bluuebunny/crossref_metadata_2025_split huggingface dataset:
"Cement Packer": An Innovative Technique to Recover Reserves Above Packer Without Re-completion
Authors: Susilo Yoliandri , Wibowo Wahju , Rich David 
Published: December 2007

Abstract
Reserves with marginal production potential are often by-passed during the early stages of reservoir development. Re-evaluations of well logging data has resulted in the discovery of potential reserves located above the production packer that were not previously considered in the initial completion strategy.
Conventional completion techniques required a workover to re-complete to these potential zones. However, due to marginal reserves or the presence of production from existing zones below the proposed re-completion (ex: a dual completion where the long string is still producing while short string is shut-in), a workover is not a good economic option to recover these zones. A novel technique of cement packer has been successfully developed in Offshore West Java (OWJ) field to re-complete these zones without pulling out the existing completion. Pressure isolation of potential zones is accomplished by placing cement in the tubing-casing annulus above the production packer. This cement then acts as a new production packer further up the wellbore. Conventional or oriented perforating is then used to complete the well in the new productive intervals.
The advantages of this technique are it is inexpensive (rigless), there is no need to wait for other tubing strings in the well to deplete to their economic limit before re-completing up-hole and –most importantly-access to and production from lower completion is not affected.
To date, a total of 9 wells have been reactivated using this technique to recover productive zones located above the production packer. The average cost was only 20-60% of conventional workovers and savings of up to US$ 800,000 have been achieved. These successful results have brought new opportunities for reactivating many more shut-in wells with by-passed reserves that are economically marginal.
A Mechanical Model of Shale Instability Problems Offshore Abu Dhabi
Authors: Yamamoto K. , Shioya Y. , Matsunaga T. , Kikuchi S. , Tantawi Ibrahim 
Published: December 2007

Abstract
Natures of Nahr Umr shale instability problems in Zakum field are studied in Geomechanical and chemical views. Literatures, past drilling data, wireline logging and well test data, and analysis of cuttings and cores are studied to define the cause of the problem and find the way to fix it.
By using the record of past drilling troubles, problems are likely in the highly deviated well, and relationship between drilling direction and trouble occurrence is not clear. It has obvious relationship with mud weight and chemicals, however the causality is not clear.
The Geomechanical model was set for the formation from the analyzed data, available literatures and measured data in the recently drilled well. Also, mechanical and chemical characteristics of the shale are examined with cuttings recovered from wells, and cores from past wells. Mineralogical test are mechanical strength measurements are performed for the samples. Observation and testing of the samples unveil the fact that the shale has severe anisotropic feature of the mechanical strength and physical feature such as permeability.
By integrating the facts and findings, the authors determine the failure mode as bedding plane failure caused by its anisotropic feature and pressure penetration. Counter measures are proposed based on the numerical studies of poro-elastic and discontinuous modeling.
Using Solid Expandable Tubulars for Openhole Water Shutoff
Authors: van Noort Roger , Rivenbark Mark , Jones Mike 
Published: December 2007

Abstract
In recent years, many operators in the oil and gas industry have moved to horizontal drilling, a process that has proven much easier than trying to move hydrocarbons into vertical wellbores. For the last several years, a major Middle East operator has been leveraging horizontal drilling technology to maximize oil recovery. Although horizontal drilling technology has resulted in significant production increases, this operator saw that recovery efforts were somewhat hampered by water breakthrough in the horizontal openhole section of some wells. Unwanted water production is a problem for many operators, not just because of water content and reduced lift efficiency, but also because of the cost of water handling facilities and the cost of disposing of or re-injecting the unwanted water.
This paper describes the planning and deployment of solid expandable tubular technology in the application mentioned above and cites an actual case history. This paper also discusses applications under development that leverage emerging solid expandable tubular technology.
Reconciling Core Derived Permeabilities and Well Test Using A Fracture Network: A Field Case Example
Authors: Charfeddine Mohsen , Al-Deeb Maged , El-Abd Salem , Bahar Asnul , Ates Harun , Soeriawinata Tono , Kelkar Mohan 
Published: December 2007

