bluuebunny/crossref_metadata_2025 huggingface dataset:
History Matching and Production Forecast Uncertainty by Means of the Ensemble Kalman Filter: A Real Field Application
Authors: Bianco A. , Cominelli A. , Dovera L. , Naevdal G. , Valles B.
Published: December 2007

During history match reservoir models are calibrated against production data to improve forecasts reliability. Often, the calibration ends up with a handful of matched models, sometime achieved without preserving the prior geological interpretation. This makes the outcome of many history matching projects unsuitable for a probabilistic approach to production forecast, then motivating the quest of methodologies casting history match in a stochastic framework.

The Ensemble Kalman Filter (EnKF) has gained popularity as Monte-Carlo based methodology for history matching and real time updates of reservoir models. With EnKF an ensemble of models is updated whenever production data are available. The initial ensemble is generated according to the prior model, while the sequential updates lead to a sampling of the posterior probability function.

This work is one of the first to successfully use EnKF to history match a real field reservoir model. It is, to our knowledge, the first paper showing how the EnKF can be used to evaluate the uncertainty in the production forecast for a given development plan for a real field model. The field at hand was an on-shore saturated oil reservoir. Porosity distribution was one of the main uncertainties in the model, while permeability was considered a porosity function.

According to the geological knowledge, the prior uncertainty was modeled using Sequential Gaussian Simulation and ensembles of porosity realizations were generated. Initial sensitivities indicated that conditioning porosity to available well data gives superior results in the history matching phase. Next, to achieve a compromise between accuracy and computational efficiency, the impact of the size of the ensemble on history matching, porosity distribution and uncertainty assessment was investigated. In the different ensembles the reduction of porosity uncertainty due to production data was noticed. Moreover, EnKF narrowed the production forecast confidence intervals with respect to estimate based on prior distribution.
Successful Application of a Robust Link To Automatically Optimise Reservoir Management of a Real Field
Authors: Al-Khelaiwi F. T. , Davies D. R. , Tesaker Ø. , Straub R. , Barrett R. K.
Published: December 2007

Realistic modelling is essential for both the planning and the optimal operation of Oil and Gas Fields. Such a model for modern well or field development architecture requires coupling of the reservoir simulator with the well/surface facility network model when making choices as to the reservoir and production management strategies to be employed. Such close coupling is not, currently, readily available; particularly when the reservoir simulator, the well/surface facility simulator and, potentially, the optimiser programs are provided by different suppliers.

We have had the opportunity to test a newly developed "link tool" to integrate the reservoir simulation model with a subsurface/surface network model, allowing (automatic) optimisation of the full network performance. The tool supplies the simulation results to the surface network simulator/optimiser, which in turn, reconfigures the intelligent well completion zones by use of Individual Control Valves (ICVs) and wellhead or manifold in order to maximise the total production against the well and facility constraints. The network targets are then returned to the reservoir simulator in a simple manner at each time step.

The authors have used the S-Field over a number of years which proved to be a very suitable case study for illustration of the value of "Intelligent" Field development techniques. This paper discusses the automatic, optimal control of the S-Field's five intelligent production wells by application of a "link tool" (Supplier 1) to couple the reservoir simulator (Supplier 2) with a surface network modeller and optimiser (Supplier 3). N.B. The latter two suppliers are among the market leaders within their segments.
First Experience in the Application of Radial Perforation Technology in Deep Wells
Authors: Cirigliano Raúl Andrés , Talavera Blacutt Juan Felipe
Published: December 2007

This paper describes the first application of radial perforation technology with hydraulic jet and coiled tubing in deep wells with complex geometry.

Radial perforation technique utilizing hydraulic energy is being used in different places around the world with good results. Its main application is intended for marginal fields, with low productivity and shallow wells with depths between 1000m and 2000m, normally having simple geometry. Basically, several perforations can be made with this technology, in an existing well (mother well), perpendicular to the well axis and at several productive levels, thus improving the production profile around the main well or mother well.

Repsol YPF Bolivia has adopted this technology to perform a pilot test in fields with good to moderate recovery and in deep wells with complex geometry (directional wells with depths between 3500m and 3900m).

This operation was performed in three wells (Surubi A1, Paloma C7 and Surubi Bloque Bajo 109) in the Mamore Block in Bolivia.

The main challenge for this operation was to adapt equipment and tools used up to that time, to much more severe operational conditions due to greater depths, tortuosity, type of formations to be drilled and mechanical conditions of the wells.

The main subjects covered by this paper are: IntroductionCharacteristics of the reservoir and objectives for the application of this technology.Geometrical and mechanical characteristics of the wells. Operative results.Description of the equipment and main adaptations to new operative conditions.Main problems encountered. Solutions. Operative limitations.Conclusions.

