bluuebunny/crossref_metadata_2025 huggingface dataset:
Reservoir Management in Maturing Oil Field
Authors: Pan Zhijian , Mu Longxing , Hong Liu , Yao Wenguang
Published: December 2007

The terrestrial reservoirs in China are mainly under waterflood development. Now these oil fields are generally running into mature waterflooding with 82.5% of water cut during which the oil field productions decline faster. As to the fact that the annual productions and remaining recoverable reserves still take a very important role in the oil industry, the advanced investigation and management on improved oil recovery in maturing fields have to be focused to keep the oil production stable and success in both economic and social benefits. Based on the determination of three kinds of factor controlling the distribution of remaining recoverable reserve[1], such as heterogeneity, fluid flow behavior in pore media and oil field development procedure, this paper presents integrated approaches to description of shale or flow barrier on waterflooding, heterogeneity on the basis of statistical geologic modeling and sedimentary petrography, and reservoir flow unit or hydraulic unit. By going through the single sand development procedure and fluid flow mechanism in heterogeneous pore media, the remaining reserve distribution and development in a reservoir with 95% of water cut have been explored.
Condensate Banking Dynamics in Gas Condensate Fields: Changes in Produced Condensate to Gas Ratios
Authors: Zhang H. R. , Wheaton R. J.
Published: December 2007

A general theoretical treatment of condensate banking dynamics was developed previously by Wheaton and Zhang1 to show how the compositions of heavy components of a gas condensate change with time around production wells during depletion. This current paper presents further analytical development of condensate banking dynamics on the behavior of produced condensate to gas ratios.

In this paper, a general theoretical treatment is attempted to show how the produced condensate to gas ratio varies with time during pressure depletion. Numerical simulations are pursued to confirm and supplement the theoretical analysis. Numerical welltest results and in particular liquid gas ratios are interpreted with the developed analytical model. The effects of low permeability and reservoir heterogeneity on condensate banking are discussed in terms of condensate to gas ratios.

Results have shown that no natural steady state exists with regard to condensate to gas ratio. Well tests to obtain data relating to the initial condition of the reservoir are not reliable once bottom hole pressure falls below dewpoint. The level of heterogeneity has a significant impact on the way a condensate bank develops. Only if pressure rises within condensate banking region following a period of depletion, will condensate to gas ratio increase and be greater than the initial condensate to gas ratio value. The condensate to gas ratio is very sensitive to the heterogeneity level in the reservoir and it is in itself an important indicator of reservoir heterogeneity.

In summary, the objectives of this paper together with our previous study of compositional changes are to introduce novel theoretical treatments to form a foundation for increased understanding of the condensate banking processes and of the well deliverability impairment.
Converting Gas into Liquid Fuels to Develop RCD Field, Central Sumatera, Indonesia
Authors: Arianto Indria Doria
Published: December 2007

Gas-to-Liquids (GTL) technology is a technology to converts natural gas into synthetic liquid hydrocarbon. This technology can be used for marginal gas field, can reduce gas-transportation costs, and helps satisfy the demand for cleaner fuels. The process of this technology consists of two steps, synthesis gas ("syngas") formation from natural gas, and synthetic liquid fuel formation using Fischer-Tropsch reaction. Synthetic liquid fuels produced from natural gas have long been known as the cleanest fuels available. RCD field located in Jambi area, approximately 60km South West Jambi, Central Sumatera, Indonesia. Discovered at 1985, RCD field developed as an oil field although geologic evaluation and seismic interpretation discovered large oil and gas reserves. This gas reserves currently undeveloped due to a limitation of gas markets. To develop RCD gas reserves, 18.6 MMscfd natural gas for 20-year production time can be converted into 1860-bpd synthetic liquid fuels consists of naphtha, kerosene, and diesel. Economic analysis indicates that converting into liquid can be used to commercialize RCD gas reserves with 5.54-year of payout time and 20.69% internal rate of return. Transformed into liquids, RCD gas reserves would be developed and have an access to markets through conventional oil infrastructure. This development would not only impact oil and gas supply, but also help to meet environmental requirements.
Optimising the Development of Blake Field under Tough Economic and Environmental Conditions
Authors: Du K. E. , Pai S. , Brown J. , Moore R. M. , Simmons M.
Published: December 2007

This paper summarises the studies performed during the optimisation of the Blake Field Development (UK) in the low oil price environment prevailing in 1999 and concurrent with the introduction of new tighter environmental regulations aimed at reducing the emission of greenhouses gases in the UK industry. It describes the technical work carried out up to the sanction of the project. The paper focuses on the principles and assumptions that determined the field development plan prior to the development drilling. The following aspects are addressed in the paper: 1) utilisation of existing infrastructure to economically develop marginal fields, 2) use of reservoir modelling techniques to optimise well placements, completion strategies and topside capacities, 3) practical means of managing reservoir uncertainties/risks during the development drilling and 4) application of updated reservoir management practices, with particular emphasis on the management of gas and water coning and on the development of this high permeability reservoir coincident with a thin column of fully saturated oil.
Effect of Dispersion on Local Displacement Efficiency for Multicomponent Enriched-Gas Floods Above the MME
Authors: Johns R. T. , Sah P. , Solano R.
Published: December 2007

Research on four-component one-dimensional displacements has shown that enriching the gas above the minimum enrichment for miscibility (MME) can substantially increase oil recovery for certain systems. Research has further shown that the oil recovery increase can be very sensitive to the level of dispersion at the enrichment chosen.

