bluuebunny/crossref_metadata_2025 huggingface dataset:
Predicting Productivity of Multiple-Fractured Horizontal Gas Wells
Authors: Zhu D. , Magalhaes F. , Valkó P. P.
Published: December 2007

In low-permeability gas reservoirs, horizontal wells have been used to increase the reservoir contact area, and hydraulic fracturing has been further extending the contact between wellbores and reservoirs. This paper presents an approach to evaluate horizontal well performance for fractured or unfractured gas wells, and a sensitivity study of gas well performance in low permeability formation. A newly-developed Distributed Volumetric Sources (DVS) method was used to calculate dimensionless productivity index for a defined source in a box-shaped domain. The unique features of the DVS method are that method can be applied to both transient flow and pseudo-steady state flow with a smooth transition between the boundary conditions. By describing the geometric dimensions of the sources, productivity index for a horizontal gas well or a longitudinal fracture along a horizontal well is readily calculated. For transverse fractures with infinite conductivity or uniform flux, the superposition principle is used for multiple sources in the system. Wellbore frictional pressure drop is coupled with the inflow calculation from fractures.

The study compares the productivity of horizontal wells versus horizontal well(s) with hydraulic fractures. The effects of parameters such as reservoir permeability and anisotropy ratio, horizontal well spacing and placement, and orientation of fractures along a horizontal wellbore are also presented in the paper. The objective is to optimize well design based on the maximum productivity and economic benefit. The results of the study show that the performance of horizontal wells can be very sensitive to the vertical permeability of the formation. In low vertical-permeability formation (high anisotropic ratio), fractures improve well performance significantly. In large drainage area, multiple-well placement, even with shorter wellbore length, increases productivity, compared with single-well placement. The study provides insight on optimization of production performance in low-permeability gas reservoirs.
Evaluation and Optimization of Low-Conductivity Fractures
Authors: Manrique J. F. , Poe B. D.
Published: December 2007

This paper presents the results of an investigation of the design and analysis of low conductivity fractures. The mathematical model used in this work is a practical alternative to estimate the degree of stimulation by means of a Stimulation Index (SD) and for evaluating the efficiency of wells with low conductivity hydraulically induced fractures. We utilize the dimensionless productivity index solution (JD) for finite-conductivity vertically fractured wells in closed rectangular bounded reservoirs and their corresponding pseudo-steady state shape factors under boundary-dominated flow conditions. Designing the optimum stimulation fracture treatment in this case is more heavily weighted on the achievable Stimulation Index (SD), for a given set of reservoir parameters and job sizes and on optimization of the flow rate and cumulative production.

We discuss the reasons for and alternatives to conductivity impairment within the fracture; fracture cleanup, width changes, conductivity degradation with time and stress effects are discussed. Field evidence indicates how these effects affect the fracture conductivity, affecting deliverability and inflow performance.

A practical performance criterion that focuses on conductivity improvement is used to improve performance of fractured wells. We use guidelines for choosing from the available fracture stimulation alternatives to focus on the technical merit of each technique and their application for improving fracture efficiency and deliverability, and include the use of higher breaker concentrations, lower polymer loads, and use of proppant with better resistance to stress (conductivity and permeability). Field examples and applications are provided for fracture stimulation evaluation and optimization.

This paper also introduces a way to evaluate and optimize the financial performance of fracture treatments. The financial criteria link the well deliverability or well potential (technical limits) to the fracture costs (or total well costs or OPEX).

Optimization is achieved by Net Present Value maximization and by generating an incremental return on investment due to the optimization steps. In this manner, we can financially quantify the engineered options for increasing well performance and optimization of the Stimulation Index (SD) while taking into account the associated costs into a financial model.
Sandstone Matrix Stimulation Can Improve Brownfield Oil Production When the Chemistry and Procedures Are Correct
Authors: Yong Yin-Chong , Shaikh Karim , Queiros Joao , Song Yan , Srisa-ard Surasak , Chan Keng Seng , Samuel Mathew
Published: December 2007

Improving oil and gas production from the Brown Fields is now more important than ever to the operating companies, as the oil price remains record high. Matrix stimulation is often preferred as it could generate additional production gain with relatively low level of investment.

In the recent acidizing campaign in Brunei, a particular challenge was the flowback of tubing pickling and spent acids, and neutralization of the spent acid on the surface. A series of effective methodologies for the stimulation of offshore multi-layer sandstone oil reservoirs was implemented. The chemistry and art of four different acidizing methods involving Tubing Pickling, Bullheading, Diversion and Coiled Tubing placement were used. Stimulation of over forty wells utilizing different acid systems and procedures resulted in noticeably different production gains. The short and long term results are correlated with the stimulation procedures and practices. The present paper describes a comparison of procedures and production gains during these acid stimulation treatments. The cost, logistics and operational constraints due to specific Brunei offshore environment and conditions will also be discussed. Post-treatment production gain is correlated with the efficiency and timing of the flowback process.