The results indicate that this technology may continue being an attractive substitute for other stimulation techniques, such as fractures, acids, side tracking, etc, even with higher costs implied by its application to complex wells and with the improvements that will definitively be applied to current tools and equipment
Casing and Liner Drag Forces as Design and Analysis Parameter for Complex Architecture Wells
Authors: Ciccola F. , Vicente L.
Published: December 2007

Frictional load losses during the tubular running into a wellbore are strongly associated with the well design. In complex architecture wells design, the drill string drag force is one of the most important analysis parameter. However, casing and liners drag forces are not proper considered, although differences between these types of pipes and the drill string can lead to significant changes in drag load levels.

In this work, the influence of drag forces over casing and liner strings used in complex architecture wells is demonstrated. The study shows a numerical treatment of the problem and its validation through a model which calculates drag forces over the casing during running. In this way the prevalence of casing and liner drag forces as design parameter to be considered in conventional methodologies is demonstrated. The model involves stress and displacement calculations, using a recursive method, wich considers pipe discretization, stiffness of each pipe's element, and centralizer effects.

The validation of the developed model was carried out with three wells located in the Santa Rosa field, Venezuela. The obtained calculations agreed with the actual values of hook loads, even in cases where the pipe got stuck, showing the model advantages for the design and analysis of complex architecture wells.
Implications of the Phase-Solubility Behaviour on the Performance Predictions of the CO2 Trapping in Depleted Gas Reservoirs and Aquifers
Authors: Ülker B. , Alkan H. , Pusch G.
Published: December 2007

The phase behaviour modelling of gaseous/super critical CO2 mixtures with reservoir brine exhibits constraints regarding thermodynamical complexity of the system as well as insufficiencies in computing approaches. The modelling of physical properties of mixtures of CO2 with CH4 in a depleted gas reservoir is not problematic. In this study a generic reservoir model was created with the aid of a commercial reservoir simulator ECLIPSE, which uses different approaches on modelling the phase behaviour of CO2 containing geological systems. The model reservoir, adapted to storage properties of real cases, was assumed to be infinite acting, homogenous and isothermal. A constant rate of CO2 injection was considered. The critical saturation for the flow of gas and water, salinity and brine composition as well as the permeability anisotropy were defined as main parameters influencing the solution trapping of CO2. The chemical interactions between the system components as well as the hysteresis effects of mechanical trapping were neglected.

The phase/solubility calculations are most critical for the prediction of solution trapping capacity of the aquifers. The migration capacity of the higher density plumes is dependent on the solubility modelling of CO2 in brine. The results indicate an obvious sensitivity to the varying solubility of CO2 in various types of brines (NaCl, CaCl2) with changing salinities. The ratio of vertical to horizontal permeability (kv/kh) has a significant effect; at low kv/kh CO2 tends to migrate laterally, whereas an increase in this ratio enhances the vertical gas migration leading to more CO2 dissolution trapping.
A General Approach for Asphaltene Modeling
Authors: Sánchez Néstor L.
Published: December 2007

This paper describes a complex volatile oil reservoir fluid characterization process to develop an equation of state for compositional reservoir fluid simulation modeling of the asphaltene flocculation-precipitation phenomena, including the impact on rock permeability.

The process consist on lumping the available fluid sample composition into five components, in order to split the heaviest component into its paraffinic, naphthalene, and aromatic constituents being an important part of solid precipitation, which generally form wax and the heaviest aromatic is the major constituent (Ref. 1). As consequence results a composition with seven components used to reproduce the available experiments.

The multiphase flash experiment simulation at different temperatures, allow reproducing experimental data from isothermal depressurization of the fluids, determining the asphaltene appearance and disappearance pressure, by observing the behavior of each component on the liquid phase with pressure. The beginning of the increase in the slope of the curve indicates an increase of the asphaltene content on the liquid phase. As consequence, reservoir and facilities plugging may be anticipated.

Based on the results of the core oil injection experiment, the effect of reservoir pressure reduction on core permeability to oil was reproduced, observing important formation permeability reduction in good to intermediate quality reservoir regions. This is modeled by modifications of the rock compaction, pore volume and changes on transmissibility with pressure.

