bluuebunny/crossref_metadata_2025_split huggingface dataset:
Infill Well Modelling in Reservoirs with Multiple History-Matched Descriptions: Case Studies from Andrew and Harding
Authors: Walker Greg J. , Skinner Roger , Litvak Michael 
Published: December 2007

AbstractThe task of selecting and planning infill wells is critical to the ultimate recovery of hydrocarbons from a field, and in a mature basin we have progressed down the long tail of targets to the numerous but small opportunities. There is considerable value left in such targets, even with current drilling technology, but the targets require a better understanding of risk and a higher level of detail. We also face the difficulty this has to occur at a time when the industry is constrained by people resources and rig availability.The Andrew and Harding assets have been leading members of a field trial of a system to test large numbers of alternative depletion plans to try and find the optimum for economic impact and recovery. The assets have also been early adopters of the recent advances in computer assisted workflows, using tools such as BP's TDRM1 in history matching mode to generate alternative reservoir descriptions that satisfy observations and has some measure of the range in possible outcomes.This paper presents the results of combining infill well planning and multiple reservoir descriptions in a computer-assisted workflow of Top Down Depletion Planning (TDDP)2. The results have enabled smaller targets to be sanctioned, as there has been a better understanding of the risk. Furthermore, instead of appraising three targets in five months of effort, it has enabled the appraisal of seven targets to the same level of detail in only two months of effort, a factor of 4 increase in efficiency for the subsurface team.The case studies have also forced advances in the data analysis, to understand how the infill wells and the alternate reservoir models interact. We can make the choice to seek the optimum choice of things that we can control, such as the depletion plan, on the average performance across the multiple reservoir models that we can't control, but we can use surveillance to try to distinguish between models if we can identify the surveillance prize.The first case study is an introduction to the data analysis of a simple case, looking at the determination of the optimum in a single reservoir model. The second case examines Andrew in more detail, which optimizes on average performance on a range of models constrained by current surveillance. The second study does show the start of a surveillance prize, by showing that some of the different reservoir descriptions actually support consideration of a different depletion plan. The value of surveillance theme is explored in the third case study where we return to Harding and now examine the infill wells when the problem is phrased as the phasing, location and operating conditions of two wells, based on 9 alternative reservoir models.
Permanent Real-Time Downhole Flow-Rate Measurements in Multilateral Wells Improve Reservoir Monitoring and Control
Authors: Zakharov M. , Eriksen S. H. , Raw I. , Pride S. , Ridez A. 
Published: December 2007

AbstractDuring the last decade, intelligent well completions have evolved to become engineered solutions widely used for both monobore and multilateral horizontal wells. However, a clear understanding of zonal or lateral branch flow contributions still remains an issue. Several SPE papers covering the issue have been published recently.This paper presents the engineered solution for a TAML level 5 dual-lateral horizontal well that was drilled and completed in the Oseberg Sør field in December 2005. The solution combines hydraulic flow control valves with advanced downhole two-phase flow and density measurement provided by a Venturi-based flowmeter with a gamma ray source and detector. Real-time data were used to optimize the settings of the downhole chokes to obtain a balanced production from the two horizontal wellbores. The completion provides the capability to control and measure, in real time, flow contributions from both laterals and is the first installation of its type. This capability is critical for production and reservoir optimization.Additional value of the technology is demonstrated by the analysis of acquired downhole data. Productivity Indices are obtained for each of the two laterals without any production loss associated with shutting down the other lateral branch. Data analysis indicated a decrease of the Productivity Index for one of the two horizontal wellbores.The successful installation of the two-phase flowmeter in an intelligent completion is a significant milestone corresponding to the general trend in the industry to improve inflow control and the understanding of flow contributions in multilateral wells. This solution for flow control and measurement can be applied effectively in both multilateral wells and monobore wells designed for commingled production from different reservoirs where accurate production allocation is a critical issue.
Results in Construction and Completion for Extend-Instrumented Horizontal Wells Into Low-Pressure Zone: Case History—Reservoir Miocene Ll-03, Maracaibo Lake Venezuela
Authors: Pizzarelli Sergio , Alter David , Tillero Edwin , Garcia Jose Luis , Leal Tulio 
Published: December 2007

