bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of an Integrated Single Well Model to Drawdown and Buildup Analysis of Production from Commingled Zones
Authors: Almehaideb R. A. 
Published: December 2007

ABSTRACT
The problem of designing and analyzing well tests for wells producing from multiple zones through the same production string is often complicated by the interaction between the different layers. Often, measurements of both downhole rates vs. depth in addition to downhole pressure is required so as to ascertain how much rate is coming from each layer in order to analyze the response of each layer separately. A complicating factor comes in if the layers are communicating, which may significantly reduce the accuracy of available analytical methods.
This paper describes new applications of a recently developed integrated single well model (ISWM) that couples equations describing dynamic wellbore flow with ones describing transient reservoir flow. This coupling allows the user to assign production, injection, and shut-in of wells at the surface point, where the valves are physically located, instead of downhole for conventional reservoir simulators. The wellbore flow is handled by use of the Bernoulli equation including friction and kinetic contributions to pressure drop.
Another feature of this model is the use of the full rate equation for gas flow in the reservoir, including the inertial-turbulent (forcheimer) term, in order to handle the rate-dependent skin in addition to mechanical skin at the wells. Reservoir and wellbore equations are solved simultaneously using the fully implicit Newton method.
Applications for this model include determining the dynamic wellbore pressure drop versus time for both single phase oil or gas, and multiphase production and shut-in in vertical and deviated wells, and the resultant change in production rates at the wellbore sandface with time. This feature enables the engineer to simulate the actual flow rate coming from each layer and the resultant reservoir response as measured downhole from a pressure recording tool. The degree to which crossflow affects pressure response can also be measured. Examples describing how one can use the model to better design well tests i n commingled formations are also included.
Maximising Well Potential: An Integrated Approach
Authors: Walters N.S. 
Published: December 2007

Abstract
The paper summarises the strategy and methodology employed to maximise well productivity and minimise formation damage during the well construction process for the Wanaea and Cossack projects. Actual performance against expectations and targets is reconciled. The outcome has been oil wells with lower than expected skins and as a direct consequence, aggregate well potential is in excess of nameplate process capacity. The incremental cost associated with achieving the better than expected well potentials has been small due to the methodology employed, but the incremental value is high.
The strategy adopted can be summarised as:–Where are we now?–What is possible?–How do we get there?
rather than the incremental methodology of 'how can we improve'.
This was found to be a very powerful strategy. The methodology used to implement this strategy is described, which included a life cycle approach to completion design and a laboratory based programme to assess various aspects of the drilling and completion processes on productivity. The application of 'fit for purpose' technology; including a novel horizontal completion design and use of long (100m) wireline conveyed perforating guns is also described.

Introduction
The Wanaea and Cossack oil fields are located in some 80m of water approximately 100km offshore North Western Australia. The two fields are being developed in parallel using subsea wells tied back via manifolds and flexible flowlines to an FPSO with a design life of 25 yrs; Reference Figure 1. Well construction activities occurred between July 1994 and February 1995, with production start-up in November 1995. Maximising Net Present Value (NPV) over the life-cycle of the well requires achieving the correct balance between:–Initial CAPEX (ie. well construction costs);–Tubing size vis a vis well productivity (initial production rate, forecast production profiles);–Well reliability and intervention costs (surveys, workovers etc.); and–Installing the appropriate degree of flexibility to cater for reservoir performance uncertainties.
The prime cost driver for the process of well construction was identified as rig time and therefore reducing rig time became the primary focus for cost reduction. However, well productivity was identified as potentially having the most significant impact on Net Present Value (NPV) over field life and therefore any proposed cost reduction was weighed against potential impact on well productivity.
This paper focuses on the application of the above strategy on well productivity and completion design and summarises the solutions adopted. The development and application of the philosophy and the necessary cultural climate is fully described in Reference 1.
P. 321
A Pilot for Polymer Flooding of Saertu Formation S II 10-16 in the North of Daqing Oil Field
Authors: Demin Wang , Zhang Zhenhua , Chun Li , Cheng Jiecheng , Du Xingjia , Li Qun 
Published: December 2007