Sensitivities to different reservoir modeling strategies allow to observe the critical time during the reservoir depletion live, indicating the necessity of maintaining the reservoir pressure above the point at the beginning of maximum increase of the slope of the curve of asphaltene evolution on the liquid phase.
Understanding Flow Paths—New Opportunities From Time-Lapse Seismic Data
Authors: Thedy E. A. , Salomão M. C. , Corá C. A. G. , Santos M. S. , Pumputis A. , Gomes R. M. , Caletti L.
Published: December 2007

After producing 400 million barrels of oil along the last five years, Marlim Sul field, situated in Campos Basin, Brazil, applied its first time-lapse seismic acquisition. The oil is being produced from six different reservoirs, each one with different characteristics. The main common point of them is the water drive mechanisms, and therefore the flow path of the injection water is the prime purpose of this 4D action. Almost all producers have seen the breakthrough of water, sometimes after the forecasted time, sometimes before. The seismic data were acquired by a streamer steering system and received special attention in terms of velocity analysis and crossequalization process. The preliminary analysis indicates some interesting conclusions. The water path seems to be less regular than expected from flow simulation and indicates a trend in rock permeability. This knowledge allows a better match of the model, and a better control of production and injection rates. In addition, some areas are less flooded than expected, wich permits the proposal of new infill drillings, in order to recover this additional oil, depending on the economic analysis, as well as a new infill well, proposed before the acquisition, is not in the better position, and may be relocated or cancelled. Furthermore, the communication of two blocks, situated one above the other, was strongly suggested by the presence of an anomaly related to increase of gas saturation in the higher block derived from the depletion of the lower one. These simple conclusions reveal the power of time-lapse seismic acquisition, and evidence the importance of a permanent reservoir monitoring for the optimization of recovery factor and the profitability of the exploitation project.
A Gun Jump Model for Underbalance Perforating
Authors: Zazovsky Alexander , Zhan Lang , Kusumadjaja Aming , Chewyam Johan Komarudin
Published: December 2007

A new methodology for evaluating the risk of gun jump during post-perforating surge is proposed and tested against field data. This methodology is corroborated by an advanced mathematical model of transient flow into the wellbore triggered by the creation of perforation tunnels under static underbalance and fully coupled with evolving transient flow inside the wellbore containing the gun string. The model predicts the viscous drag on the tool string and the gun string dynamics, which may induce cable tangling or breaking owing to gun jump. This model is used to mitigate the risk of gun jump by varying perforating job design options such as shot density, thickness of the perforated interval, and height of the liquid cushion. Examples of model application to the analysis of field data from Indonesia are provided.
Improved Convergence Efficiency in an Assisted-History-Matching Experiment
Authors: Keating James F. , Ozdogan Umut
Published: December 2007

This study is an attempt to justify the increased performance of an assisted history matching experiment with plausible concepts. These concepts were based on patterns within the error vector (the unique distributions of the error components).

The observed patterns were very similar to patterns seen while using Error Surface Analyses (ESA) to manually history match models. ESA is the animation of errors at their respective spatial locations though time. This error analysis can easily identify locations or times with high errors. During manual history matching with ESA, the efforts are placed on removing the highest errors. In this automatic history matching experiment, the same systematic approach was found when the convergence efficiencies were high.

In this experiment, a simple parametric search routine was used to compare the performance of a data weighted (DW-L2) to an equal weighted (EW-L2) objective function. The data weighted objective function tended to reduce the highest errors first. Results of multiple history matching trials showed that the automatic history matching became more efficient (less simulations) when the data weighted objective function was used. The comparison was made using a conceptual reservoir with ten years of production history under a peripheral water injection. The uncertainties associated with the synthetic reservoir were, (1) the number and sealing capacity of the faults, (2) permeability magnitude, (3) net-to-gross, (4) vertical to horizontal permeability ratio, and (5) relative permeabilities.
Change in Patterns in the Application of a Vertical Drilling System (Stabilized Drilling System) VDS in the Basin of the Gulf of San Jorge
Authors: Speranza Cesar , Fontana Adrián , Marquez Hugo , Crovetto Marcelo , Wallace Cameron
Published: December 2007

This paper will present case histories of the successful development of a novel stabilized drilling system developed to reduce drilling time and improve drilling program economics in wells drilled in the basin of the Gulf of San Jorge.

A program of drillstring stabilization was developed that combines technologies proven in other drilling applications, with the goal of reducing maneuvering time, drill-bit changes, and time spent on well logging while improving wellbore quality. Substantial improvements in the wellbore gage quality and reduced tortuosity contributed to reduction in trip times, better wellbore calipers, increased ROP with fewer bits used, no electrical logging set up incidents, and no incidents in subsequent casing and cementing operations.
Modeling Two-Phase Flow in Porous Media With Consideration of Jump Interfaces
Authors: Peng Xiaolong , Du Zhimin , Liang Baosheng , Qi Zhilin , Wang Wei
Published: December 2007

Discontinuities of rock and fluid properties are very common in the reservoir due to variations of formation lithology and oil-water gravity differentiation. Fluid discontinuity also exists at the water front in the water-flooding reservoir. Interfaces with discontinuous fluid properties are called jump interfaces. It is known that fluid flow at these jump interfaces is neither continuous flow, which is dealt with conventional multiphase flow model in porous media, nor purely piston-like drive, which is the problem of dynamic interface tracking. In practice, however, by neglecting jump interfaces, fluid flow is widely treated as continuous flow by adding relative permeability into each phase equation in black oil simulation. Also, single-point upstream weighting and high order schemes have no improvement on flux rate and moving speed of phase interfaces.