AbstractIt is a common observation that well test permeability values do not match with thickness weighted core permeability averages. This is not a surprise because of the differences in the measurement scales where, unlike well test measurements, core samples represent a very small portion of the reservoir around the well bore. In addition, the presence of fractures and/or high permeability channels will further enhance the difference between the two sources of data. Therefore, reservoir descriptions based on core measurements alone cannot honor well test results. They need to be modified properly without violating the underlying geological and geostatistical information.In this paper, we present a methodology to properly enhance permeability fields that also accounts for fracture distribution in the reservoir. The basic idea is that radial upscaling around a wellbore within a given investigation radius should match the permeability obtained from well tests. The enhancement is caused by two factors: microfractures, which cannot be explicitly represented in the reservoir description, and macro-fractures, which can be interpreted using 3-D seismic data. To account for these two different types of fractures, we calculate two different enhancement factors, one for the base level (microfractures) and one for the higher level (macro-fractures). The base level, after appropriate interpolation, is applied across the entire reservoir, whereas the higher level is applied only to locations where macro-fractures are interpreted from 3-D seismic data.The technique was successfully applied to a Middle Eastern carbonate reservoir. A significant correlation is observed between the enhancement required to match the well test data and the fracture density (macro-fractures obtained from 3-D seismic data) within a given investigation area. A correlation function is then obtained between the enhancement factor and the fracture density for a given grid block, which in turn is used to apply enhancement to interwell locations. Thus, the resulting permeability field did not only honor the well test results but also the fracture distribution and the underlying geological and geostatistical descriptions. In a later stage, a tensorial approach was used to upscale permeability to account for the anisotropy in permeability distribution. Using this approach, a proper anisotropy of permeability distribution, matching the fracture orientation, has been obtained.
Block Size and Fracture Permeability in Naturally Fractured Reservoirs
Authors: Rivas-Gómez Santiago , Cruz-Hernández Juana , González-Guevara José A. , Pineda-Muñoz Armando 
Published: December 2007

Abstract
During a naturally fractured reservoir simulation process, reservoir engineers use some important properties of the reservoir as the number and width of fractures, block size, fracture permeability and the shape factor. Some times these properties are taken in an independent way, causing waste of simulation time.
In this paper a relation among the mentioned reservoir properties and the well production, based on Darcy's equation is presented. The relation obtained for the total flow rate, that includes the matrix and the fractures contribution, and the number and width of fractures shows that there are different sets of values that give the same production, but they are dependent each other. This method contributes to define by means of the data obtained in production tests, the mentioned parameters, makes them consistent and determines all the values when one of them is known. An application is presented using the data of Cantarell field, the largest one fractured reservoir in Mexico. Different combinations of parameters are shown, the ranges for the reservoir properties are discussed and also the way to define them.
Seismic fracture detection at a Middle East offshore carbonate field
Authors: Holmes Gordon M. , Thomsen Leon 
Published: December 2007

Abstract
In 2001, a wide-azimuth 2C/3D OBS survey was acquired over an offshore carbonate field in the Middle East, and processed with techniques specifically designed to preserve and extract the azimuthal effects in the data. The results showed significant azimuthal anisotropy in amplitude, with apparent azimuthal variation in the P-wave AVO slope of as much as 100% at selected target horizons. The azimuth of the most positive slope was generally NW/SE, in agreement with the regional tectonic trend. The magnitude of the anisotropy varied markedly, with patches of strong anisotropy, with a granularity of 10's to 100's of metres, and a regional trend on the 2km scale. Vertical variation of these patches supports the hypothesis that the effects are due to subsurface anisotropy, rather than acquisition artifacts.
Management of Stress Sensitive Reservoirs Using Two Coupled Stress-Reservoir Simulation Tools: ECL2VIS and ATH2VIS
Authors: Onaisi Atef , Samier Pierre , Koutsabeloulis Nick , Longuemare Pascal 
Published: December 2007

Abstract
The stress state in and around a reservoir can change dramatically due to changes in pore pressure, temperature and water saturation caused by either depletion or water injection. Both depletion and water injection may cause deformation of the rock and alteration of the rock fabric, which in turn gives rise to phenomena such as compaction and subsidence, induced fracturing, opening of natural fractures and fault slip. These mechanical and chemical phenomena continuously affect the reservoir properties, the flow pattern in the reservoir and ultimately the recovery factor. In addition, changes of stress within the reservoir and in the overburden require special consideration in the design of wells to prevent sand production and casing collapse and for later infill drilling.
To capture the link between flow and concomitant depletion and/or injection pressures and in situ stresses at field scale, it is essential to perform coupled reservoir-geomechanical simulations. This paper introduces the ECL2VIS and ATH2VIS tools, which provide a two-way link between the reservoir simulators ECLIPSETM1 and ATHOSTM2 and the geomechanical stress simulator VISAGETM3. The basic versions of these coupled simulators take the pore pressure and temperature increments calculated by the flow simulator and use them in the geomechanical simulator, which calculates corresponding changes in stresses that are used to update the permeability in the flow simulator.
The latest versions of ECL2VIS and ATH2VIS address the issues of compaction drive. These versions will also allow for the modification of the mechanical properties of reservoir rocks due to corresponding changes of water saturation. The compaction-drive algorithm, with or without water weakening effects, forces the pore volume calculated by the flow simulator to be similar if not equal to the pore volume obtained from strain calculations.
The Effect of Wettability on Saturation Functions and Impact on Carbonate Reservoirs in the Middle East
Authors: Masalmeh Shehadeh K. 
Published: December 2007