The main focus of this paper is to extend the research on four-component systems to displacements of multicomponent oils and gases where the recovery is affected by dispersion and enrichment. We consider here a twelve-component oil displaced by solvents enriched above the MME. For this case, the increase in recovery (displacement efficiency) above the MME can be as large as 15% OOIP depending on the level of mixing. The methodology outlined can be used as a screening tool to identify if a significant benefit may exist and further 2-D and 3-D studies are warranted.

A secondary focus of the paper is to examine in detail how dispersion affects recoveries and displacement mechanisms for the four and twelve-component systems. We show that for the case of the four-component model the displacement mechanism changes from a combined condensing/vaporizing displacement (CV) to a strictly condensing one as enrichment increases above the MME. We also show how to quantify the percentage of the CV displacement that is vaporizing or condensing by calculating the compositional distances between key tie lines identified from "dispersion-free" theory.
Why Oilwells Leak: Cement Behavior and Long-Term Consequences
Authors: Dusseault Maurice B. , Gray Malcolm N. , Nawrocki Pawel A.
Published: December 2007

Oil and gas wells can develop gas leaks along the casing years after production has ceased and the well has been plugged and abandoned (P&A). Explanatory mechanisms include channelling, poor cake removal, shrinkage, and high cement permeability. The reason is probably cement shrinkage that leads to circumferential fractures that are propagated upward by the slow accumulation of gas under pressure behind the casing. Assuming this hypothesis is robust, it must lead to better practice and better cement formulations
Integration of 3D-Seismic With Reservoir Simulation for Reservoir Characterization and Assessment of Alternative Exploitation Schemes of Field Development - A Case Study
Authors: Singh C. S. , Borgohain B. , Borgohain D.
Published: December 2007

This paper deals with a study where integration of 3D-seismic survey and reservoir simulation has aided in reservoir characterization which in turn have led to better and effective implementation of reservoir development schemes. Shalmari, one of the major oilfields in Assam-Arakan geological province of North-East India was discovered in 1986 and the initial field development was carried out on the basis of then available 2D-seismic data. During the course of initial field development, the area of major concern was the rapid decline of reservoir pressure. A detailed simulation study was carried out in 1994 for assessment of the pressure maintenance requirements and field development.

A 3D-seismic survey was carried out in 1994 in this area to obtain additional information on the reservoir geometry and structural configuration. The processing and interpretation of 3D-seismic data resulted in identification of additional faults thus bringing about a change in the structural configuration of the reservoir. The presence of identified faults was corroborated by pressure transient surveys. This necessitated in carrying out of another detailed reservoir simulation study by building up a geological model based on 3D-seismic data.

The basic objective of the study was to carry out a more accurate and reliable reservoir characterization apart from identifying the prominent direction of aquifer support and reassessment of the hitherto planned reservoir development scheme including ongoing pressure maintenance scheme. The results of the study carried out in 1997 also indicated possible increase in gross ultimate recovery as a result of water flooding. The financial analysis of the development schemes envisaged in this study was also found to be attractive.

Cross-discipline integration of data expertise and study has helped in accurate mapping of the minor faults and has provided a better insight into fault transmissibilities in the fluid flow simulation.
Production Impairment and Purpose-Built Design of Hydraulic Fractures in Gas-Condensate Reservoirs
Authors: Wang X. , Indriati S. , Valko P. P. , Economides M. J.
Published: December 2007

Hydraulic fracturing has been the stimulation/completion method of choice for the vast majority of gas reservoirs throughout the world. There is no fundamental difference in the design of hydraulic fractures in reservoirs of any permeability. However, for low-permeability reservoirs, obtaining the indicated length of the hydraulic fracture has been the key element in the execution of the stimulation treatments; for high-permeability reservoirs increasing the fracture conductivity (width multiplied by fracture permeability) is important. For the latter, "tip screen-out" treatments have been developed.