This paper starts from analyzing two-phase flow with consideration of jump interfaces. In porous media, flow channels of oil and water are relatively stable at low rates: one fluid always takes first priority of displacing the same type of fluid and then displaces the other fluid when the channels of the same type of fluid are not sufficient. Therefore, the flow of a specified fluid through jump interfaces includes two parts: displacing the same type of fluid and displacing the other type of fluid. Based on this analysis, we develop a new two-phase flow model, considering discontinuities of flow properties. Unlike currently available flow models, our model takes account the effect of one fluid displacing the other fluid across jump interfaces.

We apply to a 1-D case and compare with Buckley-Leverett equation. The example demonstrates that our new model has more capabilities to describe the physical flow at the jump interface. We also discuss applications of our model on connection condition construction for jump interfaces in the numerical model and relative permeability measurements.
Developing and Field Implementation of a State-of-the-Art BHA Program
Authors: Chen David C-K.
Published: December 2007

This paper presents the development and field implementation of a state-of-the-art bottomhole assembly (BHA) program using the industry's first generic algorithm based on Lubinski's equations. The strengths of the new BHA program are accuracy and computation efficiency, as compared to the conventional finite-element based BHA programs. In addition, the new program integrates static and dynamic models so that users can run both models in the same application. Using the new algorithm, the static model is designed mainly for directional drilling applications, such as optimal BHA design for maximum steerability, bending moment calculations to minimize fatigue failure, and BHA sag corrections to improve survey quality. The dynamic model is based on a hybrid of analytical and finite-element methods to calculate the critical rotary speeds of the BHA. This paper describes the significance of applying these features in a user-friendly application to maximize drilling performance.
Dynamic Nodal Analysis in Well Testing Interpretation
Authors: Schindler Miguel H.
Published: December 2007

In well testing, the subject of study is composed by the reservoir, wellbore and piping.

The traditional well testing interpretation approach focuses in the transient behavior of the pressure inside the reservoir. Flow rates are considered input information; generally assumed instantaneously constant during each flow period.

On the other side, the traditional nodal analysis concentrates in the pressure drops inside the wellbore and pipelines reducing the behavior of the reservoir to a pseudo-stationary state.

These simplifications can be applied for a limited period of time in high potential wells.

However, especially in low potential wells, the productivity index varies continuously, flow rates can not be approximated by constant values; the effects of liquid loading, slugging, and other regimes of multiphase pipe flow affect decisively the conditions in the reservoir. Understanding system's operation implies the analysis of every component and the relations between them.
Advances in After Closure Analysis for Naturally Fractured Reservoirs
Authors: Uribe O. , Tiab D. , Restrepo D. , Chipperfield S.
Published: December 2007

Using the theory of impulse testing and principle of superposition, Nolte et al [1] developed a method which allows the identification of radial flow and thus the determination of reservoir transmissibility and reservoir pressure. The exhibition of the radial flow is ensured by conducting a specialized calibration test called mini-fall off test. Benelkadi and Tiab [2] proposed a new procedure for determining reservoir permeability and the average reservoir pressure in homogeneous reservoirs. In this paper, the procedure is extended to naturally fractured reservoirs.

A new method for the determination of reservoir transmissibility using the after closure radial flow analysis of calibration tests was developed based on the pressure derivative. The primary objective of computing the pressure derivative with respect to the radial flow time function is to simplify and facilitate the identification of radial flow and the characteristic trough of a naturally fractured reservoir. The proposed method does not require a-priori the value of reservoir pressure. Only one log-log plot is used to determine the reservoir permeability, average pressure, storativity ratio, and interporosity flow coefficient.

The technique is presented as a step-by-step procedure, with appropriate equations and graphs. The log-log diagnostic plot of pressure and the pressure derivative is employed here as the main tool to identify the radial flow regime and determine properties of a naturally fractured reservoir (i.e. permeability, interporosity, storativity ratio, and average reservoir pressure). The application of the proposed method is demonstrated on real field data from calibration tests.