Abstract
Several papers on polymer flooding pilot test in Daqing have been published previously, they stress on enhancing oil recovery by polymer flooding in thick pay zone of major reservoirs with high permeability and heterogeneity. This paper presents the polymer flooding pilot test results in thin layers of non-essential reservoirs with medium-low permeability and heterogeneity. The purpose is to:study the feasibility of polymer flooding in such thin pay zones;test separate injection techniques;provide data for further extending polymer flooding potentials.
The pilot has 4 injectors and 9 producers in inverted five spot patterns. The polymer flooding through Putaohua P I 1–3 formation had been finished in this pilot in 1990, then S II 10–16 was plugged and S II 10–16 was perforated to perform polymer flooding by dual-pipe separate injection. S II 10–16 formation includes 5 sedimentary time units and has complex geometry of sandbody and some layers pinch out in a few wells in the pilot. Its microstructure relief is large, the deference in depth of the formation is 3 7 meters. The net thickness of a single layer is 0.4 to 4.0 meters. Its average permeability is 0.342 m2 and Dykstra-Parson coefficient is 0.6. Polymer injection started in December of 1993 and 0.35 PV of polymer solution has been injected by the end of 1995.
When 0.025 PV polymer solution was injected, the producers responded one after another. The average water cut of the pilot decreased from 94.5% to 80.1% and daily oil production increased from 37 tons to 95 tons maximum. The water cut of the central well decreased from 95.1% to 63.1%, daily oil production increased from 8 tons to 33 tons. Up to now the oil recovery for the central well has increased 10.84% OOIP over water flooding with the polymer flooding efficiency of 151 tons of oil per ton of polymer.
The measurements of injection and production profile showed that the heterogeneity of the reservoir is adjusted and that separate injection technique by dual-pipe is feasible.
P. 431
Revitalization Of A Mature Volatile And Condensate Oil Reservoir Using Horizontal Well
Authors: Villalba S.M. , Perez P. , Marcano C. , Rojas G. , Rodriguez H. , Almeida J. 
Published: December 2007

REVITALIZATION OF A MATURE VOLATILE AND CONDENSATE OIL RESERVOIR USING HORIZONTAL WELLS.

Abstract
The great interest shown in optimizing the exploitation of reservoirs, in the last two decades through the drilling of horizontal wells, has been the best evidence of the potential of this technology. Significant increments in production rates and recoveries have been reported even in oil fields considered uneconomic.
In this paper, the revitalization of the RG-14, COEF reservoir in the Santa Rosa Field by means of horizontal wells is analyzed. This reservoir is the most important mature reservoir producing volatile oil and condensate in Eastern Venezuela. The RG-14, COEF reservoir started its production in April of 1950, having been subjected to gas injection since 1955. Depth of the reservoir varies from 6560 ft subsea at the crest of the dome to 11150 ft at the flank. Presently, gas channeling and the subsequent entrampment of oil in undrained areas limit the recovery of 14.5 MMBls of remaining reserves. Consequently, the drilling of horizontal wells is a potential option to minimize gas channeling and maximize the drainage area, increasing crude production, final recovery and the economic feasibility of the project, at the same time.
This paper presents the integration of geological, reservoir and production studies to define undrained flow units, the selection of objective areas for three horizontal wells, the characterization of fluids, production forecast by means of pseudocompositional simulation and an economic analysis. A Peng-Robinson equation-of-state was used, to characterize both gas condensate and black oil. The simulation studies were performed only in the areas were horizontal wells are proposed, in order to compare them with vertical wells. Results indicate that it is feasible to reactivate production from the RG-14, COEF reservoir in the Santa Rosa Field from the current 567 STBD to a level of 2620 STBD through the drilling of three horizontal wells.

Introduction
In Corpoven's Anaco and San Tome traditional areas in the Eastern Venezuela Basin, there are about 134 mature fields of condensates and medium and light oil which still have reserves of between 50 and 300 million barrels. Secondary recovery processes (gas injection) used in these fields for the last 30 years have permitted the extraction of 75% of the initial estimated reserves. However, a good portion of the remaining reserves are still trapped due to inefficient drainage and preferential channeling of injected gas and/or water in the reservoirs subjected to a pressure maintenance.
Due to these circumstances, the use of the horizontal drilling technology is required in order to maximize the contact with undrained areas and so reduce the water and/or gas coning. Consequently, this procedure will permit the acceleration of the final recovery of reservoirs.
P. 231
Multi-Lateral Underbalanced Drilling For Field Optimization: Weyburn Unit, Saskatchewan, Canada
Authors: Yurkiw F. J. , Gilmour S. G. , Barrenechea P. J. , Wasslen R. D. , Churcher P. L. , Pustanyk R. H. 
Published: December 2007