Damage to the fracture, which causes a reduction in the well performance, has manifested itself in two ways, 1) reduction of the proppant-pack permeability because of polymer residue, choking of the near-well region and over-displacement and 2) damage to the fracture face, i.e., reduction to the reservoir permeability normal to the fracture, because of polymer leakoff during the fracture execution. Both types of damage affect primarily higher-permeability formations, the first reducing the much-desired large fracture conductivity and, the second, providing an impediment to flow, which becomes important because of short fracture lengths. For long fractures and short penetrations of fracture-face damage the reduction to the well performance is insignificant.

In gas-condensate reservoirs a situation emerges very frequently that is tantamount to fracture-face damage. Because of the pressure gradient that is created normal to the fracture, liquid condensate is formed which has a major impact on the reduction of the relative permeability-to-gas. Such a reduction depends on the phase behavior of the fluid and the penetration of liquid condensate which, in turn, depends on the pressure drawdown imposed on the well. These phenomena cause an apparent damage, which affects the performance of all fractured wells irrespective of the reservoir permeability (including very low-permeability values). Well testing of such wells would invariably calculate much shorter apparent lengths than actually placed.

We are presenting here a model that predicts the fractured well performance in gas-condensate reservoirs, quantifying the effects of gas permeability reduction. Furthermore we present fracture treatment design for condensate reservoirs. The distinguishing feature primarily affects the required fracture length to offset the problems associated with the emergence of liquid condensate. Also, guidelines for the calculation of the appropriate pressure drawdown during production to optimize well performance are provided.
Simultaneous Propagation of Multiple Hydraulic Fractures – Evidence, Impact and Modeling Implications
Authors: Weijers L. , Wright C. A. , Sugiyama H. , Sato K. , Zhigang L.
Published: December 2007

Multiple hydraulic fractures have been observed in numerous field settings1–9. Direct evidence for the simultaneous growth of multiple hydraulic fractures has emerged over the last decades by coring through propped hydraulic fracture treatments in reservoirs; mineback experiments; intersection of multiple fracture (planes) through offset wells; multi-planar fracture propagation observed in micro-seismic fracture mapping and tiltmeter fracture mapping; and laboratory experiments showing complex fracture growth. The simultaneous growth of multiple hydraulic fractures beyond the near-wellbore area is therefore probably more the rule than the exception, especially when fracturing from a large perforated interval or in naturally fractured formations.

A comprehensive and consistent approach to approximately quantify and model multiple hydraulic fractures growth using observed fracture pressure feedback has provided significant insight into the mechanism of multiple fracture growth. A simplified concept of "equivalent" (equal sized) multiple fractures "competing" for fracture opening and leakoff has been used to approximate this complex phenomenon. This concept is very useful for quick, real-time fracture treatment analysis, and modeling results have also been calibrated by direct fracture diagnostic technologies to limit potential modeling solutions within reasonable bounds.
Long-Term Performance of Hydraulically Fractured Layered Rich Gas Condensate Reservoir
Authors: Al-Hashim H. S. , Hashmi S. S.
Published: December 2007

Compositional simulator has been used to investigate the effect of hydraulic fracture on the performance of a layered rich gas condensate reservoir. The reservoir consists of five layers having permeabilities ranging from 0.08 to 115 md with about 68 % of the gas reserve located in the lowest permeability layer. The fracture is assumed to penetrate all layers.

The results of this investigation show that hydraulic fracturing is effective in improving the productivity (PI) of the gas condensate wells both above and below the dew point pressure by about three folds as compared to the non-fractured wells. Hydraulic fractures are also found to delay the dew point pressure and consequently extend the production plateau above the dew point pressure. The results also show that as the dimensionless fracture conductivity increases, the long-term performance of the gas condensate reservoir is improved, and the improvement is more pronounced for longer fractures. It is also observed that once the dew point pressure is reached, the flowing bottom hole pressure drops sharply to the specified minimum flowing bottom hole pressure in the fractured and non – fractured cases. However, the drop is less severe in the fractured case. This sharp drop in the flowing bottom hole pressure results in dropping the productivity of the gas condensate wells.

At early times after reaching the dew point pressure the highest condensate saturations along the fracture faces are found to be in the highest permeability layer. However, at late times (after reaching pseudo steady state) it decreases and stabilizes at certain level above the critical condensate saturation.

Finally, formation cross-flow is found to improve the productivity of the fractured and the non-fractured wells. However, the improvement is more pronounced in the fractured cases.
Acidizing High-Pressure Water Injection Wells Using a New Low-Damage Acetic/HF Acid System
Authors: Wang Baofeng , Jiang Weidong , Liu Xihua , Feng Puyong
Published: December 2007

A significant loss of injectivity was observed in some of the high-pressure water injection wells on the Chunhua Oilfield the east of China due to severe formation damage, believed to be caused by fines and clay. This paper details the results of matrix acidizing treatments carried out in Chunhua sandstones, using a new low-damage acetic/HF acid system. The new low-damage acetic/HF acid systems, which will be referred to as "LDA-1", can coordinate aluminum fluoride complexes and buffer the spent HF fluids. The coordination of aluminum fluoride complexes helps alter the aluminumfluoride equilibria, which minimizes the amount of AlF3 in solution and forces the HF reactions to lower F/Al ratios. This system increases the effectiveness of the treatment and overcomes the damaging precipitation of aluminum fluorides during the HF reactions.

