bluuebunny/crossref_metadata_2025_split huggingface dataset:
Performance of Horizontal Wells in Gas Condensate Reservoirs: Hassi R'Mel Field, Algeria
Authors: Marir Boualem , Tiab Djebbar 
Published: December 2007

Abstract
Hassi R'Mel Field is one of the biggest gas-condensate fields in the world. The southern area of this field, Module 02, has been depleted by vertical wells since 1979.
Since 1981, water production has exceeded the allowed water limit. The salinity of the produced water is about 05 g/l, which is the maximum salinity allowed at the surface facilities. As a result, a sever reservoir damage may have occurred. So the producing reservoir levels (C) were shut-in.
The primary objective of this study is to investigate the performance of horizontal wells in a Sector-Model, to predict their behavior versus water production, and condensate recovery.
To simulate the depletion processes, a compositional simulation is conducted to investigate the following phenomena in the case of horizontal and vertical wells: (a) Water influx effects, (b) Comparison of horizontal well drawdown pressure to that of vertical wells, and (c) The influence of the horizontal well length section and reservoir thickness on horizontal well productivity, and condensate recovery.
A reservoir characterization is made, and a 3-Parameter Peng-Robinson equation of state (3-PR-EOS) is established to characterize the reservoir fluids.
A 3-D Cartesian Sector Model was built for the zone of interest in order to predict the performance of horizontal wells and the different phenomena that can be present in retrograde gas-condensate reservoirs, and to analyze the most relevant reservoir parameters that affect horizontal wells performance.
The obtained results showed that the use of horizontal wells is a proven technology for reducing water influx problems and improving condensate recovery. The condensate production of a horizontal well compared with that of a conventional vertical well can be increased by a factor of 1.30, owing to less condensate accumulation in the region of the producing well.
26-in. Hole Sidetracking Problems in Salman Oil Field, Persian Gulf: A Case Study
Authors: Rahchamani A. , Kalantari-Dahaghi A. M. , Moghadasi J. , Gholami V. 
Published: December 2007

Abstract
This paper describes the reason of sidetracking in 26 inch hole of Salman field in Persian Gulf, its problems and restrictions including unconsolidated formation type, existence of washout below the conductor pipe, probability of anti collision, limitation to survey in order to determine the well situation and short side track interval. Finally the methods for overcoming these problems in order to do a successful sidetrack are explained.
A New Genetic Algorithm (GA) Model Predicts Green-House Gas (GHG) and Reservoir Oil Interaction Parameters More Accurately in Geosequestration Applications
Authors: Emera M. K. , Sarma H. K. 
Published: December 2007

Abstract
The GHG geosequestration in oil and gas reservoirs has recently been receiving much attention, particularly because it also offers an opportunity to concomitantly enhance oil recovery from depleted reservoirs. However, for it to be successful for geosequestration and EOR, it is critical that the GHG-oil miscibility and interactions are favorable and well understood.
This study presents a new genetic algorithm (GA)-based model to predict GHG-oil interaction parameters, notably, GHG-oil solubility, impact on oil swelling factor, GHG-oil density and viscosity. The model utilizes saturation pressure, temperature, oil specific gravity, oil and GHG compositions, GHG critical properties, and equally important, the GHG liquefaction pressure to predict the GHG solubility. The oil-swelling factor is modelled as a function of the oil molecular size and GHG-oil solubility. For the GHG-oil density, the initial oil density, saturation pressure, temperature, and oil specific gravity are used as input variables. The modelling of GHG-oil viscosity takes into account the effects of initial oil viscosity, saturation pressure, temperature, GHG-oil solubility, oil specific gravity, and compositions of oil and GHG.
The model has been successfully validated with published experimental data and has also been compared against other commonly reported models that are developed, essentially, for CO2-oil properties. The GA-based model consistently yields outstanding accuracy (0.48 to 6.2% average error range). Furthermore, the GA-based model can be applied over a much wider range of data under various conditions (wider oil gravities, Ps≤41.37 MPa, T≤141.1°C, and oil MW≤450) and over bigger range of GHG compositions. In addition, this model can easily be incorporated into a reservoir simulator and it can serve as yet another useful experimental protocols design tool.
Commercial Success of Polymer Flooding in Daqing Oilfield—Lessons Learned
Authors: Yupu Wang , He Liu 
Published: December 2007