Use of computer-based virtual laboratory tool for the fluid selection, coreflow laboratory testing for the fluid optimization at downhole conditions and evaluation of fine migration tendencies were investigated before the treatment. The results were compared with the one from other operators in the same environment and reservoir conditions. Review of post acidizing results came up with recommendations and lesson learnt for future campaigns. This effort will certainly enhance the success ratio of the sandstone acidizing treatments.

Significance: Developed lessons learnt to increase the success ratio of sandstone stimulations.
Advanced Mud Logging: From Archie's Dream to Reality
Authors: Loermans Ton , Kanj Mazen , Bradford Charles
Published: December 2007

Advanced Mud Logging (AML) has been named "Archie's Dream" since AML will fulfil what must have been Archie's dream. That is: obtain high resolution rock parameters as quickly as (wireline) logs. Up until the recent past, the idea of obtaining quantitative petrophysical parameters from mudlogging seemed a dream. However, AML is moving towards continuous, real time determination of rock and fluid parameters from drill cuttings, drilling parameters and mud (gas) returns, in aid of well evaluation and reserves calculation.

The value of (to a large extent conventional) mudlogging for hydrocarbon productivity prediction is already significant, confirming that mud gas measurements, if properly analysed, provide very valuable information for production testing decisions.

Through application of rock typing techniques and rock catalogues, amongst others, reasonable electrical parameters, which normally require elaborate core measurements, can be obtained near real time from cuttings descriptions.

Tests on a method for direct permeability measurement on cuttings confirm the potential for this method for many circumstances.

Micro and nano indentation techniques are being tested to provide rock mechanical properties also from drill cuttings.

As the techniques to determine several of the key parameters are becoming more firmly established, AML is entering the stage of actually providing a significant input for a complete formation evaluation.
State of the Art – Natural Gases Viscosity under Reservoir Conditions
Authors: Gawish Ahmed , Al-Homadhi Emad
Published: December 2007

The influence of fluid viscosity on flow is especially important in petroleum reservoirs. Gas is now a highly desirable hydrocarbon resource. An accurate prediction of transport properties of natural gases is very important in the design and operation of fluid transportation, production, and processing. Viscosity is one of these properties. Many viscosity correlations are available but each has limitations in the range of applicability1–7. Only the Carr et al8–12. charts include the correction for gas impurities and reservoir pressure and temperature. Using Carr et al. charts you have to follow five steps to find the natural gas viscosity at any condition. As a results, some errors and inaccurated will occur and more time will be consumed. Standing13’14 proposed a convenient mathematical expressing for calculation the viscosity of the natural gas at atmospheric pressure and reservoir temperature, μ1. Standing also presented equations for describing the effects of impurities on μ1. Dempsey15 expressed the viscosity ratio (the viscosity at high pressure to the viscosity at 1 atm), by using reduced pressure and temperature.

Using the Standing equation and the slightly revised Dempsey equation, the natural gas viscosity at high pressure can be found by one step only. It includes all corrections for gas impurities. Its also includes any condition at the reservoir pressure and temperature.
On the Use of Acid and Proppant Fracturing Treatments to Develop Carbonate and Sandstone Reservoirs – Field Examples
Authors: Rahim Zillur , Bartko Kirk
Published: December 2007

For the past five years Saudi Aramco has implemented different stimulation techniques to develop its gas reservoirs.1,2 With the growing demand in gas and the need to meet the gas processing plant capacities' the stimulation treatments have provided excellent completion means for enhanced gas recovery. This paper provides an overview of the various stimulation methods used and presents the challenges encountered in different fields due to reservoir heterogeneity' low permeability, condensate dropout and banking, sanding of unconsolidated formations' high pressure and temperature, etc., and the systematic approach used to encounter such challenges to optimally develop the reservoirs. Several field examples are cited to show the success of stimulation technology.
A Fully-Implicit Fully-Coupled Well Model for Parallel Mega-Cell Reservoir Simulation
Authors: Fung Larry S. K. , Su HoJeen , Tan Cheng T. , Hemanthkumar Kesavalu , Pita Jorge A.
Published: December 2007

Various production and injection processes with the attendant well controls represent the most important boundary conditions for a reservoir simulator. Therefore, it is of significant interest that the modeling of wells be done in an accurate and robust manner. Recent development of horizontal wells, maximum reservoir contact (MRC) wells, and smart wells further increase the demand for more comprehensive numerical treatment of wells. In mega-cell simulation, wells can be perforated in more than one hundred computational layers known as well cells whose layer productivity indices (LPI) can vary widely. Contributions of inflow from each of the well cells make up the total target well rates. Collectively, the well cells communicate through the wellbore pressure boundary condition. A converged time step means the material balance is satisfied for all grid cells plus all the well constraint equations active at that particular time step.