A series of laboratory short-core and long-core flow tests has been fully analyzed. Coreflood results showed that the core permeability increased after the treatment. Permeability ratio(final/initial)of reservoir cores exponentially increased with the acid injection rate. Acidizing returns in coreflood were analyzed to better understand the chemistry involved in HAC/HF acidizing. Returned samples were analyzed with inductively coupled plasma (ICP) and 19F nuclear magnetic resonance (NMR) spectroscopy. The combination of ICP and 19FNMR determined fluoride distribution on silicon and aluminum in the samples and the extent of HAC/HF fluid reactions.

The case historie included in this paper is treatment carried out on one formation in Chunhua Oilfield. The field test results shows that LDA-1 mixture is able to generate several fold increases in the injectivity of the wells. They include remedial treatment carried out on zones which had experienced detrimantal results due to poorly-designed conventional HF acid stimulations.

The treatment of CHC23–22 well was monitored with a real-time monitoring program, that showed that the skin factor has dropped from about 13 to –0.21. Following the treatment, injectivity of this interval increased from 0m3/d to 100 m3/d. The real-time monitoring plot shows that the skin has dropped continuously during the injection of preflush and LDA-1, what has proven to be effective for deep damage removal. The LDA-1 system treatment was able to increase the injectivity and sustain it for more than 6 months.
A Study of Fluid Leakoff in Hydraulic Fracture Propagation
Authors: Yew C. H. , Ma M. J. , Hill A. D.
Published: December 2007

A pressure dependent fluid leakoff (PDFL) model and a constant fluid leakoff model (CRFL) model are incorporated into a 3D fracture simulator for studying the effect of fluid leakoff on propagation of a hydraulic fracture. In order to make a meaningful comparison, the leakoff coefficient used in the CFL model is calculated by equating its final fracture area to that predicted by the PDFL model. The propagation behavior of a hydraulic fracture based on these two fluid leakoff models are assessed and evaluated by comparing the calculated time histories of the bottom hole pressure, fracture opening width, and proppant distribution inside the fracture.

Although the agreement between the predicted results from these two fluid leakoff models are good, detailed features in the calculated time histories of BHP and fracture opening width are very different. The difference is large during the fracture growth period, but starts to decrease when proppant packing begins. The results from this study suggest that a more accurate information on propagation of a hydraulic fracture can be obtained by taking the pressure dependent fluid leakoff into consideration.
Computer Simulation of Multilayer Hydraulic Fractures
Authors: Gu H. , Desroches J. , Elbel J. L.
Published: December 2007

When a hydraulic fracturing treatment is carried out in a layered formation, multiple fractures may propagate simultaneously in different layers. It is important to determine whether the multiple layers can be effectively stimulated in one treatment or if a multi-stage treatment is a better solution. Present fracturing models are mostly adequate to design and evaluate multiple stage treatments. In this paper, a computer simulator of multi-layer fractures is presented with the view of designing and evaluating simultaneous fracturing treatments in layered formations. The simulator rigorously calculates the flow rate distribution into multiple fractures based on mass conservation and pressure continuity principles. The fracture in each layer is treated as a pseudo-three-dimensional (P3D) hydraulic fracture model that allows height growth into adjacent layers. The multiple fractures are inter-related not only by the hydraulics through the wellbore, but also by the mechanical interaction through the rock formation, which is important when the stress barriers between layers are weak and fractures grow close to each other. The fracture growth behavior observed from other geomechanics studies is applied in this model. The results from this simulator and a previous one based on the PKN model are compared and discussed. The importance of fracture height growth on flow rate distribution and propped fracture geometry is demonstrated. Tip screenout and near-wellbore screenout in one or more fractures are simulated, showing flow rate diversion into other fractures after screenout occurs in one fracture. Simulation results also show that perforation erosion may have an undesirable effect on the ratio of slurry volume to pad volume in each fracture. Measured data of pressure and flow rates from a field test are compared with the simulation results and good agreement is observed. Based on the results of the simulator, recommendations on the design of simultaneous fracturing treatments of multiple pay zones are presented.
Numerical Simulator for the Combination Process of Profile Control and Polymer Flooding
Authors: Yuan Shiyi , Han Dong , Wang Qiang , Yang Hua
Published: December 2007