Abstract
The polymer flooding technology has been applied commercially in Daqing Oilfield since 1996. It has become an important supporting technology for both the stable output of Daqing Oilfield and the development improvement of the mature oilfields. In Daqing Oilfield, the polymer flooding annual output has exceeded 10 million tons; water cut reduction rate has been kept 24.8% for 2 years. In the testing blocks, the average incremental oil recovery over waterflooding is 10.99%. To solve emerging problems in the pilot areas, new techniques and processes have been applied. They are: 1) injection of high concentration slug; 2) polymer injection to separate layers; 3) in depth profile modification. The success of these techniques and processes have enlarged the polymer flooding scale year by year and the technology of polymer flooding itself has been improved. The successful experience of Daqing polymer flooding is valuable for polymer flooding technology development in other countries.
A New Pressure Transient Analysis Model for Water Injection Well in Dual-Porosity Reservoirs
Authors: Shimamoto T. , Kuramoto D. , Arihara N. , Onishi T. 
Published: December 2007

Abstract
This paper presents a new analytical model for pressure transient tests of water injection wells in naturally fractured reservoirs. Considering negligible flow in matrix, the dual-porosity model was assumed for formulating a mathematical model that accounts for two-phase flow and saturation changes in fracture and matrix. Water saturation distributions in fracture and matrix were calculated analytically using the Buckley-Leverett equation and the empirical transfer function to account for fracture-matrix flow. Pressure equations for two-phase flow were formulated with the multi-composite modeling approach. The system of pressure equations was solved analytically in Laplace space. Calculations were carried out stepwise as the injection or falloff time proceeds.
The model solutions were validated for such special cases as single-phase flow in the dual-porosity model, and two-phase flow in the single-porosity model. Pressure and pressure-derivative type-curves, graphed against the injection time or the dimensionless time based on well radius, exhibited features of both fractured reservoirs and two-phase flow. The parameters in the type curves are storativity ratio, interporosity two-phase flow coefficient defined as a function of shape factor, total mobilities for matrix and fracture, and exponential recovery constant Rc. Rc characterizes imbibitiondominant recovery performance of matrix, and is defined as a function of permeability, porosity and capillary pressure of matrix, and shape factor.
Characterizing Sparsely Fractured Reservoirs Through Structural Parameters, Time-Lapse 3D Seismic, and Production Data
Authors: Zeidouni M. , van Kruijsdijk C. P. J. W. 
Published: December 2007

Abstract
In the case of fractured reservoirs the productivity is primarily based on the fracture density, thus structural parameterisation becomes highly important. In conventional history matching, the process of conditioning the reservoir model to the historical dynamic data, the production data are utilised to condition the model. Based on the nature of production data the model can be parameterised by reservoir parameters only and the structural and geological inputs are kept fixed. Given time-lapse 3-D seismic the procedure might be altered and structural parameterisation becomes possible.
In this paper we evaluate the benefit of using time-lapse seismic to model the fractured reservoir with structural parameters, i.e. to locate the fractures. A synthetic sparsely fractured reservoir is modelled and parameterised structurally based upon the length and position (x and y coordinates) of the fractures. A compressional-wave velocity model is developed to enable the comparison of seismic data and reservoir data (saturation and pressure). A production, pressure, and saturation profile is simulated and results are compared with history through an automated history matching loop.
The advantageous of the seismic and production data in parameters' evaluation is examined. The well data are found very efficient in defining the parameters that are involved in production. Time-lapse seismic data grants information about all the parameters, but over a wide confidence interval. The results depend strongly on the times of acquiring seismic surveys as well as the number of unknown parameters. As the number of parameters is increasing, the efficiency of seismic comparing to that of well data increases. The optimal times for acquiring seismic data can be found through modelled saturation profiles. Extracted pressure data from time-lapse seismic proved to be very valuable in fractured reservoir modelling because of the pressure anomaly between the matrix and the fracture. The uncertainty of the resulted parameters due to the measurement error of the data is also analysed.
Formation of Underwater Cuttings Piles in Offshore Drilling
Authors: Fang Qian , Guo Boyun , Ghalambor Ali 
Published: December 2007