Abstract
PanCanadian Petroleum Limited, operator of the Weyburn Unit in southeastern Saskatchewan, Canada, has been involved in the development and application of underbalanced and multi-lateral drilling technologies to access reserves which otherwise were likely to be uneconomic to develop. In an attempt to optimize the mature waterflood in the Weyburn field, both vertical and horizontal infill wells have been drilled over the last 12 years. The most success has been realized from horizontal wells, which have evolved from single laterals to dual laterals to quad laterals. The combination of multi-lateral wells and properly designed underbalanced drilling techniques has resulted in increased reservoir access, significant decreases in the cost of reservoir access, and decreased formation damage. Continued exploitation of remaining reserves has been accomplished by progressively pushing the development of new technology to meet the changing economic and technical demands imposed by drilling in different parts of the Unit.
A Comprehensive Study of Wellbore Stability in Shale Formation and Its Application to Horizontal Drilling Operations
Authors: Cheng Yuanfang , Yan Jienian , Wang Guihua 
Published: December 2007

Abstract
Though the mechanical studies of wellbore stability in the water-sensitive shale formations have been conducted for many years, there was almost no successful example of application in drilling operations. The main reason for this is that the in-situ mechanical properties, strength and hydrated stress of shales can not be accurately determined using traditional procedures.
The project focuses on studying the shale strength in different water contents and the changes of hydrated stress in different in-situ stress, hydraulic drop and classification of shales. The shale samples were obtained from S3 group in Oagang Oilfield. On the basis of plenty of multidisciplinary teamwork, the procedures for the comprehensive evaluation of the various properties of the shales, such as the in-situ strength, pore pressure, Yuang's modulus are given by virtue of a series of laboratory test data, log data and drilling information. In addition, a model that can be used to calculate the borehole collapse pressure, fracture pressure and to determine the suitable density of drilling mud is developed according to the theory of elastic mechanics in porous medium and the theory of partial molar free energy. The model is superior to the models provided in the past in the accuracy of prediction because its input parameters were synthetically identified with test data, log data and drilling information, and both the influences of drilling muds on the shale properties and hydrated stress were taken into account.
The model has been successfully applied to the drilling operations of the horizontal wells in Dagang Oilfield, located in east China. It is confirmed that the optimum densities of the drilling muds predicted with the model are practical, indicated by the quite stable boreholes with very low hole enlargements (less than 10%) in shale formations for the horizontal wells.
Multi-Techhique Comprehensive Interactive Inversion in Sanding Geometry Simulation
Authors: Xu Baoci , Li Chunhua , Dusseault Maurice B. 
Published: December 2007

Abstract
In many oil fields, because of the limitation of geography, humanity conditions, seismic method is impossible to use in oil exploration. In other areas such as where volcanic rocks present then the quality of seismic results will be affected. To solve this problem, a new method called "Optimum Co n-strained Inversion Method (OCIM) "has been developed.
Based on data of constraint area, seismic or drilling, the optimum approach theory can be applied through a optimum fitting function. If the primary parameters of the inversion area are given, rapid iterative inversion can be carried out with OCIM for the detail structure of the inversion area. OCIM can invert the depth of layered structure and opening distribution between layers used in potential field data. According to OCIM, the 3-D tomographic image for density distribution on oil deposit can be obtained and enlarged by filtering of the wavenumber-frequency domain. If the variable values of potential field with time can be monitored, we can obtain the 4-D tomographic structure image or tomographic density distribution image according to OCIM, so that one can use to evaluate structure hazards and avoidance of tectonic hazards during drilling and oil/gas production. This paper also discuss the Accuracy, uniqueness and influence factors of OCIM.
Acid/Rock Interactions During Stimulation of Sour Water Injectors in a Sandstone Reservoir
Authors: Nasr-EI-Din H. A. , Al-Anazi H. A. , Hopkins J. A. 
Published: December 2007