In this paper, the fully-implicit fully-coupled treatment of well constraint equations in the context of parallel mega cell reservoir simulation is described. In parallel computation utilizing several processors, grid cells are partitioned roughly evenly into these processing units. A single well can traverse several grid cells residing in multiple processors where information pertaining to well inflow must be gathered to construct the well constraint equations. These well equations are unstructured and are solved simultaneously with the multi-million grid cell material balance equations. The paper describes the well modeling equations and the numerical procedures for solving these equations in a fully-implicit fully-coupled manner. Furthermore, methods for treating fully implicit wells in several special simulation features such as local grid refinement, dual porosity dual permeability, and complex MRC wells with flow hydraulic calculation are also included. A number of examples on the advantages of applying the implicit well model as compared to the less rigorous well treatments are also discussed. In addition, for some mega-cell simulation cases, we compare the field-scale performance and parallel scalability of the methods.
Modeling and Upscaling Fracture Corridors- Uncertainties
Authors: Ozkaya S. I. , Bolle L.
Published: December 2007

This short paper presents an overview of some critical issues related to fracture modelling and upscaling, using as an example, borehole image data from a carbonate field in the Middle East.

Relationship between fracture density and mechanical layer characteristics is common knowledge. A fundamental question is whether fracture-prone units have a larger number of fracture corridors and mega-fractures. Fracture corridor spacing may be large controlled by the fault size and is independent of mechanical layers. Alternatively, the spacing of fracture corridors and mega-fractures may be controlled largely by mechanical layer characteristics to a large extent. In this Field, the fracture prone units seem to have higher number of fracture corridors and mega-fractures than less fracture- prone units.

One important step in fractured reservoir characterization is estimating the percentage of fracture fairways (fault zones) detectible from seismic data. Without such an estimate, fracture models can only yield a global history match and can not be used for well-planning. The importance of mapping fracture fairways is high when the fracture corridors are much clustered in fracture fairways and fault zones. For a low degree of clustering, it may not be so important to locate all fracture fairways, since fracture corridors will be widely spread with a low degree of connectivity. Fracture analysis showed that seismic fault maps show only half of fracture fairways and small faults that are present in this field. The remaining half of the faults must be generated stochastically and used in stochastic fracture corridor discrete and upscale models along with actual seismic faults. Introduction of stochastic faults poses a serious challenge to reservoir simulation because classical history match procedures can no longer be used to evaluate a fracture model.
An Accurate Set of Correlations for Calculating Critical Properties and Acentric Factors for Single Carbon Number Groups
Authors: Al-Meshari Ali A. , McCain William D.
Published: December 2007

In order to describe the phase behavior of a reservoir fluid and calculate its volumetric properties, an EOS requires the values of critical pressure, critical temperature, and acentric factor for each component. There are several correlations in the literature for calculating critical properties and acentric factor for each single carbon number group, SCN.

For heavy ends, accurate properties can be predicted with accurate representation of the critical properties and acentric factor. Direct measurement of the critical properties for heavy ends is not practical. So, characterization of the heavy ends is required.

In tuning EOS after splitting the plus fraction and assigning critical properties and acentric factor for each SCN group, the saturation pressure for the reservoir fluid will be matched at reservoir temperature using the extended composition. Since the experimental measurement for the molecular weight of the plus fraction has some uncertainty, it is reasonable to use the molecular weight of the plus fraction as the tuning variable for matching saturation pressure with the extended composition.

The critical properties and acentric factor for each SCN group extended from the plus fraction were calculated using six different sets of correlations, as discussed above. The main objective of testing these different sets of correlations is to find the set of correlations that will lead to the least adjustment for the molecular weight of the plus fraction when the measured saturation pressure is matched using the extended composition. Results show that using Cavett correlation for calculating critical properties and Riazi and Al- Sahhaf correlation for calculating the acentric factor will lead to the least adjustment in the molecular weight of the plus fraction when saturation pressure is matched with the extended composition.
Simulation of Underground Natural Gas Storage in Sarajeh Gas Field, Iran
Authors: Khamehchi E. , Rashidi F.
Published: December 2007

One of the main concerns in Tehran during winter is the pressure drop in gas transfer lines which leads to shortage in gas supply to the northern part of the city located in higher altitude. To deal with this problem, National Iranian Gas Company (NIGC) decided to store gas in nearby natural reservoirs during hot season and produce it during cold season. Sarajeh gas condensate reservoir, located 145 Km far from Tehran, was considered for underground gas storage (UGS) to deal with gas demand in Tehran.

First, the significance of UGS, different types of reservoirs considered for UGS and its history are presented; next, coarse grid model of the reservoir is built; simulation and history matching of Sarajeh gas field are introduced and briefly discussed and finally conclusions and recommendation for future work is presented.