This paper presents a three-dimensional, three-phase, nine-component mathematical model that can be used as a practical tool for the simulation study on the combination process of profile control and polymer flooding (CPPCPF). This model considers the major mechanisms, principal physico-chemical phenomena and important influence factors during the complicated process, such as the gel formation, mobility performance, blockage characters, gel movability in porous media and various effects caused by gel system as well as the factors involving in the process of polymer flooding. Based on the model, the corresponding numerical simulator is developed subsequently, which can be used for simulating primary production, water or polymer flooding, crosslinked profile control, in-situ permeability modification, low concentration flowing gel (LCFG) injection and any combination of above processes. The simulator has been applied to simulate LCFG experiments with the good consistency between laboratory and simulation results. Effects of various factors on displacement mechanism and oil recovery have been studied based on multi-serial simulating results. Several oilfield pilot tests according to the simulation studies and injection designs have been carrying out with encouraging preliminary results. The applications have shown the powerful capability of the simulator, which is very useful for CPPCPF mechanism study and oilfield performance prediction.
Development of FEM Reservoir Model Equipped with Effective Permeability Tensor and Its Application to Naturally Fractured Reservoirs
Authors: Park Y. C. , Sung W. M.
Published: December 2007

The numerical simulation of naturally fractured reservoirs is commonly based on the continuum dual-porosity model. However, the model needs to assume that the fractures form very regular patterns, different from field observations. In order to overcome this problem, this study proposed a method that considers the characteristics of the real fracture system, and developed a two-phase transient FEM model being able to implement effective permeability tensor. For the permeability of natural fractures assigned to the numerical grid, Darcy’s law in matrix and cubic law in fracture were adopted for considering the flowing characteristics in discrete fracture network (DFN) approach. The developed model was applied to paludal sand reservoir of MWX (multi well experiment) site to demonstrate the validity and the applicability of the model for the naturally fractured reservoirs. The estimated average permeability in the MWX is almost identical compared to the results of the welltest analysis. Then the numerical simulation with the FEM model was performed by using the transient pressure recorded from gas well test on the MWX #1. From the results of BHP and pressure distribution within the system, it was noted that the model with effective permeability tensor generated almost identical results against DFN model in the aspects of the behavior and the direction of fluid propagation with pressure decline, and therefore, the proposed model is considered to be more efficient in terms of the computation time as well as the required storage capacity. Also from the upscaling study, it was shown that even with fewer numbers of gridblocks the developed model can effectively describe the directional flow caused by the fracture characteristics such as orientation and density of the fracture.
Clinton Well Performance Predictions Based On Flow Tests - A Well Study
Authors: Slider H.C.
Published: December 2007

Introduction

The objective of this paper is to demonstrate methods of testing and predicting the behavior of very tight gas wells that must be tested under nonideal conditions and that result in data that does not conform to the ideal radial flow concepts. Isochronal testing using constant production rates and bottom hole pressure guages is well understood by most engineers. Interpretation of radial flow isochronal data to obtain the gas well performance when it reaches pseudo steady state flow is also well defined. However, it appears that the flow of gas from a very tight reservoir with a "large" artificial fracture at the well has not been treated in a practical manner.

It will be shown that such a well tends to flow under linear unsteady state infinite acting conditions for relatively short periods of time. Then the well gradually changes to a radial flow geometry. An understanding of these flow conditions can lead to an approximate prediction of the gas well behavior with the accuracy depending upon the length of the flow tests and the accuracy of the "guesstimate" of the drainage area of the well. The treatment of the subject is based on a flow test of a gas well producing through the annulus while water production is being pumped through the tubing. Only surface pressures were measured during the flow tests.

CONSTANT RATE DRAWDOWN AND ISOCHRONAL TEST THEORY

Very tight low permeability reservoirs are generally completed by hydraulically fracturing the well during completion. A long vertical fracture and very low permeabilities permit the well to exhibit linear flow characteristics for very short periods of time. This is demonstrated in Fig. 1. The very low permeability means that the disturbances in the reservoir caused by initiating production will move at a relatively slow rate through the reservoir. Since the effect of the disturbance will move outwardly from the long fracture it means that except for the relatively small amount of the reservoir near the ends of the fracture the flow will be linear. Of course the longer the fracture is the less will the flow into the ends of the fracture cause the overall behavior to deviate from a linear flow geometry.

As the affected volume of the reservoir increases with the production time, the fixed length of the fracture becomes smaller in relationship to the affected volume of the reservoir until substantially radial flow will exist throughout most of the drainage area. Thus, for small producing times, t, we would expect the pressure behavior of a well being produced at a constant rate to be governed by an equation for the constant rate infinite acting linear flow behavior in a reservoir.
New Solids-Free Drill-in Fluid for Low Permeability Reservoirs
Authors: Cobianco S. , Bartosek M. , Lezzi A. , Massara E. Previde , Guarneri A.
Published: December 2007

The most widely used drill-in and completion fluids for seepage loss control in payzone are water-based mud containing polymeric additives and sized calcium carbonate or sized salt. These inorganic bridging solids are very effective in sealing the pore throats of the porous matrix and preventing formation damage but owing to their brittleness they will grind down during circulation and handling. This particle degradation makes it difficult to maintain the correct particle size distribution during drilling operations and can cause a deep penetration of the finest solids into the formation.