The main conclusion of this study is that small mini-fracture treatments can be used as an effective tool to identify the presence of natural fractures and determine reservoir properties.
Permeability Estimation Using Hydraulic Flow Units in Carbonate Reservoirs
Authors: Bagci A. Suat , Akbas Ceylan Yildirim
Published: December 2007

This study focuses on the evaluation of formation permeability for a carbonate reservoir from well logs and core data using the concept of flow units. Characterization of carbonate reservoirs by flow units is a practical way of reservoir zonation. The study represents a petrophysical-based method that uses well loggings and core plug data to delineate flow units within the most productive carbonate reservoir of Derdere Formation in Y field, Southeast Turkey. Derdere Formation is composed of limestones and dolomites. Logs from the 5 wells are the starting point for the reservoir characterization. The general geologic framework obtained from the logs point out for discriminations within the formation. 58 representative core plug data from 4 different wells are utilized to better understand the petrophysical framework of the formation. The plots correlating petrophysical parameters and the frequency histograms suggest the presence of distinctive reservoir trends. These discriminations are also represented in Winland porositypermeability crossplots resulted in clusters for different port-sizes that are responsible for different flow characteristics. Although the correlation between core plug porosity and air permeability yields a good correlation coefficient, the formation has to be studied within units due to differences in pore-throat sizes and reservoir process speed.

Linear regression and multiple regression analyses are used for the study of each unit. The results are performed using STATGRAPH Version Plus 5.1 statistical software. The permeability models are constructed and their reliabilities are compared by the regression coefficients for predictions in un-cored sections.

As a result of this study, 4 different units are identified in the Derdere Formation by using well logging data, and core plug analyses with the help of geostatistical methods. The predicted permeabilities for each unit show good correlations with the calculated ones from core plugs.
Successful Application of a High Temperature Viscoelastic Surfactant (VES) Fracturing Fluids Under Extreme Conditions in Patagonian Wells, San Jorge Basin
Authors: Fontana Cristian , Muruaga Enrique , Perez Daniel , Cavazzoli Gustavo , Krenz Angeles
Published: December 2007

The San Jorge Basin is characterized by multilayer formations requiring proppant fracturing as a completion method in order to achieve oil production at commercial levels. As fields are arriving to a mature stage they require continuous improvements with regards to fracturing techniques.

Typically viscous polymer based fluid had being used with acceptable results for proppant transport and fracture placement; however these fluids are known to generate undesired effects such as uncontrollable height growth, significant proppant pack damage, lengthy clean up times and high friction pressures.

In recent times, polymer-free viscoelastic surfactant-based (VES) fluid systems have been introduced in the industry as an improvement over polymer-based fluid. Nevertheless, VES were known up to now, for their limitation to withstand elevated temperatures. Detail laboratory studies proved that a novel VES high temperature (HT) version was also feasible for the given conditions of this high temperature formation. Since the reservoir temperature exceeded the technical limits of even this HT fluid, simulations indicated that a series of cool-down brine stages would allow the application of this fluid at this temperature (280F). The characteristic of the fluid allowed the treatment to be confined in the limited layer thickness between weak barriers avoiding growth into water - or non - productive zones, resulting in reduced fluid and proppant volumes. Field implementation proved also to be successful in terms of operational simplicity, reduced clean up time and consequently work over rig cost savings. Overall, the use of polymer-free fluids improved well productivity. Design, laboratory studies, temperature simulations confirmed by downhole measurements, field implementation and results of the first VES HT fluid application in the El Tordillo field are presented in this paper. Four different zones were successfully treated in the first well application at various reservoir conditions presenting a wide range of permeability and temperatures.
Surveillance Planning: The Key to Managing a Mature Gas Reservoir
Authors: Samsundar Kamal , Moosai Roshni , Chung Ronald
Published: December 2007

The Mahogany field in Trinidad and Tobago was developed as a dedicated gas field with reserves of 2.6 TCF to supply gas to the Atlantic LNG Plant in 1999. The reserves are deposited in a number of stacked sands, all of which must be optimally produced in order to achieve a successful depletion of the field. To date over 1 TCF has already been produced through a rigorous depletion management system and a renewed effort has been made to ensure that the remaining reserves are not at risk as the field enters the mature stage of its development.

One of the foundation processes that were used in the development of the field was that the right level of surveillance existed and maintained. Acquiring the right surveillance data was considered when designing the wells and facilities. In fact the field is operated in a manner that ensures surveillance data is collected when required, without compromising production or plant integrity. The result of this rigorous surveillance planning and the application of data collected have provided the assurance around delivering the remaining Mahogany reserves.

This paper will discuss the importance of surveillance planning as it relates to maintaining the base production as well as the key issues that should be addressed when forming a surveillance plan. It will also highlight the successes of proper surveillance planning as well as the actions that can be taken to overcome the challenges faced when developing a surveillance plan.
Monitoring and Controlling Paraffin Deposition by a Direct Assessment Technique
Authors: Gomez D. Carlos I. , Medina F. Eduardo J. , Patiño Edgar
Published: December 2007

This paper presents the results of the evaluation of paraffin control treatments applied in rod pumped wells in La Concepcion oilfield, located at the western of Venezuela and operated by Petrowayuu, which is a mature field with paraffin deposition problems.