Abstract
Wettability is an important factor, which affects the flow behavior in oil reservoirs. It has a profound effect on the shape of relative permeability and capillary pressure curves and consequently on oil displacement processes in porous media. This paper presents experimental measurements on core samples where the effect of wettability is investigated on connate water, residual oil, oil and water permeability end points, relative permeability and capillary pressure curves.
The paper summarizes the main findings of few years of data collection on several cores from different carbonate fields in the Middle East, and a comparison with clastic data is made when appropriate.
The data shows very low connate water for most carbonate fields investigated in this study even for low permeability rocks, 1 md. The residual oil saturation after restoring wettability was measured to be less than 10% for both carbonate and sandstone fields. For water-wet samples a residual oil of around 30% is measured. A distinct difference was found in the dependence of residual oil saturation on initial oil saturation for water-wet and mixed-wet cores. For water-wet samples Sor increased almost linearly with Soi, however; for mixed-wet samples Sor was found to be constant for a very wide range of Soi values.
For water-wet samples we often measured high oil relative permeability end point, Kro(Swc)&gt;1.0, and it decreased as the wettability changed to mixed-wet or oil-wet. The water relative permeability end point is low for water-wet samples and increased for mixed-wet or oil-wet samples.
As demonstrated in the field case discussed in this paper, the findings of this study have important implications for field development and hydrocarbon recovery.
Determination of the Effects of Capillary Number, Viscosity Ratio and Wettability on the Capillary Pressure-Saturation Relation Using an Advanced Pore Network Simulator
Authors: Constantinides George N. , Payatakes Alkiviades C. 
Published: December 2007

Abstract
Macroscopic modeling of two-phase flow in porous media is based on the use of appropriate constitutive equations, the most important of which correlates the capillary pressure with the saturation. Several semi-empirical relationships of this type have been proposed in the literature, which include adjustable parameters. In the present work the dependence of capillary pressure on saturation is calculated as a function of the pertinent parameters (capillary number, viscosity ratio, dynamic contact angles, pore structure) using an advanced pore network simulator. The advantage of this approach is the correlation of the mesoscopic properties of the process, such as capillary pressure and saturation, with the main flow mechanisms at pore scale. The calculations involve the actual pore mechanisms and do not use adjustable parameters. The pore medium is modeled as a three-dimensional network of randomly sized unit cells of the constricted-tube type. Solving the problem of forced imbibition and drainage, the time evolution of the capillary pressure is calculated as a function of the saturation and the system parameters.
The capillary number, the viscosity ratio and the wettability affect the capillary pressure-saturation relation strongly and their effects should not be neglected. We find that the shape of the capillary pressure-saturation curve depends strongly on the step increase of the capillary number. The capillary pressure is an increasing function of the viscosity ratio at the initial stages of displacement and a decreasing function of the viscosity ratio at the final stages. The effects of wettability are quite complex and are explained in the full text. The results are correlated with the flow mechanisms at the pore scale (mechanisms of oil disconnection, action of wetting films flowing through pore wall microroughness, distribution of oil in the porous medium, etc.).
Geological Modeling of a Tight Carbonate Reservoir for Improved Reservoir Management of a Miscible WAG Injection Project, Abu Dhabi, U.A.E.
Authors: Gomes J. S. , Ribeiro M. T. , Fouchard P. , Twombley B. N. , Negahban S. , Al-Baker S. 
Published: December 2007

Abstract
This paper presents the methodologies adopted to model a tight carbonate reservoir located in Abu Dhabi and to better predict its performance (completed with horizontal wells) under a water-alternating-gas (WAG) process. The model is built through integrating geological, geophysical, petrophysical, geomechanical, and geostatistical information.
The large-scale reservoir framework is built by integrating horizontal wells and 3D seismic data. Horizontal well results are used to improve the velocity modeling and depth conversion. The fine scale reservoir zonation is based on lithostratigraphic correlations derived from the porosity and micro-resistivity logs. Stylolitic intervals are used as stratigraphic markers to guide the reservoir zonation. The Porosity model is derived from a high resolution stochastic seismic inversion, and the permeability model is generated using cloud transforms with P-Fields applied by reservoir rock types. High-pressure mercury injection data is used to define reservoir rock types. Lorenz plots have been applied and found to be a useful technique for capturing the heterogeneity of the reservoir and determining the main flow units. Fracture analysis is conducted using cores and image logs (FMI). A geomechanical study is performed to assess the orientation of the horizontal wells in the field. A discussion on the orientation of the horizontal wells with respect to maximum principal stress versus productivity/injectivity is also addressed in this paper. A mechanistic compositional flow model is built to perform sensitivity analyses on various WAG schemes (cycle, ratio, etc). A full field compositional model is subsequently built to evaluate the field performance under various development scenarios. The field is scheduled to come on stream by December of 2005.
Saturation Evaluation in Micritic Reservoirs: Raising to the Challenge
Authors: Mario J. C. , Takezaki Hitoshi , Asakura Shigeaki 
Published: December 2007