A novel, solids-free drill-in fluid system containing a biopolymer as viscosifier and a highly crosslinked starch and microfibrous cellulose as fluid loss control agents has been developed for drilling and completing low permeability formations. This fluid composition provides the qualities of both good drilling mud and a non-damaging completion fluid. This paper presents the laboratory results obtained from coreflooding tests carried out on this solids-free drill-in fluid in limestone cores with permeability lower than 100 mD. The synergistic interaction of the biopolymer with a highly crosslinked starch and a microfibrous cellulose material promotes the quick formation of a very thin (ca. 50-60 µm) and impermeable filter cake which prevents polymer and drilled solids invasion into the core. The results show that the filter cake can be completely removed by backflooding and the permeability can be completely recovered. The non-damaging effect of this drill-in fluid was also observed when its density was increased to 1.48 g/cm3 by potassium formate brine. Good filtration and rheological properties were also maintained when simulated drilled solids, e.g. reactive and non-reactive clays were added. Core plug invasion and thickness and the morphological structure of the filter cake, investigated by means of Scanning Electron Microscopy, is also discussed.
Water-Dispersible Resin System for Wellbore Stabilization
Authors: Eoff Larry , Chatterji Jiten , Badalamenti Anthony , McMechan David
Published: December 2007

Global economic conditions require innovative and state-of-the-art wellbore-stabilization methods to reduce the total cost associated with the construction and life cycle of a well. Stabilization includes preventing unwanted fluid or gas flow into or out of the wellbore, preventing the flow of particulates into the wellbore, and mitigating formation compressive or tensile failure. Solutions should involve the use of real-time drilling data obtained from measurement-while-drilling (MWD) and logging-while-drilling (LWD) systems, advanced fluid chemistries, computer-generated placement procedures, and job histories of similar well problems. The end result of a properly designed wellbore stability process is reduced well-construction cost. Costs are reduced by minimizing nondrilling rig time, eliminating emergency or unplanned casing strings, and reducing unwanted fluid/ gas flow that causes environmental hazards.

This paper focuses on a water-dispersible, aliphatic epoxyresin system (WDR) that has been developed to plug fractures/ vugs, reduce formation permeability, and artificially increase formation fracture gradients. Aliphatic epoxy resins impart water compatibility, which is an advantage over more commonly used aromatic epoxy resins that cannot tolerate water contamination. The aliphatic epoxy-resin system can be used during drilling and can be pumped as a neat resin, resin/sand or resin/ barite mixture, or dispersed in water- or oil-based drilling fluids. A pill can be spotted over trouble zones followed by a pressure squeeze that forces resin through the mud filter cake, where it then hardens and consolidates the formation. This paper presents data that illustrate the system's capability to reduce permeability, dramatically enhance mechanical properties of the formation, and solve various production-related wellbore stability problems such as annular casing pressure, water production, and multilateral junction sealing.
Optimization of SBM Formulations for Minimum Damage
Authors: Herzhaft Benjamin , Audibert-Hayet Annie , Sandford Rick , Freche Patrick
Published: December 2007

Synthetic based mud formulations (SBM) are specially proposed to drill long open hole sections since such formulations present enhanced lubricating properties and limit torque and drag problems. When the mud is in contact with horizontal open hole section for a long period of time in overbalanced conditions, it induces invasion phenomena that may be detrimental for reservoir productivity.

Formation damage due to OBM or SBM is largely due to solid invasion occurring during the first steps of filtration when an internal filtercake is built. The damage is evaluated in terms of cake formation, filtration volume and back flow properties. During the back flow, when the cake is partially or totally removed, an overpressure to initiate flow through filter cake, named flow initiation pressure (FIP) appears and may affect the porous media stability. In case of unconsolidated reservoir, such a pressure may induce fine particle production which may affect the surface facilities and have to be removed from the production fluid.

Additives used in OBM formulations may either be dispersed or solubilized in the oil phase. A comparative study was performed with two kinds of additives through classical mud tests i.e. rheological characterisation, emulsion stability and static filtration tests and formation damage experiments on natural cores put under downhole saturation conditions. Organo soluble additives may enhance the cake properties and limit the invasion both under dynamic and static conditions. The dynamic filtration properties were studied on a large range of reservoir permeability. Compared to a classical additive, the organo soluble additive used in a SBM formulation induces a lower invasion on low permeabilities.