Abstract
Discharge of drill cuttings to seabed can significantly reduce offshore drilling cost. However, formation of cuttings piles on seabed near the rig site can present problems for drilling and production operations. When the problem is likely to occur in the areas of low current velocity, the cuttings are not discharged to seabed but ground and injected to formation, or transported to onshore for disposal, which increases drilling cost. It is highly desired to have an accurate method to predict the location and configuration of the cuttings piles in the design stage of well drilling. This paper presents a solution to the problem.
Starting from Newton's second law of motion, a mathematical model has been developed in this study to predict the location, configuration, and characteristics of cuttings piles. Factors considered include water depth, current velocity, cuttings properties (size distribution, density, and sphericity), and water properties (density and viscosity). This mathematical model has been computerized. It provides well planners a useful tool for predicting the characteristics of cuttings piles during drilling. Application of the tool can reduce cost of drilling through better handling of drill cuttings such as discharging to water versus injecting into formation.
Case Studies—Proactive Managed Pressure Drilling and Underbalanced Drilling Application in San Joaquin Wells, Venezuela
Authors: Beltran J. C. , Gabaldon O. , Puerto G. , Alvarado P. , Varon V. 
Published: December 2007

Abstract
The San Joaquin field was discovered in the 1930's and is one of the largest oil-gas fields in the eastern Venezuela. It field currently including over 240 wells producing from 662 different reservoirs. The average daily production is about 800 MMSCFGD and 8000 BOD of condensate.
Due to the reservoir characteristics and the natural decrease of the reservoirs virgin pressure, drilling operations applying conventional overbalanced methods have induced significant Operational Problems and formation damage.
To reduce initially the operational problems (average fluid losses, which were more than 2,000 barrels per well) and to decrease Productivity Index damages due to differential pressures on the depleted formations, the Near/Under Balanced technique was considered.
Several months of reservoir evaluations with geomechanical and stability studies were spent, before the decision to use Managed Pressure Drilling through-out shale/sandstone-layered gas payzones formations was taken.
Twelve wells have been performed up to date using proactive Managed Pressure Drilling (MPD) & Underbalanced Drilling (UBD) techniques in the Merecure and San Juan formations (8½″ and 6½″ hole sections respectively). Nitrogen injection has been applied in the San Juan formation to achieve the required ECD below 6.0 ppg.
These types of wells were the first of their kind drilled in Latin America using these techniques in conjunction with the Down Hole Deployment Valve (DDV).
The application of the MPD technology to solve the varied range of operational problems that had been experienced in the San Joaquin field, began in December 2004 in the 8½″ section of the G-92 well, with an excellent operational and production result. After this milestone, the MPD program has included the performance of the following wells, up today: JM-229, JM-230, JM-233, JM-235, JM-236, JM-237, JM-238, JM-239, G-96, JM-240, JM-242.
A total of sixty days and US$1.4 Million have been saved using the above practice in the first five wells (8½″ and 6½″ hole sections). As a result, PDVSA will continue applying the technique in the San Joaquin field. The well bore stability study is currently under evaluation for the 12 ¼″ hole section to enable the MPD application in an effort to optimize time and costs in the upper section too.
This paper describes how the planning and operational procedures have been performed in order to obtain savings during the drilling activity in San Joaquin wells and How the improvements in the production are being achieved following a great step forward in today's industry needs for recovering production from complex reservoirs.
Well Sanding and Lost Production due to Cyclic Water Hammer
Authors: Hayatdavoudi A. 
Published: December 2007

