrial field is one of the most important hydrocarbon giants of Venezuela. It's located at the north of the Monagas State and it handles approximated 45 % of the production of this area. It was discovered in 1986 and its characteristic makes it unique. The strategy of development has been supported by the combined injection of miscible gas and water, this has allowed to maintain the production plateau of 400 MBPD. A previous feasibility studyshowed a recovery factor ranging from 50 % to 60 % by implementing AGA, that study lead to the necessity of a new numeric model capable of simulate non conventional recovery possesses, creating a model known as the V9 Model.

This new approach is one of the most transcendental advances of the El Furrial field characterization. It's created over a structural model, which is based in 3D seismic of 370 Km2., which allowed a better definition of structural complexity. A petrophysics supported by 13692' of core, classified by 5 types of rocks, representing the heterogeneity of the reservoir. A high resolution stratigraphics model which is based on a cronostatigraphic criterion, which defined 47 statigraphic units. A sediment model based on 24 Paleoambient maps, considering direction of the sediment in the geostatistic model. A fluid model which changed a TarMat surface that varied from a horizontal to a folded one. A Geocellular model which is described by a 350 million cells grid, which generated a simulation grid of 500K active cells out of 900K.

A thermodynamic model which honors the fluid model, with a miscible optionvalidated by a slim tube and iswelling tests and a state equation for the compositional simulation. A rock-fluid model with a set of curves per rock type, which considers the hysteresis process that allowed simulate the AGA and the Dewatering process.

As a result the OOIP increased in 1.3 MMMBls. A fluid model with thicker and area extension of the TarMat in the sands. Drilled new delineation wells in areas previously considered in the non-economic limit incorporating new reserves and the development of new opportunities. A portfolio of 70 locations for the development of reserves of the field. Modeling of an AGA pilot project in order to evaluate the implementation of it. Evaluation different injection processes conventional and non conventional, in order to define the development plan of the field. The integrated subserface-surface simulation achieving the integration between recollectionand the reservoir model V9,which is one of the biggest world wide.
Reservoir-Based Benefits Analysis Demonstrates Value of Intelligent Completions in Latin America
Authors: Cabrera B. , Sakowski S. A. , Anderson A.
Published: December 2007

Intelligent well technology, referring to the implementation of fundamental process control down-hole, has advanced rapidly over the last decade in the upstream oil and gas industry. Focus for application of this technology in Latin America recently has shifted from high profile offshore projects to the more economically sensitive land-based arena. Stimulus for this shifting market in Latin America has been the ability to clearly demonstrate value of intelligent completions in terms of improved well and reservoir performance. Significant reduction in well intervention costs no longer is the primary economic driver for the application of intelligent well technology.

In this paper, we present a reservoir-based benefits analysis process that has successfully been used to quantify the value of Intelligent Well Systems for several operators in Latin America. The process involves close cooperation between the service and operating companies to: identify and rank potential Intelligent Well System candidate wells,understand reservoir and operational issues,design the most appropriate Intelligent Well System solution andquantify the value of the Intelligent Well System application compared to conventional completion alternatives.

A case example will be presented that highlights these major steps of the process and illustrates typical results that allowed the respective operator to make value-based, informed decisions on the application of intelligent completion technology. Post-installation well performance results also are presented for several case examples to illustrate the actual value of Intelligent Well Systems to another operator in Latin America.
Production Enhancement for a Northern Mexico Field Well Resulting from Flowback Evaluations Using Chemical Frac Tracers: A Case History
Authors: Hurtado A. L. , Asadi M. , Woodroof R. A. , Casas D. D. , Morales R.
Published: December 2007