On high permeability sandstone, it was noticed that the invasion is not damaging since during the black flow, the pressure evolved as a function of time up to a constant low value. This indicates a high value of ultimate return permeability due to the production during the back flow of the additives present in the filtrate but removable in the oil flow.
Permeability Modifications by In-Situ Cations Hydrolysis
Authors: Busolo M. A. , Mogollón J. L. , Rojas Freddy
Published: December 2007

The precipitation of inorganic compounds by cation hydrolysis could be an alternative method to modify injection and production profiles. The precipitation in porous media can be caused by a pH increase as result of fluid-rock interactions, direct neutralization with base or thermal decomposition of a basic precursor, placed as additive. This paper ascertains the effects of precipitant solutions of zinc or aluminum salts, plus urea as basic precursor, on permeability, at reservoir conditions.

Flow tests were conducted in 30 cm Berea cores, at 140°C, 800 psi. Different injection schemes were tested, varying the number of precipitant solution batches, i.e. 1 and 2, and the shut-in time, i.e. 24 and 48 h. After that, fresh water was injected to determine permeability reduction, as well as the effect stability, along the core and in 3 sections of 10 cm each.

The results show 98% as maximum permeability reduction located mostly in the inlet section, while in the outlet section the maximal reduction achieved was 80%. In all cases, the effect was stable for at least 10 PV of water injected. Furthermore, permeability was not restored by 0.1 N HCl solutions. Precipitation occurs at T>70 ºC; it takes 2-4 hours at 80 ºC, and 40 min. at 140 ºC; enough time for the placement of the solution into porous media. Scanning electron microscopy images of the treated Berea cores demonstrated different shapes of particles precipitated, depending on the cation; all of them reduce permeability by filling the porous space.

The aforementioned results show that in-situ cations hydrolysis induced by basic precursor have the potential to modify injection and production profiles in the field, with some possible placement advantages.
Paraffin Deposition in Oil Production
Authors: García María del Carmen
Published: December 2007

Paraffin deposition problems in oil production, transportation and storage will be presented. An experimental methodology for deposits characterization and paraffin deposition control, oriented toward the identification of "tailor made" preventive or remedial treatments, will be shown. Research results including some correlations between oil composition and wax appearance temperature (WAT), as well as paraffin inhibitors efficiency, will be presented. The knowledge provided in this paper has direct application to paraffinic crude oils productivity enhancement in terms of costs reduction (cleaning and deposits removal), and oil production improvement. On the other hand, correct selection of a prevention treatment will avoid extremely expensive and inefficient "trial-and-error" procedures, and even severe formation damages due to eventually paraffin deposition in the reservoir. This last phenomenon can be a consequence of the precipitation of crude oil paraffin's heaviest components after improper operations, like "hot-oil" treatments. The designed experimental strategy starts with the deposit analysis, which includes a preliminary physical separation of the organic and inorganic components. The organic fraction characterization, in terms of its hydrocarbon components, allows to discriminate between wax and asphaltenes plugging. Once the paraffin deposition problem is identified, the original crude oil characterization is carried out. Specific compositional characteristics of the crude oil allow to select an adequate paraffin deposition treatment, based on previously established correlations. An example selected from field operations carried out in Venezuelan facilities, will illustrate the benefits derived from this methodology.
Successful Applications of Anti-agglomerant Hydrate Inhibitors
Authors: Frostman L. M. , Przybylinski J. L.
Published: December 2007

While it is important to approach each system individually when dealing with new types of performance chemicals, the anti-agglomerants have been found to be suitable for hydrate control in most of the situations encountered in offshore oil production. Anti-agglomerants have now been used in several field applications in deepwater systems - both in subsea wells and dry tree wells - under both flowing and shut-in conditions. During these applications, no hydrate problems were observed. The anti-agglomerants caused no upsets in the topsides operations; there were no emulsion problems, no foaming problems, and no water quality problems. The products were deployed through the existing methanol injection systems without incident. Application rates were significantly lower than if methanol were used. Potential advantages of the anti-agglomerants over methanol include smaller umbilicals, smaller pumps, smaller storage facilities, and less frequent supply trips.
Money Left On The Table In Sealed, Competitive Bidding: Federal Offshore Oil And Gas Lease Bids
Authors: Dougherty Elmer L. , Lohrenz John
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The expected values of money left on the table are evaluated for lognormally distributed, sealed, competitive bids. Functions are developed and evaluated that can be used to make a priori predictions of money left on the table and a posteriori comparisons with actual bids. Extensive comparisons of federal offshore oil and gas lease bids show agreement with the theoretical function except that some extreme bids appear to depart from lognormality.