Abstract
The micritic limestone reservoir zones offshore Abu Dhabi have consistently challenged formation evaluation specialists. For years, zones exhibiting very low resistivity and interpreted as water-bearing, by standard or even more advanced interpretation schemes, have been shown to produce significant quantity of oil. Production tests and core studies have confirmed this fact.
Previous work has shown that a saturation equation still based on resistivity but using a triple porosity model improved the quality of the formation evaluation in these very challenging conditions. One limitation of this very valuable approach was that, in order to ensure an easy analytical solution to the equation, a fixed relationship was assumed between the saturations in the various porosity types, primarily macro- and meso-porosity. Similarly, a fixed exponent was used in the mixing law, combining the respective conductivities of macro-, meso- and micro-porosity.
In this paper, we demonstrate that these limitations can very easily be lifted through an original approach: the saturations in the three types of porosity are computed sequentially, faithfully following the oil migration reservoir model, which states that oil migrates first in the macro-pores, those pores rapidly becoming oil-wet, then in the meso-pores, the micro-pores remaining primarily water-filled.
In addition, the mixing law attempts to model the fact that meso-porosity appears to create a large divergence from Archie's law, which was not fully accounted for by the earlier models, by allowing for a variable exponent, itself function of pore type.
The split between macro-, meso- and micro-porosity is preferably derived from Nuclear Magnetic Resonance logs, but an alternative approach, that can be used when NMR logs are not available, has also been found to give satisfactory results, provided a reliable permeability log is available, which is in itself a challenge in these difficult formations.
This paper describes in details the equations used to arrive at the solution and shows examples of computation, with comparison to core results and to cased hole saturation obtained from a non Archie approach, in particular from pulsed neutron logs.
Development and Deployment of a "Bullheadable" Chemical System for Selective Water shut off leaving Oil/Gas Production Unharmed
Authors: Morgan J. , Gunn A. , Fitch G. , Frampton H. , Harvey R. , Thrasher D. , Lane R. , McClure R. , Heier K. H. , Kayser C. 
Published: December 2007

Abstract
A low concentration chemical treatment has been developed for pumping into a producer from surface to stop water production without harming hydrocarbon production. Matrix reservoirs are the primary target, though the upper permeability limit is not yet known. Numerical simulation has shown that while such a treatment would not be universal, many viable targets exist. Horizontal wells and multilaterals can make ideal targets, as would many vertical wells in heterogeneous formations and hydraulically fractured wells. Key performance targets were set for these chemical selective water-blocking systems (often called relative permeability modifiers). A dilute, water-dispersed system was favoured as treatment volumes were expected to be large in some cases. Because some of the chemical will enter valued oil/gas zones, the chemical must collapse to allow oil/gas to flow back through treated rock. A mechanism for this is described. To be of wide use, the chemical system should inhibit water production in reservoir rock with matrix permeabilities up to 10 Darcy, and at temperatures up to at least 110 °C. Simulation indicated the minimum degree of water block required for selected targets. However, laboratory tests showed that blocks beyond 99.5% could be slow to clean up to hydrocarbon flow under available drawdown. This gave a performance target range. Well targets should always have appropriate reservoir stratigraphy, but it may not be possible to log the wells pre-treatment to check hydrocarbon/water inflow distribution. Therefore some "high-risk" treatments would fail because of lack of separate oil inflow, or absence of any flow barriers (such as shale) between water and remaining oil. A simple remediation treatment option was therefore required. Also, low toxicity and compatibility with production facilities were seen as non-negotiable properties. We describe the key molecular design parameters derived to give a polymer/crosslinker system with the performance demanded from simulation. Laboratory test results showing the required water/oil block performance and long term stability (at 100 °C) are presented. Field deployment designs including "rule of thumb" treatment volumes are described. The polymer and crosslinker were manufactured at full scale for trial application. Quality assurance tests of this unique "dancing-thin-gel" system are detailed. Results of several full-scale "calibration" field trials are presented. Lab-field correlation appears to be acceptably robust.