Based on available information and those generated by the model, this field could be a candidate for UGS plan. The results showed that two horizontal and one vertical gas production wells need to be drilled to achieve pressure drop in the reservoir and deliver 150 MMSCF of gas per day including production from existing three gas producers. Reservoir performance after history matching using depletion scenarios is predicted and depletion last for 4.5 years. Ultimate recovery factor is 65% for gas and 40% for gas condensate. Following reservoir depletion to approximately 2400 Psi, gas injection cycles in 6 months during hot season with the injection rate of 160 MMSCF per day and gas production cycles in 5 months in cold season with the rate of 175 MMS per day can start. Total gas volume stored in each cycles is approximately 1 × 1012m3.
Increasing Oil Recovery of Channel Sandstone Reservoirs with Extra High Water Cut by Using Horizontal Wells
Authors: Bo Liu , Xin Liu
Published: December 2007

Salaxing oilfield of Daqing has been developed for more than 40 years and has entered the high water cut late development stage. The reservoirs are large lacustrine luvial delta facies with multi-layers, heterogeneity is serious, watered-out degree of the reservoirs are extremely uneven, remaining oil distribution is complicated too, but its potential to produce oil is still high, and is mainly concentrated in the thick reservoirs of sandstone sediment origin. To produce the remaining oil in the thick reservoirs, the currently used ways are selective perforation, deep profile modification, selective position fracturing etc., and the currently used methods are infill drilling, polymer flooding etc. However, the use of these ways and methods in vertical wells can't completely produce the remaining oil inside the thick reservoirs. This paper provides an example of a successful horizontal well with a horizontal section of 650 m and production rate of nearly 100 t/d, which is drilled in channel sandstone of 7 m (of which the lower part has been watered-out to a medium ~ high degree) with the remaining oil bearing thickness of only 3 m. The key technologies are lateral accretion interlayer prediction technology by detailed reservoir description, accurate remaining oil description to avoid the watered-out section of the horizontal well, and optimally perforation technology for horizontal well. This indicates that drilling horizontal wells in Salaxing oilfield of Daqing can increase the oil recovery of channel sandstones reservoirs with extra high water cut.
Enhanced Petrophysics: Integration of Core and Log Data for Improved Reservoir Saturation Monitoring
Authors: Ma S. Mark , Al-Hajari A. A. , Kersey D. G. , Funk Jim J. , Holmes K. , Potter G.
Published: December 2007

Oil migrating into a water saturated reservoir is a drainage process while waterflooding an oil reservoir is a water imbibition process. Many factors affect drainage and imbibition rock properties including pore structure, rock surface properties (lithology) and their interactions with pore fluids (wettability), and fluids displacement processes. Difference in drainage and imbibition is significant and this difference should be considered, but is often neglected, in reservoir saturation monitoring (RSM).

In this study, fundamentals of rock properties and their interactions with oil and water were reviewed. In a specially designed laboratory special core analysis program, both drainage and imbibition rock properties were measured in the laboratory, at reservoir conditions, using reservoir rock samples, crude oil, and synthetic brine. Wettability was restored by aging the rock samples in crude oil at temperature. Pore structure was characterized by integrating capillary pressure and petrographic studies. Rock lithology was determined by X-ray diffraction measurements and thin section examinations. All laboratory measurements were integrated to better understand drainage and imbibition rock properties.

In applying the laboratory determined rock petrophysics to field RSM, time-lapse resistivity logs were used to identify the current dynamic water-oil contact (DWOC). Above this DWOC, drainage rock properties were used for log processing while below this contact imbibition rock properties were used. Field examples are shown to demonstrate the applications of drainage and imbibition petrophysics in evaluating waterflood sweep and identifying intervals for potential side-tracks.
Efficiency of Vertical Gravity Separators in Gas Liquid Applications
Authors: Noui-Mehidi M. N. , Albarran M. Rivero , Wu J.
Published: December 2007

This paper is concerned with a study of the efficiency of vertical separators intended to gas liquid applications. A compact configuration of coaxial cylinders in which a multiphase flow is vertically flowing can achieve gas liquid separation by the use of gravity in a certain range of gas-liquid flow rates. With this method the separated liquid can be collected in the lower part of the system without any gas carry under. The stability limit of such separators has been identified regarding the inlet conditions and the geometry of the system.
Experimental Study on Additives Systems Used for Proppant Flowback Control in a Hydraulic Fracturing Treatment
Authors: Alqam Mohammad H. , Abass Hazim H. , Khan Mirajuddin R. , Caliboso Edwin T.
Published: December 2007

The use of proppant combined with various additives, as a mean to control proppant flowback in propped hydraulic fracturing treatments, has gained a wide support in the industry. A screenless hydraulic fracturing treatment has been applied as an acceptable completion strategy to mitigate sand production and/or production increase in non-associated gas reservoirs in Saudi Arabia. Understanding the parameters that maximize the life of propped hydraulic fracturing applications is very crucial in controlling sand production and maximizing gas/oil production.