Abstract
This paper describes our recent observations relative to the repeated shut-ins of the high-pressure oil and gas wells in the Gulf of Mexico. The current Mineral Management Service regulation requires that in the case of an emergency such as hurricanes, fires, spills, pipeline problems, etc., the subsurface safety valve slam shut in 45 seconds but the flapper at the end of its travel actually slams instantaneously against the well flowing pressure. The type of subsurface safety valve installed for this purpose is a flapper, which is kept open by an hydraulically activated spring. Once the spring receives the triggering signal, it will close the flapper instantaneously. The instantaneous shut-in appears to cause a water hammer effect in the form of strong cyclic peak pressure, which travels down the tubing into the perforations. This extra pressure builds up cyclically in the reservoir rock near the well bore until it is attenuated with time. After the emergency condition has passed, the operator puts the well back on production. We have observed, at least in three deep wells with highly consolidated reservoir rocks, that not only did they lose fluid production, but they also produced a great deal of pulverized, highly angular rock fragments. The microscopic analysis of the rock fragments show patterns of reflected and propagated tension fractures, stick-slip sheared surfaces, and catastrophic failures of silica, feldspars, and various types of grain-bonding cements such as siderite. We have concluded that the wells lost production due to well sanding and that the well sanding was induced by cyclic hammering pressure and cyclically induced and propagated micro fractures extending all the way into the water bearing formation below or above the producing zone. Furthermore, these induced Hammering Waves detrimentally changed the cyclic effective stresses around the perforations.
Downhole Fluid Analysis and Fluid Comparison Algorithm as an Aid to Reservoir Characterization
Authors: Venkataramanan L. , Elshahawi H. , McKinney D. , Flannery M. , Hashem M. , Mullins O. C. 
Published: December 2007

Abstract
In recent years, formation sampling and testing tools have provided a variety of new downhole optical measurements for downhole fluid analysis (DFA). DFA involves in-situ measurement of optical absorption spectra used to compute properties such as hydrocarbon composition and gas oil ratio (GOR). Abrupt changes in these fluid properties with depth may be a marker for reservoir compartmentalization. However, hydrocarbon differences can be reliably identified only when the significance of uncertainties due to measurement and oil base mud filtrate has been taken into account. Recently, an algorithm called the fluid comparison algorithm (FCA) has been developed to address this issue.
FCA propagates uncertainties in optical measurement and contamination into uncertainties in fluid properties, such as color, composition, and GOR. The output of FCA is the probability that two fluids are statistically different. Real-time application of FCA can optimize capture of downhole fluid samples and generation of a continuous downhole fluid log representing the fluid complexity in the reservoir. In addition, by identifying abrupt changes in fluid properties with depth, FCA may in some circumstances be an assay for reservoir compartmentalization.
In this paper, we briefly review the theory of FCA. The strengths and limitations of the technique to improve understanding of reservoir architecture and fluid complexities are presented through two case-studies.
History Matching of the Valhall Field Using a Global Optimization Method and Uncertainty Assessment
Authors: Al-Shamma B. R. , Teigland R. 
Published: December 2007

Abstract
This paper provides a study of a history match on a complex reservoir model using a global optimization method. This is done by applying Evolutionary Algorithms to the problem of history matching. The results of the history match are then used to carry out an uncertainty assessment on variables of interest. The main parameters used in the history match included: horizontal permeabilities, porosities and vertical transmissibilities.
This study also made use of methods for improving the convergence of the optimization cycle, which included using correlations, adopting a Bayesian approach and exploring the search space. The results obtained over the optimization cycle, are used to identify sensitivity parameters, correlations and parameter trends in a global search space. In addition the original manual history match was further improved by adopting a pressure match using an Evolutionary Strategy. Best matched cases were selected based on the global and partial objective values of each match. Predictions runs were performed in order to investigate the effect on the cumulative oil produced and the STOIIP.
Finally an uncertainty assessment of the most recent history match was carried out using an experimental design matrix. The results of the experimental design were used to generate a proxy, which is used in a Monte Carlo simulation to develop P10/P50/P90 oil forecasts.
Predicting Deepwater Well Behavior
Authors: Al Kindi Azhar 
Published: December 2007