Abstract
A sandstone reservoir in central Saudi Arabia produces sweet, super-light oil. Reservoir pressure support is accomplished by water injection into an aquifer underlying the pay zone. Several water injectors were found to be damaged due to iron sulfide and biomass generated by sulfate reducing bacteria (SRB). The sandstone reservoir is heterogeneous, poorly cemented, and contains up to 11 wt% of clay minerals and up to 0.3 wt% calcite.
An experimental study was conducted to design an effective stimulation treatment to restore the injectivity of the damaged wells, while maintaining the integrity of the formation. Various acids including HCl, acetic acid, regular and retarded mud acids were tested. Stimulation additives including H2S scavenger (aldehydes), iron control agents(EDTA), corrosion (amines) and scale inhibitors (phosphonic acid) were evaluated. Tests included acid-rock interactions under static and dynamic (core flood) conditions. Spent acid was analyzed for key cations using Inductively Coupled Plasma Spectrophotometry (ICP).
Core flood tests indicated that full strength mud acid damaged reservoir cores. Therefore, a half strength regular or retarded HF acid was used. Retarded HF acids which are based on boric acid produced a precipitate (KBF4) and are not recommended for ñeld application. Hydrochloric acid at 7.5 wt% was effective in removing iron sulfide and biomass. However, XRD/XRF analyses indicated that elemental sulfur and CaS04 precipitated inside the core, and were present in the core effluent Addition of EDTA (chelating agent) to the acid substantially increased the concentration of multivalent cations in the core effluent. It also triggered production of fine silica particles and kaolinite, thus the cores were damaged. Hydrogen sulfide scavenger were found not to damage the reservoir cores. Scale inhibitor (phosphonic acid) minimized precipitation of calcium sulfate, however, it caused a significant drop in brine permeability when used at high concentrations (&gt; 0.3 wt%).
Results obtained in this study indicated that a thorough screening of various acids and stimulation additives is needed before stimulating sour wells, otherwise severe damage can occur due to acid reactions with iron sulfide (a corrosion byproduct) and carbonate minerals present in the formation.
Detection Of Formation Damage Associated To Paraffin In Reservoirs Of The Recôncavo Baiano, Brazil
Authors: Khalil C. N. , Rocha N. O. , Silva E. B. 
Published: December 2007

Abstract
This work aims at presenting evidences of paraffination in some reservoirs located in the Recôncavo Baiano, state of Bahia, Brazil, by means of a thermal-chemical method called Nitrogen Generating System or SGN after the original Portuguese expression "Sistema Gerador de Nitrogênio". This method comprises applying the huge amounts of heat and nitrogen gas generated by the reaction between two nitrogen salt-containing aqueous solutions to fluidize the paraffin which becomes then incorporated to the reservoir oil production. In the present work, huge variations were observed for measurements of the melting point, paraffin content, viscosity of the samples, gas chromatography analyses, simulated distillation and wax appearance temperature taken before and after SGN treatment of the reservoirs. It could be seen that the heavy paraffin fraction (C40+) was increased while the light paraffin fraction (C20+ to C40) decreased due to the removal of paraffin deposits from the reservoir next to the perforation.
Evaluation of Paraffin Crystal Modifiers by Dynamic Videomicroscopy
Authors: Magri N. F. , Kalpakci B. , Nuebling L. 
Published: December 2007

Abstract
Conventional techniques for selection of wax inhibitors for crude oils have been limited in that visualizing oil and wax behavior under flowing conditions has not been possible. This paper describes a new technique, videomicroscopy, which allows for visualization of precipitating wax behavior in flowing oil under field conditions. In addition to videomicroscopic data, results of conventional crude oil and model wax systems characterization are given. These conventional techniques include cloud point, pour point, rheology and crystal morphology characterization. Results from videomicroscopy agree with, but go well beyond, what iss learned from conventional analysis. Videomicroscopy shows uninhibited crude to form strong wax aggregates resulting in plug flow, while inhibited oil tends to produce weakly bonded clusters. The technique shows changing behavior of the wax with respect to network formation and deposition as functions of temperature and shear.
Experimental Investigation on the Injectivity of Phenol-Formaldehyde/Polymer Gelants
Authors: Bryant Steven L. , Borghi Gian Paolo , Bartosek Martin , Lockhart Thomas P. 
Published: December 2007

Abstract
Knowing the injectivity of a gelant, i.e. the pressure gradient required to achieve a given flow rate, enables the designer to program the rate/volume schedule of a water shut-off treatment. Bulk gelation times determined from bottle testing have often been used to estimate available pumping time, but such tests do not measure the evolution of gelant rheology as crosslinking proceeds, nor do they measure the tendency of the gelant to undergo filtration within a porous medium. These factors can affect injectivity significantly, resulting in pumping times much less than the bulk gelation time. In this paper we describe techniques for discriminating between vis-cosification and filtration by means of experiments in porous media, making use of multiple pore volume injection, step changes in flow rates, and in-line capillaries. Tests with phenol-formaldehyde crosslinked polymer gelants, which possess a number of characteristics favorable to high temperature applications, show that filtration of pre-gel aggregates in sandpacks and cores can play the dominant role in reducing the mobility of the gelant. The filtration behaviour is not universal, however; one gelant formulation showed no loss of mobility at all by this mechanism. When filtration does occur, it is strongly correlated to the age of the gelant (i.e. time the gelant has spent at temperature) but is relatively insensitive to the permeability of the porous medium or the presence of residual oil. The viscosity of the gelants tested evolves in similar ways in bulk and during flow in porous media.