Before the study, the only treatment applied on the wells to control paraffin deposition was hot watering. Because the average production rate of the wells was 30 BFPD, the application of high volume treatments, as hot watering, implied production deferral due to their low productivity index (around 0.09 BFPD/psi).

Paraffin dispersant cold batch was used as an alternative treatment. To assess the effectiveness of the paraffin control treatments and their optimal application frequencies, it was necessary to use scale coupons observation, flowline pressure monitoring, and dynamometer cards analysis.

It was found that paraffin dispersant cold batch treatment resulted to be the most cost-effective way to control the problem in all of the wells evaluated and the optimal batch treatment frequency was determined for each well. Moreover, most of the wells had been treated in a very low frequency. Besides this, it was demonstrated that circulation of high volume of hot water generated production deferral.

This enabled Petrowayuu to increase its earnings in approximately 500,000 U.S. $/yr, compared with hot watering costs, mainly because of production deferral reduction.
Greater Plutonio Open Hole Gravel Pack Completions: Fluid Design and Field Application
Authors: Whaley Kevin , Price-Smith Colin , Twynam Allan , Jackson Phillip
Published: December 2007

Initial Open Hole Gravel Pack (OHGP) completions that have been installed in Greater Plutonio to date have all achieved complete annular packs and zero mechanical skin factors, resulting in well productivity indices that are significantly greater than expected.

The success of the Greater Plutonio OHGP completions has been attributed primarily to the rigorous design and field application of the fluid systems used at all stages of the well from drilling the reservoir through to the gravel pack itself and subsequent completion. An integrated approach was adopted for the design of the fluid systems involving extensive formation damage and fluid compatibility testing. To translate the robust design into a fluid system which can be applied effectively in the field, a thorough, fit for purpose QA/QC system for all drilling and completion fluids was developed, requiring extensive fluids testing and reporting at the well site.

The paper describes in detail the reservoir completion philosophy, drilling and completion fluids' systems and overall operational practices used in the Greater Plutonio OHGP completions. It also discusses the fluids design phase of the project and the QA/QC processes implemented in the field. Finally the paper presents the well productivity data from the wells completed to date.
Dual Lateral Horizontal Well Drilled Underbalanced in a Depleted Reservoir in Libya—Case Study
Authors: Safar Hussein , Azhary Sadek , Hijazi Ahmad , Qutob Hani , Chopty James , Pham Chau
Published: December 2007

The B24 well in the Fidaa Field was the first dual lateral underbalanced horizontal well drilled in Libya and the second well of Zueitina Oil Company's (ZOC) underbalanced drilling campaign.

The targeted reservoir "Facha" is partly depleted after 23 years of production to a 7.2 ppg equivalent mud weight. Nitrified diesel, a two-phase drilling fluid, was used to drill the reservoir section of the B24 underbalanced to avoid circulation losses and formation damage. Real time LWD was crucial for geosteering the well path in a complex reservoir structure and real time annular pressure measurement was also necessary to ensure the underbalanced condition was maintained throughout the entire UBD drilling phase.

Two 6" horizontal drains were drilled successfully with 2053' and 1517' drain lengths. Integrated efforts of ZOC and service companies of various disciplines during planning and operation stages of the well led to the success of the project. No QHSE incidents were reported and the productivity of the well was enhanced significantly.

The B24 well's production alone contributes to over 30% of the total Fidaa field production.
Powder River Basin Coalbed Methane Wells—Reserves and Rates
Authors: Swindell Gary S.
Published: December 2007

Coalbed methane has become a significant source of U.S. natural gas production, contributing 9% of the country's supply and 10% of its proved reserves. The most active coalbed methane area is the Powder River basin of eastern Wyoming, with more than 20,000 wells completed in the last 10 years with annual additions of greater than 2,000 wells.

This study analyzed the projected ultimate recovery, flow rates and dewatering time of 6,600 wells producing from the Wyodak and Big George coal zones – the source of 58% of the basin's cumulative production, 61% of the current production and 45% of the CBM wells.

For the Big George and Wyodak wells, the estimated ultimate recovery (EUR) averages 223 million cubic feet (MMcf) per well (median 168 MMcf). An average peak gas rate of 319 thousand cubic feet per day (Mcf/D) (median 236 Mcf/D) occurred an average of 1.2 years after the well was placed on production. The average well declined at a rate of 45% per year after entering the decline phase with very little hyperbolic behavior (average b = .09). Distributions of EUR and peak rates were strongly log-normal.