This paper discusses the roles of closure stress, temperature, curing time and carrier fluids in attaining a maximum strength of the new systems compared to other additives following a propped hydraulic fracturing treatment. Also, the conductivity of RCP by itself and in combination with other additives has also been evaluated.

The study results showed that all the independent variables play important roles in achieving an appreciable increase in compressive strength of the new system in comparison with other additives. Also, the new system out-performed the other additives as it shows no reduction in conductivity experienced by proppant/fibers system. The application of this new system in the field confirmed our laboratory findings as it showed better productivity compared with the offset well treated with other additives.
Extended Matrix Acidizing Using Polymer-Acid Solutions
Authors: Amro Mohammed M.
Published: December 2007

The present work investigates the effect of adding polymer as a retarding agent to acid solutions to slow and control the reaction in matrix acidizing treatment of carbonate rocks. Two different polymers, Polyacrylamide (PAA) and Polysaccharide (Xanthan) and three different acids, hydrochloric acid; acetic acid and formic acid were used through this study. Polymer-acid solutions were prepared and their viscosity was measured to identify the compatibility of the acid with the polymer. The measurement was conducted as a function of shear rate, salinity, temperature and acid concentrations. The results revealed that the presence of PAA did not change the viscosity of the acid solution significantly, while the viscosity of Xanthan-acid solutions was decreased with increasing the acid concentration. Additionally, the reaction of polymer-acid solutions with the rock material was monitored under microscope. Original rock samples obtained from Saudi reservoirs containing mainly carbonate were used in the reaction. The PAA-acid solution did not show any decrease in the reaction rate compared to that of acid solution. Thus, the PAA solution applied in this study is not recommended as a retarder.

However, Xanthan-acid solutions showed a significant decrease in the reaction time. Therefore, Xanthan was selected to perform further investigations in Rotating Disk Reactor (RDR) at different pressures. The results showed clearly that the presence of Xanthan leads to an increase in the acid spending time by decreasing the reaction rate with the rock samples. This indicates that Xanthan can be added to the acid solution as a retarder to achieve an extended matrix acidizing. Moreover, scanning electronic microscopy (SEM) was conducted on pre-treated and post treated rock samples. This provides the opportunity to perform a detailed description of the rock surface and facilitates the identification of the changes occurring due to polymer-acid treatment.
Laboratory Technique for Screening Asphaltene Inhibitors for Kuwaiti Reservoirs
Authors: Oskui G. P. , Salman M. , Gholoum E. F. , Rashed A. , Matar B. S. Al , Al-Bahar M. , Kahali K.
Published: December 2007

Currently Kuwait Oil Company (KOC) is facing asphaltene deposition problems in the wellbore of some of the Marrat Jurassic reservoirs in West Kuwait (WK) and South East Kuwait (SEK). This has caused a reduction in production and shutting of some of the wells and a severe detrimental effect on the economics of oil recovery. This paper describes the results of the laboratory studies on the characterization and phase behavior studies of three different crude oil samples from Marrat reservoirs, and the screening of a number of commercially available inhibitors, which were proposed as a remedy and prevention of asphaltene deposition for this reservoir.

Initially the samples were characterized for their chemical and physical properties. Then the phase diagram (P-T) and Asphaltene Deposition Envelope (ADE) for bottom-hole samples were established by measuring the saturation and Asphaltene Onset Pressures (AOP) at different temperatures from reservoir to surface conditions by using the laser technique Solid Detection System (SDS). Asphaltene Flock Point (AFP) analyses were then performed by the titration technique using Stock Tank Oil (STO) samples and n- Heptane as the asphaltene precipitant. The effects of different concentrations of each inhibitor on different reservoir fluids were investigated in the laboratory, using the AFP technique. The most efficient inhibitor with the optimized concentrations for each reservoir fluid was established for economical evaluation purposes. Based on these studies, a selected inhibitor is now being used for a pilot field study.
Reducing Road Traffic Fatalities Through Driver Education: A Major Oil-Producing Company's Approach
Authors: Odunmbaku Seun , Obarewon Felix
Published: December 2007

Over the years, many companies in the Oil and Gas industry have taken several initiatives towards reducing the frequency of road transport accidents. Despite these efforts, accidents still occur, sometimes resulting in fatalities.

Consequently, a major oil producing company in Nigeria launched a 4-step driver training program that is hinged on eliminating major risks associated with its land transport activities. The Program identified driver education as key to reducing road traffic accidents.

Using a holistic approach, we recognized the existence of a competency gap in the driver education program in the country and focused on continuing driver education, coaching and mentoring to build the desired positive attitude in the drivers towards risk reduction in land transport activities.