Introduction

We do not know the competitive bidder who first bewailed the amount of "money left on the table" after winning by being the highest (or lowest) with a sealed, competitive bid. The phrase may be colloquial, but the meaning is phrase may be colloquial, but the meaning is clear. If the highest bid wins, money left on the table is the amount by which the winning, highest bid exceeds the next highest bid. Money left on the table is the amount of money bid in excess of what would have been necessary to win had the bids been known.

Since the first federal offshore oil and gas lease sale on Oct. 13, 1954, through a sale held on July 29, 1975, 2,580 leases receiving 9,142 sealed, competitive bids were issued to the highest bidders. The winning bidders spent over $15 billion for the leases, leaving about one-half of that money on the table. Thus, studies in the statistics of money left on the table have a practical cogency.

We used these 2,580 leases as a data base throughout this study. All 9,142 sealed, competitive bids were used excepting 170 (1.9 percent of the total), which were deleted as percent of the total), which were deleted as low, noise bids using the 30–30 deletion algorithm* of Dougherty and Lohrenz.

A BRIEF REVIEW AND SOME DEFINITIONS

Previous studies have provided the practical and statistical basis for considering practical and statistical basis for considering federal offshore oil and gas lease, sealed, competitive bids as lognormally distributed. Dougherty and Lohrenz used -the lognormal distribution and derived an expression giving expected values of money left on the table as a function of the standard deviation of bids, and the number of bids per lease, n.
Rheological and Structural Properties of Heavy Crude Oils in Relation with their Asphaltenes Content
Authors: Hénaut I. , Barré L. , Argillier J-F. , Brucy F. , Bouchard R.
Published: December 2007

Heavy oils represent a strategic source of hydrocarbons as their reserves are of the same order of magnitude as the ones of conventional oils. The production of these crudes remains low, in particular because of their very high viscosities. The asphaltenes which they contain are known to be responsible for this situation. Actually, many studies have shown that these high molecular weight polar components self-associate more or less severely depending on different parameters like temperature, concentration and solvent quality. The experimental work was usually performed using simple organic solvents (toluene, heptane…) which are not representative of complex heavy crude oils. Therefore, we decided to investigate the rheological behavior of asphaltenes in their natural environment and in relation with their structure. Samples coming from the same crude oil were prepared with different asphaltenes contents, from 0 to 20% in weight. The apparent viscosity and the oscillatory modulus (G' and G") were measured with a controlled stress rheometer and SAXS were undertaken. Two domains were identified. The first one concerns the dilute samples for which the relative viscosity increases linearly with the weight fraction of asphaltenes. In this domain, the aggregates of asphaltenes stay independent from one another and have the same radius of gyration. For the more concentrated samples, the viscosity increases dramatically because of the aggregates entanglement as was observed by SAXS. Concerning the oscillatory experiments, the elastic character increases from the first domain to the second one, which confirms that a structural change occurs. Combining the rheological measurements and SAXS reveals an analogy between heavy crude oils and concentrated colloidal systems of polymer solutions. All these results help the understanding of the flow properties of heavy crude oils and aim to contribute to the improvement of their transport.
A Field Case History: Chemical Treatment of a Produced-Water Injection System Using Anthraquinone Improves Water Quality and Reduces Costs
Authors: Law M. D. , Kretsinger M. B. , Burger E. D. , Schoenenberger J. G. , Ulman M. A.
Published: December 2007

Sulfate-reducing bacteria (SRB) are notorious for causing decreases in the quality of oilfield injection waters due to their ability to increase total suspended solids (TSS). Through dissimilatory respiration, SRB reduce sulfate to sulfide, which subsequently forms hazardous hydrogen sulfide (H2S) gas. H2S is not only an environmental health threat, but it also can indirectly contribute to decreased water injectivity by reacting with soluble iron to form iron sulfides. These very tenacious solids can plug formation faces, thereby reducing the volume of water a well can take at a specified injection pressure. A previously reported study showed that an anthraquinone treatment program was capable of controlling biogenic H2S generation while maintaining TSS within field specifications (SPE 50741). Subsequently, an anthraquinone program was initiated in Chevron's Lost Hills Field (California) produced water injection system. Chevron's water treatment program had been a continuous injection of a quaternary biocide compound plus a weekly slug dose injection of another biocide (acrolein) to control SRB, TSS and H2S. Chevron also maintained a monthly pigging program that required the disposal of classified hazardous wastes due to the continuous injection of the quaternary chemical. The new treatment program included weekly slug injections of acrolein followed by a slug dose of a soluble form of anthraquinone. The monthly pigging program was maintained, but the continuous quaternary compound usage was eliminated. This paper describes the produced water injection system, the treatment program and the parameters monitored, including TSS, SRB, and H2S levels before and after the implementation of the anthraquinone treatment program. These data show that the new program has resulted in injection water quality which is currently better than previously measured during the recent history of the field and which now for the first time consistently meets Chevron's TSS specification.