Abstract
In comparison to on-shore or shallow water fields, there is limited experience in the industry for deepwater well performance prediction. The development of deep offshore reservoirs is a high risk exercise: in addition to commercial and environmental exposure, the sparsity of early exploration data compounds with the inherent geological complexity of turbiditic formations, making any performance prediction, and therefore development planning, highly uncertain.
Prediction of a well performance is generally a twofold matter: predicting the initial rate of the well and the longevity of the well. Historical information is often extremely useful in such an exercise. In a Deepwater field in the Gulf of Mexico, understanding the behavior of existing wells and reasons for their historical deviations from prediction has formed a major input into the design of the next Phase development wells.
While the new technologies that are emerging for deepwater primarily encompass the areas of drilling and completions, and subsea systems, technologies addressing subsurface uncertainties are also rapidly surfacing. The understanding of some of the major subsurface challenges, such as compaction, compartmentalization and completion failures has, naturally, evolved as new related technologies evolved.
Technological advances in the area of 4D seismic have enhanced the understanding of underground water movement and the distribution of depletion patterns. And while fault density, position, extent, direction and transmissibility remain a large uncertainty in most GOM fields, the application of state-of-the-art seismic processing and simulation technologies is believed to be a major contributor towards the mitigation of such.
Reservoir sand quality and fluid properties have, typically, dictated certain completion designs for wells and a certain operating philosophy. Another example of advanced technology implementation, in GOM multi reservoir setting, is the deployment of an integrated field-planning tool, linking individual reservoir models to a surface facility network model. This tool manages overall system flow parameters, thus, enhancing the predictability of the field performance.
The focus of this paper is to address the challenges associated with performance prediction for deepwater wells and the techniques used to mitigate such challenges, as related to GOM fields.
The Role of Conceptual Geological Models in More Accurately Estimating Inplace Hydrocarbon: An Example From the Cooper Basin, South Australia
Authors: Al-Khalifa M. A. , Payenberg T. H. D. , Lang S. 
Published: December 2007

Abstract
The generating and usage of conceptual geological models become an integral part of reservoir characterisation studies, because they represent geologist understanding of the reservoir. With understanding of uncertainty associated with the conceptual models, their usage could be expanded to accomplish critical task such as inplace hydrocarbon (IPH) estimation. This paper presents a recommended workflow for building a conceptual geological model for a fluvial system and discusses the different uncertainties associated with it. Afterward, Its uses this workflow to build a conceptual geological model for a gas reservoir in the Cooper Basin, South Australia and estimates the IPH through stochastic modeling method.
Building a fully integrated conceptual geological model involves input data of different scales such as core data, well logs and analogues, and each input has its own uncertainty. The process of building a conceptual model is made up of different steps such as core description and depositional facies identifications. Uncertainty cannot be eliminated, but it can be reduced. It cannot be eliminated because the accurate description of the reservoir is not known and will not be known precisely, but using available data will help in narrowing down the possible choices.
Inplace hydrocarbon estimates using stochastic modeling method was preformed for a gas reservoir in the Cooper Basin. There were two stochastic porosity models built using the same input data, but one model was based on a conceptual model and the other was not. The results showed that the use of conceptual models has given higher oil and gas estimates. This is due to the mechanism of the porosity simulation based on geological data. The porosity is simulated independently in each facies object in each reservoir interval. Another advantage of using the conceptual model is improvements in the continuity of porosity. Without the facies objects, porosity continuity will be dependent of semivariograms and values at wells. In the absence of any well data, the continuity will be estimated for the semivariogram parameters namely range and direction.