Its implementation has brought a significant reduction in the frequency and severities of road traffic accident in the company within a reasonably short time. This is at a cost that is low compared to the cost of traffic fatalities.
Fracture Acidizing: History, Present State, and Future
Authors: Kalfayan Leonard J.
Published: December 2007

The first observation and description of hydraulic fracturing, by Grebe and Stoesser (1935), involved injecting acid to stimulate oil production from a carbonate formation. With the advent of hydraulic propped fracturing of sandstones with oil and sand in the late 1940s, fracture acidizing has been generally confined to carbonate formations; its advancement did not match that of propped fracturing. By the 1970s, propped fracturing of carbonates (in addition to sandstones) gained popularity through the greater understanding and ease of modeling fracture stimulation with non-reactive (non-acid) fluids. After the 1970s, however, advancements occurred in modeling fracture acidizing and in fracture acidizing stimulation theory. Thus, entering the 1980s and into the 1990s, fracture acidizing in carbonates increased, with development of a variety of fluid systems and multi-step procedures that are still in use today. Nevertheless, fracture acidizing continues as the less-preferred alternative to propped hydraulic fracturing in carbonates - and it has never been seriously considered as a stimulation method for sandstones.

With approximately 70% of worldwide hydrocarbon reserves in carbonate formations, and the need to simplify sandstone stimulation treatments in general, the merits of fracture acidizing and its greater possibilities - for both carbonates and sandstones - must be considered.

This paper endeavors to briefly review the historical milestones leading to fracture acidizing, and their bearing on present methods and on the imposed rules. The paper touches on the types, purposes, benefits and limitations of present technologies and methods with a focus on the propped fracturing versus fracturing acidizing decision - and with a view to future possibilities and opportunities.
Asphaltene Gravitational Gradient in a Deepwater Reservoir as Determined by Downhole Fluid Analysis
Authors: Mullins Oliver C. , Betancourt Soraya S. , Cribbs Myrt E. , Creek Jefferson L. , Dubost Francois X. , Andrews A. Ballard , Lalitha Venkataramanan
Published: December 2007

The fluids in large reservoirs can be in equilibrium - especially if conditions conducive to convective mixing prevail. A large vertical column of reservoir hydrocarbons offers a unique laboratory to investigate potential gravitational grading. Asphaltenes are known to exist in crude oils as a colloidal suspension, but which had not been well characterized in the laboratory until recently. In this paper, we review a gravitational gradient of asphaltenes in a reservoir and a simple theory is shown to apply. The corresponding downhole and laboratory analyses are consistent; asphaltenes exist in these crude oils in nanoaggregates. The corresponding asphaltene gradients provide a stringent and new method to test reservoir connectivity (as opposed to compartmentalization), which is key to the efficient economic development for many deepwater projects.
Productivity Increase Using the Combination of Formation Isolation Valve and Dynamic Underbalanced Perforation
Authors: Tiribelli Achille , Luca Minneci Giovanni , Daoud Ahmed , Ghodbane Fathi , Dahroug Ahmed
Published: December 2007

The transition from completion to production often requires the well to be killed immediately after perforation is completed, thus exposing the formation to potentially damaging kill fluid. To obtain a perforation tunnel with maximum productivity, this transition requires an optimal cleanup and the removal of the perforation damages.

A new underbalanced oriented perforating technique has been successfully implemented in Algeria. It combines the use of a formation isolation valve (FIV) to keep damaging completion fluid off the formation immediately after perforation and a perforating technique that utilizes the dynamic underbalanced method, which cleans perforations with more efficiency than conventional static underbalanced perforating method. In addition, a passive gun-orienting system was used to optimize the perforating process and enhance the well's performance.

The new technique was applied in 2003 to horizontal Well-1, which was drilled by in the Tadrart sandstone formation of the Berkine basin. After successful results in this well, the operator adopted its use in 2005 for two additional wells, Well-2 and Well-3.

The paper describes the application of the new technique to three horizontal wells of the Berkine basin and the evaluation of the related productivity increase vs. the conventional perforating method.
Wax Control by Biocatalytic Degradation in High-Paraffinic Crude Oils
Authors: Kotlar Hans Kristian , Wentzel Alexander , Throne-Holst Mimmi , Zotchev Sergey , Ellingsen Trond
Published: December 2007

Paraffins, mainly composed of long chain alkanes (LCA), pose a problem in the recovery of oil from fields producing paraffinic oil. This is due to the build up of paraffin deposits. Solidification and aggregation of LCA can cause serious problems in oil recovery due to the clogging of oil production pipes, deposits in the process equipments and sealing off pores in the reservoirs. Partial degradation, i.e. reduction in chain length of LCA present in such oils is likely to greatly increase its quality as well as enhance the recovery.