Proposal

The chemical frac tracing technology is used to evaluate flowback and flowback efficiency. This unique technique utilizes a family of environmentally friendly and fracturing fluid compatible chemical compounds to trace segment-by-segment injection of fracturing fluids. These chemical compounds have unique chemical and physical characteristics that make them detectable at low concentrations of 50 ppt (parts per trillion). These tracers are mixed at a known concentration into individual frac fluid segments as the frac fluid is pumped downhole and into the formation. Upon flowback, samples are collected and analyzed for tracer detection. With the use of the mass balance technique the flowback and flowback efficiency for each fluid segment are calculated. These precise flowback and flowback efficiency calculations yield a more accurate assessment of fracture cleanup efficiency which in turn helps to unravel cleanup problems. This paper presents a case history whereby four different chemical frac tracers were injected into four fluid segments of a frac job. The flowback and flowback efficiency calculations revealed low recoveries of the injected fluid segments through 86 hours of flowback. Based on the flowback results, a recommendation was made to shut in the well for 24 hours. Upon re-opening the well to production, flowback samples were again collected to evaluate flowback enhancement as the result of reservoir pressure buildup and or gel-breaking during the shut-in period. The total flowback efficiency increased by 50% while daily oil production increased by 62%.
Modeling Deepwater Reservoirs
Authors: Ezekwe J. N. , Filler S. L.
Published: December 2007

Deepwater reservoirs pose significant challenges worldwide to companies exploring and producing such reservoirs because of the high exploration, development, and production costs. Great uncertainty and risk attend the evaluation of deepwater reservoirs because of the environment, sparse well control, and lack of direct measurement of reservoir properties. Proper modeling of deepwater reservoirs provides companies with tools to evaluate these reservoirs and quantify risks associated with their development.

There are five critical areas in the process of modeling deepwater reservoirs. These are geological and geophysical modeling, reservoir characterization, reservoir flow modeling, facilities/flow assurance, and uncertainty/risk analyses.

This paper presents methodologies found useful by experience in the modeling of deepwater reservoirs. Actual field cases describe our experience in using systematic steps based on the five critical areas to model the Zia reservoir, a Manatee reservoir in the Troika Basin, and the Magnolia reservoirs using the Markov Chain Monte Carlo technique.
Design and Development of Quaternary Amine Compounds: Corrosion Inhibitors With Improved Environmental Profiles
Authors: Tiwari L.
Published: December 2007

Stringent environmental constraints imposed by government regulators upon the oil and gas producing industry has led to the need for new ‘greener’ chemistries, which have less environmental impact to be developed and employed. The environmental impact of a corrosion inhibitor is often defined by three tests, biodegradation, bioaccumulation and toxicity. All three criteria have limits that must be met for a chemical to be permitted for use, with different emphasis on each depending which regulator controls the waters. This has become the motivation for the research into modifying old chemistries and developing new ones.

Quaternary amines (quats) have been known for a long time as excellent corrosion inhibitors for their ability to form a film on the surface of the steel; however, their biotoxicity profile is not particularly acceptable to qualify them as "Green Corrosion Inhibitors". This work covers the structural modifications that have been imparted on quats to qualify them as green corrosion inhibitors with excellent corrosion protection.
Uncertainty Modeling of the Gas Volume of Manati Field: The Challenge of Taking Into Account a 'Stochastic' Unconformity
Authors: Filho P. C. S. , Monteiro M. C. , Gonçalves P.
Published: December 2007

An uncertainty analysis study of the gas volumes in the field of Manati was conducted using gOcad™/Jacta™. The main uncertainties are associated to two important lateral limits of the reservoir, both ill-defined due to the poor quality 2D seismic lines available: the geometry of a major regional unconformity, and the Mutá fault.

A number of alternative realizations of the conjugated unconformity/Mutá fault surface were generated, using four seismic interpretations. A p-Field-like algorithm was used to sample from a probability function locally taken as a trapezoidal pdf, defined by four sub parallel envelopes built from the four interpretations available.

An artifice was conceived in order to overcome a deficiency of the software for dealing with multiple alternative lateral extensions of the model. This artifice consisted in modeling the grid with an extension taken as a maximum, and then computing only the volumes of interest by informing Jacta™ a number of alternative possible realizations of the unconformity/Mutá fault surface, as if they where gas/oil contact scenarios.

Accordingly, the real gas/water contact was given to Jacta™ as if it were an oil/water contact. Thus, with the corresponding fluid parameters informed in a coherent way, the gas volumes of interest where reported by Jacta™ as oil volumes.

Other sources of uncertainty where taken into account by means of Jacta's regular workflow.