Abstract
One of old and most important West Venezuelan Oil fields is the LL-03 reservoir which has accumulated more than 1200 MMBN and actually represent the 30% medium oil daily production of Exploitation Unit "La Salina", Maracaibo District, PDVSA.
This reservoir is characterized for contain 30% of shale with not consolidated sand at low pressure with 450 psi at 3500 feet of depth with interleayer of clay and high permeability with lost of severe circulation risks, in order to develop the reserves of 24° API oil it was designed and execute the secondary recovery project called Fase IV through instrumented horizontal wells into low-pressure zone.
Due the depleted conditions of this reservoir it was begun the search of new alternatives for perforation fluids competitive at technical and economic levels, being one of the main challenges to ensure the success in the construction and completion for extend horizontal wells. After obtained the formulation of the optimal fluid to use it was come to design the directional plan and the mechanical completion for sand control, being considered in addition the use of permanent downhole gauge for pressure and temperature readings, conforming therefore the instrumented well.
The stability of the system, the effectiveness of the saline seal and operational practice allowed the successful perforation of 3 instrumented horizontal wells (2 injectors and 1 producer) with the formulated saline fluid in a horizontal section of 2699 feet average without observe hole instability problems having completed the wells with mesh screen for sand control and permanent downhole gauge for pressure and temperature readings in a concentric string, after removing the filter cake generated by the perforating fluid it was obtained 22 months of continuous and stable production of 900 BNPD results Vs 450 BPPD expected for PB-763 well, opening opportunities for the perforation of 3 wells in similar conditions and it was begun the project for perforation of the first multilateral well in this same reservoir.
Impact of Heterogeneity on Flow in Fluvial-Deltaic Reservoirs: Implications for the Giant ACG Field, South Caspian Basin
Authors: Choi Kevin , Jackson Matthew , Hampson Gary , Jones Alistair , Reynolds Tony 
Published: December 2007

Abstract
The ACG Oilfield caps an elongate anticline with three culminations - Azeri, Chirag and Gunashli - and is located in the offshore Azerbaijan sector of the south Caspian Basin. This study focuses on Azeri in the south-east of the structure, which has over 8 billion barrels of oil in place. The major reservoir interval, the Pliocene Pereriv Suite, is characterized by laterally continuous layers of variable net-to-gross (NTG) deposited in a fluvial–deltaic environment. Azeri is being developed by down-dip water injection, with up-dip gas injection on the more steeply dipping central north flank. At the planned offtake rates both recovery mechanisms are expected to be stable. However, these predictions are based on reservoir models which do not explicitly capture the full range of geologic heterogeneity present in the Pereriv Suite reservoirs.
We report the first detailed assessment of the impact of large- and intermediate-scale heterogeneities on flow. Experimental design techniques have been used to rank the impact of different heterogeneities. A key finding is that communication between adjacent high and low NTG reservoir layers significantly improves recovery, providing pressure support and a route for oil production from sandbodies within the low NTG layers which would otherwise be isolated. Heterogeneity within high NTG layers has only a small impact on recovery, but heterogeneity within low NTG layers is much more significant. In most cases, the same significant heterogeneities impact both water and gas displacements, because both displacements are stable at the planned production rates.
The results are applicable to Azeri, and to similar reservoirs in the Caspian Basin. They also represent the first comparison of water-oil and gas-oil displacements in fluvial- deltaic reservoirs using 3D geologic/simulation models derived from outcrop and subsurface data.
An Integrated Geology and Reservoir Engineering Approach for Modelling and History Matching of a Vietnamese Fractured Granite Basement Reservoir
Authors: Le Ngoc Son , Jamiolahmady Mahmound , Questiaux Jean-Marie , Sohrabi Mehran 
Published: December 2007

Abstract
The main source of oil production in Vietnam is from naturally fractured basement reservoirs (NFBR). The SN reservoir, which is situated offshore Vietnam in Mekong basin, consists of fractured/weathered granite and granodiorite rocks and fully encased by highly over-pressured shales, which act both as seal and source rock. To date, the existing reservoir simulation models have failed to give an adequate history match without invoking the presence of a giant aquifer, something which is not supported by the existing dynamic and geological data. Furthermore, in the original simulation models, zero capillary pressure (Pc) was assumed and a single set of relative permeability (kr) curves and endpoints was assigned for the whole reservoir. These assumptions are open to question as the porosity (Φ) and permeability (k) varies by several order of magnitude for micro- to macro-fractures of this NFBR.
In this work, we have investigated a number of possible alternative sources of energy to achieve a satisfactory history match including (i) increasing the STOOIP by increasing overall pore volume (PV) of the reservoir and (ii) using different values of rock compressibility (Cr) and (iii) accounting for rock compaction (porosity reduction by fracture closure) due to reservoir pressure (Pr) reduction during production. We found that modelling porosity reduction by compaction together with a minor aquifer gave the best history match and is geologically coherent
We also considered using a dual rock-type model, with microporosity zones (Φ&lt;1%) consisting of a network of microfractures and weathering, developed along the macroporosity network which coincides with the major basement faults which criss-cross the granite basement. Microporosity zones were assigned non-linear kr curves with appropriate end points and Pc, while macroporosity zones were assigned diagonal kr curves and zero Pc. Dual rock-type models gave improved history matches. A comprehensive sensitivity study on variations in kr curves and their endpoints showed that these greatly affect reservoir flow behaviour. Finally we investigated variations in Pc but found that it had negligible effects in our models.
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

AbstractDuring 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

AbstractRealistic 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.