The approach presented in this paper is the development of biocatalytic processes involving bacteria capable of degrading LCA in situ. The project has focused on the identification of bacterial strains capable of LCA degradation and the search for and characterization of enzymes therein. One strain, identified as Acinetobacter sp. 6A2, was isolated by screening for strains capable of utilizing a paraffin with a melting point of 52-54°C. The strain was shown to be able to degrade alkanes with a chain length ranging from C10 to C40. Three enzyme systems have been identified showing overlapping alkane substrate specificities in this strain, two AlkM–type alkane hydroxylase homologues, AlkMa and AlkMb, and one system encoded by a gene given the name almA. AlkMa and AlkMb are involved in the degradation of C10 to C20 alkanes. AlmA, however, is involved in the degradation of LCA with a chain length of C30 to C40. This is confirmed in growth experiments of mutant strains. The AlmA enzyme is of particular interest as it is involved in the degradation of the more heavy wax components.

Efficiency and specificity of the enzyme systems are currently under investigation.
Enhanced Oil Recovery by COMB-Flow: Polymer Floods Revitalized
Authors: Kotlar Hans Kristian , Selle Olav , Torsaeter Ole
Published: December 2007

When a typical oil reservoir reaches its economic limit after primary and secondary recovery (water flooding), the world average says that more than two thirds of the original oil is left in place1. The challenge is to develop Enhanced Oil Recovery (EOR) methods that ensure an economical tail end production from these fields.

Today’s oil price is very high resulting in better economics for EOR-concepts. There is now a trend in the business that companies again are doing research and development in this area.

Secondary water flooding leaves the residual oil capillary trapped. Surfactant injection can mobilize this residual oil by a strong reduction in the interfacial tension (IFT) between oil and water. However, a combination of polymer for mobility control, a small bi-functional molecule for enhanced solubility and reduced effect of salinity, and surfactant to lower the IFT will according to the theory have a much better effect as a tertiary oil recovery method. The concept is to search for a robust type III phase system. A polymer, a surfactant and a small bi-functional molecule in combination has been given the tentative name of "COMB-flow".

Laboratory experiments with this COMB-flow system indicate an increased recovery of OOIP by 20%.

The residual oil saturation was lowered by 12% and the residual oil recoveries ranged between 30.5% and 37.3%. Relative to the recovery obtained after traditional water flooding the recovery is enhanced almost 50%. These results were obtained on a crude oil having the in situ viscosity of 3.5 mPas at reservoir temperature. The experiments were performed at reservoir conditions.

This system will be tested further on effects on different crude oils. Furthermore, different flow regimes will be tested.
Modelling of Non-Aqueous and Aqueous Scale Inhibitor Squeeze Treatments
Authors: Vazquez O. , Mackay E. J. , Sorbie K. S.
Published: December 2007

The most common method for preventing downhole scale formation is by applying a scale inhibitor squeeze treatment. In this process, a scale inhibitor solution is injected down a producer well into the near wellbore formation. Commonly, these scale inhibitor treatments are injected as aqueous solutions. However, there are certain situations where an aqueous based treatment is not desirable, such as where relative permeability effects, water blocking, fluid lifting, chemical penetration or hydrate formation are of major concern.

This paper presents the results of a modelling sensitivity study comparing non-aqueous and aqueous scale inhibitor squeeze treatments. The model described can simulate the effect on the treatment life of treatment solubility in the oil and water phases, treatment strategy, adsorption properties (from the water and oleic phases), viscosity effects and wellbore friction. Of particular interest is the relationship between inhibitor solubility in the carrier and in situ phases, and the choice of phase for the overflush fluid. The relationship can have a very pronounced impact on inhibitor penetration and squeeze lifetimes.

The sensitivity study is carried out using purpose written software for scale treatments. The code is a two-phase flow, multi-component, multi-layer, radial or linear mathematical model capable of simulating both aqueous and non-aqueous squeeze treatments. The model considers the immiscible displacement of oil and water phases along with inhibitor transport in both phases and mass transfer between phases. It is capable of modelling kinetic and equilibrium adsorption and desorption from either phase. The model has been validated by comparison with analytical solutions, standard conventional single-phase squeeze calculations and multi-phase reservoir simulation calculations5. An example two-phase calculation of a specific field treatment is included, and the results are compared with the field return profiles.
Development and Field Application of a New Hydrogen Sulfide Scavenger for Acidizing Sour-Water Injectors
Authors: Nasr-El-Din H. A. , Zabihi M. , Kelkar S. K. , Samuel M.
Published: December 2007

In treating sour, water injectors in carbonate formations in Saudi Arabia, sulfide scavenging, prevention of sulfur and iron sulfide precipitation is a major requirement during acidizing treatments. As the acid spends on the carbonate surfaces, and in the presence of ferric iron in the injected acid, iron sulfide precipitates at pH values less than 1.9.

Iron sulfide and elemental sulfur have been implicated in injectivity decline following acid treatments on water injectors under sour conditions. Previous research work has led to the use of a new generation of hydrogen sulfide scavengers (mixture of aldehyes) for use in acidizing treatments.1 However, one of the main drawbacks of this scavenger in acidizing treatments is the formation of oily material, which can adversely affect the performance of water injectors.