The EUR and peak gas rates both show a slight overall deterioration over time, although the "spread" is larger with more high rate wells in later years. But the time to reach peak gas rate is shortening as more areas are dewatered.

There seems to be only a slight correlation between total depth and EUR and little correlation between gross perforated interval and estimated ultimate recovery or peak rate, although the perforated interval information is very incomplete.

Development of Powder River basin coalbed methane has an average finding cost of $.71/Mcf, and the mean well has a return-on-investment of 4.70:1 and a net present value index of 3.74, assuming a base gas price of $6.50/Mcf minus $1.50/Mcf for market differential and transportation.
Hydraflow: Avoiding Gas Hydrate Problems
Authors: Haghighi H. , Azarinezhad R. , Chapoy A. , Anderson R. , Tohidi B.
Published: December 2007

Flow Assurance continues to remain a major challenge in offshore production operations. Current methods for avoiding gas hydrate problems are generally based on one or a combination of the following three techniques: (1) injection of thermodynamic inhibitors (e.g. methanol, ethylene glycol) to prevent hydrate formation, (2) use of kinetic hydrate inhibitors (KHIs) to sufficiently delay hydrate nucleation/growth, and (3) maintaining pipeline operating conditions outside the hydrate stability zone by insulation and/or active heating and/or by controlling pressure.1 However, for many production operations, particularly deepwater fields, those requiring long tiebacks, and mature reservoirs (where water cuts can be very high), the above techniques may not be economical and/or logistically practical. Thus the industry needs novel and improved techniques to tackle flow assurance problems for such challenging conditions. The new approach presented in this paper –HYDRAFLOW– aims to meet this need.

HYDRAFLOW is a novel ‘cold flow’ concept, which breaks from the tradition of straightforward hydrate prevention. Instead, gas hydrate formation in pipelines is intentionally induced and managed, eliminating the need for expensive thermal/chemical inhibition while improving the economics and practicalities of multiphase fluid transport.

Experimental analyses of low and high GOR systems for various different production scenarios with and without AA (Anti-agglomerant) have been undertaken as part of HYDRAFLOW concept development. The effect of simulated shut-in on fluid transportability has also been tested. A new experimental set-up for measuring the viscosity of the fluid system under high-pressure conditions has been designed and commissioned in order to evaluate the rheology of the systems under investigation.

Results prove that the concept is viable (at least under laboratory conditions), and strongly suggest that HYDRAFLOW technology could offer significant benefits over existing flow assurance strategies, providing a novel low CAPEX/OPEX solution for challenging (e.g. deepwater, long tie-backs, mature fields) operations.
Massive Hydraulic Fracturing Unlocks Deep Tight Gas Reserves in India
Authors: Shaoul Josef , Ross Michael , Spitzer Winston , Wheaton Stuart , Mayland Paul , Singh Arvinder Paul
Published: December 2007

Tight gas fracturing was pioneered in North America in the 1970's and 1980's, and also has a relatively long history in Germany. In the rest of the world, however, massive fracturing for production from tight gas formations (i.e. k < 0.1 mD) has been very rare, due mainly to poor economics, rather than lack of opportunities. A massive oil field was recently discovered in Rajasthan (northwest India). The field development would require significant amounts of natural gas for heating and processing of the waxy oil to be produced. The most economical solution to provide sufficient gas in this remote desert location was to produce it from a deeper formation discovered in the same area. The majority of the gas is contained in a volcanic section of basalts and felsics. A fracturing campaign was performed in 2006 on three deep gas wells to evaluate the post-stimulation production increase from a number of different horizons, with base formation permeabilities varying from 0.005 to 0.15 mD.

A comprehensive program of core testing, fluids compatibility testing and pre-fracture diagnostic injections was performed. Fracture stimulation treatments were performed in three different sections of this very thick gas-bearing formation (> 400 m gross height). The formations ranged from the highest permeability (0.15 mD) Fatehgarh sandstones, to a lower permeability Felsic section (0.05 mD) and the lowest permeability volcanic rock (0.005 mD). All three types of rock were stimulated successfully and post-fracture well testing showed initial production rates agreeing with what was expected based on reservoir simulation. This important result supports the proposition that unconventional gas resources in Asian countries can be attractive when stimulation techniques perfected in other areas (i.e. North America) are applied1.
Identifying, Correcting, and Allocating Geodetic Systems to Georeferenced Data in Hydrocarbon Exploration by Using High-Resolution Satellite Imagery
Authors: Alvarez Gabriel
Published: December 2007

Introduction

Hydrocarbon exploration in Argentina started long before the IGM created a single, high-precision geodetic reference network for the whole country.