This paper discusses the main reactions of hydrogen sulfide with various scavengers that can be used during well stimulation. A new scavenger that is based on hydroxyalkyl triaziane was thoroughly examined. Laboratory work included compatibility of the old and new hydrogen sulfide scavenger with live acids. The impact of the new scavenger on corrosion of low-carbon steel was also addressed.

Based on encouraging results from the laboratory, field trials were conducted on a number of wells. Post acidizing flowback samples were collected and analyzed to confirm laboratory results. Finally, injectivity results from the field trial were compared with offset well performance to validate the technical benefits of the new hydrogen sulfide scavenger.

This paper continues the discussion on the need and importance of using proper sulfide scavengers in well acidizing fluids. It will highlight the fact that there is more science than art involved in carbonate acidizing, especially for sour wells.
Efficient Permeability Parameterization With the Discrete Cosine Transform
Authors: Jafarpour B. , McLaughlin D. B.
Published: December 2007

The inverse estimation of permeability fields (history matching) is commonly performed by replacing the original set of unknown spatially discretized permeabilities with a smaller (lower dimensionality) group of unknowns that captures the most important features of the field. This makes the inverse problem better posed by reducing redundancy. The Karhunen-Loeve Transform (KLT) is a classical option for deriving low dimensional parameterizations for history matching applications. The KLT can provide an accurate characterization of complex permeability fields but it can be computationally demanding. In many respects this approach provides a benchmark that can be used to evaluate the performance of more computationally efficient alternatives. The KLT requires knowledge of the permeability covariance function and can give poor results whenthis matrix does not adequately describe the actual permeability field. By contrast, the Discrete Cosine Transform (DCT) provides a robust parameterization alternative that does not require specification of covariances or other statistics. It is computationally efficient and in many cases is almost as accurate as the KLT. The DCT is able to accommodate prior information, if desired. Here we describe the DCT approach and compare its performance to the KLT for a set of geologically relevant examples.
Maximising Chemical Placement in Complex Wells
Authors: Stalker Robert , Butler Kristen , Graham Gordon Michael , Wahid Fazrie
Published: December 2007

The effective placement of chemical squeeze treatments in heterogeneous wells and long reach horizontal wells has proved a significant challenge, with various factors including heterogeneity, crossflow and pressure gradients between otherwise non-communicating zones within the well, all contributing to an uneven placement of the scale squeeze treatment into the reservoir. Work recently presented by the authors has however illustrated the potential benefits of using modified injection fluids (in particular, lightly viscosified shear-thinning fluids) to aid uniform scale inhibitor placement in such wells to effect more even placement. This paper describes the various options available for achieving self diversion and describes the potential drawbacks associated with the viscous placement fluids commonly used for acid simulation techniques. In addition, the paper presents the results of laboratory and computer simulation investigations into the application of such fluids using novel laboratory core flood techniques, and discusses the implications of these results for field treatments. The work describes the importance of obtaining accurate in situ viscosity properties under realistic flow conditions to provide appropriate input data for computer simultaion studies and describes novel laboratory test methods for the determination of such properties. This work also illustrates the effectiveness of the use of dual core testing to provide experimental data to validate model algorithms prior to field applications.
Biodegradable Surfactants Aid the Development of Environmentally Acceptable Drilling-Fluid Additives
Authors: Miller Jeffrey
Published: December 2007

The additives commonly used in oil- or synthetic-based drilling fluids were designed in past years with predominant focus on providing an efficient and economical function. For nearly 50 years, the industry has relied on organically-modified clays to provide viscosity and suspension to non-aqueous fluids. However, the conventional quaternary ammonium salts used to produce these additives have shown poor biodegradability, drawing scrutiny from some regulators. Environmental restrictions governing discharges to the waters of the North Sea have now motivated fluids providers to develop cost-effective additives that deliver performance and also reduce the environmental impact.

New organic-modified clay viscosifier additives have been created using biodegradable quaternary ammonium salts. The salient features of the degradable surfactants used are similar to traditional quaternary ammonium salts, but the former include specific sites in their molecular architecture that allow them to be broken down by marine micro-organisms. When select compounds of this type are used to produce organophilic clays, the resultant materials offer functional performance comparable to traditional additives with the added benefit of providing suitable biodegradation for use in environmentally-sensitive areas.

A large number of organic-modified clays were produced in the course of a laboratory study spanning a wide range of surfactants. Many of the compounds examined could be used to make viable viscosifier additives, but only a select few that were biodegradable could sufficiently modify the clay surfaces. Performance testing showed that the new clay-surfactant complexes can provide results comparable to a conventional organophilic clay in a paraffin-based invert emulsion system. While a slightly higher concentration of biodegradable clay was needed to obtain comparable yield point values, in one case the increase was less than three pounds per barrel.