For that reason, several geodetic surveys were conducted in every producing basin, which have ever since then supported land surveys, well placement, seismic programs, etc.

Currently, every basin has a huge amount of information referenced to the so-called "local" geodetic systems, such as Aguaray in the Northwestern Basin, 25 de Mayo in the Cuyo Basin, Quiñi-Huao in the Neuquén Basin, Pampa del Castillo in the San Jorge Basin, and Tapi Aike in the Austral Basin, which differ to a greater or lesser extent from the national Campo Inchauspe datum established by the IGM in 1969 as the official geodetic network.

However, technology development over the last few years and the expansion of satellite positioning systems such as GPS resulted in a new world geodetic order.

Argentina rapidly joined this new geodetic order through the implementation of a new national geodetic system by the IGM, i.e. the so-called POSGAR network (Fig. 1), which replaced the old national Campo Inchauspe system. However, this only helped to worsen the data georeferencing issue for oil companies, as a third reference system was added to each basin. Now every basin has a local system, the national system in force until 1997 (Campo Inchauspe), and finally the newly created POSGAR network national satellite system, which is geocentric unlike the former two planimetric datums.
A Bayesian Production Analysis Technique for Multistage Hydraulically Fractured Wells
Authors: Vega Leonardo
Published: December 2007

Wells in tight gas reservoirs are often completed with multiple stages of hydraulic fracturing. Eventually, each stage contributes to the commingled well production.

This paper presents a stochastic analytic production analysis technique for multistage hydraulically fractured wells*. Based on Bayes's theorem, the new technique integrates production performance data, production logs, and prior information to arrive at the most probable description of the reservoir/completions.

After validating results with a numerical reservoir simulator, we systematically used the new technique to investigate the effect of data availability, i.e. the number of production logs and duration of production period, on the accuracy of the results.
Technical Integrity Assurance of Unmanned Wellhead Platforms for Safe Well SIMOPS
Authors: Ciaraldi Stephen , Utama Satria , Dewi Natalie S. , Sulistyorini R. , Lubis M. Syafei
Published: December 2007

BP West Java offshore operations include over 140 unmanned wellhead platforms which are frequently the sites of infill drilling and workovers using jack-up rigs. Although operational SIMOPS controls have been systematic for years, only recently has attention been directed towards the technical integrity of the platforms themselves. Most of the unmanned facilities are over twenty years old and of variable condition. Potentially severe consequences could result from a platform hydrocarbon leak during SIMOPS, made worse by the high density of drilling personnel working on site and in the rig offices and accommodations.

For this reason, a program was instituted to assure the technical integrity of unmanned wellhead platforms as a prerequisite for well SIMOPS. The work program includes thorough inspections of platform hydrocarbon pressure systems, including attached risers, as well secondary structures such as gratings, hand-rails and stairs, process safety protective and other critical electrical and instrument systems. When necessary, time consuming repairs must be executed before SIMOPS, but in some cases, mitigations are sufficient based on a risk-based rationale. The program has been a considerable challenge to implement due to the hectic pace of well operations, but has certainly reduced major accident risks associated with SIMOP activities and therefore resulted in a safer work environment.
Radial Drilling in Argentina
Authors: Bruni M. , Biasotti H. , Salomone G.
Published: December 2007

With a world context of high oil prices and a rate of increase in reserves from new discoveries, that is not enough to compensate the rate of extraction, in addition to the high maturity of oilfields currently being developed in Argentina, companies have been working to improve the recovery factor of reserves, as a strategy to extend the useful life of the existing assets.

Working in this direction, radial drilling technology seems to be an alternative, which, in spite of the fact that it currently raises uncertainty since it has never been tested in the past in or country, can be adapted to the existing wells thus becoming a low investment alternative.

The technology involves drilling lateral horizontal bores of small diameter and up to one hundred meters long, with the possibility of placing several within the each productive layer. The laterals are made in two steps: First, the casing is perforated with a ¾" mill and then the lateral extension is carried out by high pressure water jetting.

For this evaluation, pilot tests were performed in different oilfields, with the intention of covering a wide range of possible scenarios and being able to evaluate the best applications for this new alternative.

The selected scenarios and the different basins are the following:

Golfo San Jorge Basin:

Mature Oilfields: already exploited formations with production below the economic limit. Viscous Oils: Formations with high viscosity oil and low mobility.

Neuquén Basin:

Mature Oilfields: low production formations Precuyano Formation (altered ignimbrites) of low permeability, with possible micro-fissures to improve net production. Water Injection: To increase secondary recovery improving the sweeping of the formation.

This work shows the different experiences undergone by Repsol YPF in Argentina with this technology as well as shares the results obtained and the lessons learned.