bluuebunny/crossref_metadata_2025 huggingface dataset:
In-Situ Coal Gasification of Bituminous Coals – A Development Plan
Authors: Zielinski R. E. , Agarwal A. K.
Published: December 2007

There are in excess of one trillion tons of bituminous coal resources in the United States, (1) Most of this resource is concentrated in the Appalachian, Illinois and Western Interior Basins. Approximately 220 billion tons of this bituminous resource, which is comparable to the estimated mineable reserves, can be recovered by Underground Coal Gasification (UCG). A technology that would provide for the economic production of gasoline and SNG in the eastern;, high energy use markets would provide an essentially new energy source to these markets. The high rank thin seam bituminous coals therefore provide an effective target for the development of a economically viable technology for resource recovery.

The only recent field test in these thin, seamed, high rank coals was the Pricetown I Field Test performed at Pricetown, West Virginia. This test demonstrated the feasibility of gasifying deep (~ 900 feet), thin seam (~ 8 feet), swelling bituminous coals. This test provided a 72% energy recovery by utilizing only air injection. While the test was successful in meeting all of its objectives, it was only the first step in the development of eastern UCG technology. The data obtained from the test can be used to develop an effective plan which can lead to a commercial demonstration and subsequently, commercial acceptance of this technology for bituminous coals by the 1990's.

To meet the requirements of a commercial demonstration, a three phase plan is proposed for the commercialization of this technology. Phase I of this plan addresses the issues still remaining in the swelling bituminous coals of the Appalachian Basin, whereas Phase II initiates the technology in the untested Illinois Basin and Phase III provides for a commercial demonstration in the Illinois Basin near existing energy markets.
Characterization of Porous Media Properties and Leaching Capacity of Spent Oil Shales
Authors: Ramirez W. Fred , Morelli Patrick T.
Published: December 2007

Porous media properties of spent oil shales have been determined in order to provide fundamental data needed to identify and predict the transport of leachates through surface piles or abandoned modified in-situ retorts.

Using high pressure mercury porosirnetry, pore size distributions were measured. Results show unimodal pore size distributions. Mean pore sizes range from 5 microns for powders to 1 micron for compacted powder pellets to 0.5 microns for consolidated chunks.

Specific surface areas were measured using both the mercury intrusion technique as well as BET nitrogen adsorption. Both experimental techniques gave similar results implying the absence of micro pores.

Visual and chemical analyses were performed by scanning electron microscopy and x-ray fluorescence spectroscopy. SEM micrographs show the uniform pore properties of the spent shale samples as well as giving information on average grain sizes. All SEM micrographs indicate the existence of dead-space-volume.

Leaching capacities of the various spent shale samples were measured using equilibrium leaching studies to determine Equilibrium Exchange Isotherms. Some leachate species exhibit a smooth continuous release whereas other species show discontinuous jumps in the exchange isotherm owing to the encountering of solubility limits for specific chemical species.

Based on these spent shale characterization studies, fundamental modeling concepts have been established for the transport of leachates through spent oil shales.
Characteristics of Oil Displacements by Aqueous Surfactant Solutions
Authors: Minssieux L. , Moulu J. C.
Published: December 2007

The aim of this laboratory work was a detailed study of oil recovery ability of aqueous surfactant solutions.

The first part included determination of relevant physical chemical properties of additive solutions, i. e. interfacial and rheological properties, phase diagram exploration as well as an evaluation of the specific adsorption-retention properties of surfactant polymer solutions in porous media used for oil recovery tests.

In the second part, the results of the series of oil displacements were analysed –to give a precise description of the main features of displacements by aqueous surfactant solutions,–to assess their oil recovery efficiency, shown to depend on surfactant concentration in slug injected, consecutive or simultaneous injection mode of polymer and surfactant and additive retention properties in the porous media chosen,–to compare the oil recovery performances of surfactant solutions and microemulsions taken from the same Winsor III type diagram.

Finally, application of a Buckley-Leverett type approach was considered to aid in the interpretation of the successive displacement steps observed during flooding by surfactant solutions at low or moderate concentrations.
Statistical Decline Curve Analysis
Authors: McNulty Robert R. , Knapp Roy M.
Published: December 2007

The best hyperbolic curve is numerically fit to production decline data from selected oil wells. A non-linear optimization computer program finds the three best values of the general hyperbolic parameters q0, a, and b using least squares regression. By using weighted residuals, better history matching is obtained than with previous least squares methods. The future rate-time behavior of a well with only a few months of production is predicted by an analogy with other similar wells.

This production extrapolation method is superior to graphical or type curve procedures since it does not require engineering judgement until the unbiased curve fit has been calculated from observed production data. The program calculates consistent results based only on production values. Then, the evaluation engineer can use his judgement and experience to modify the prediction.
Response of the Dual Spacing Neutron Log (CNL) to Gas
Authors: Ullo J. J.
Published: December 2007

The application of a mathematical model based on 2-dimensional transport theory to predict gas response characteristics of a new version of the CNL tool, called the CNL-G, is described.

It is well-known that when gas or light hydrocarbons are present in a formation the neutron log will indicate a low apparent porosity — lower in fact than what might be expected by taking account only of the lower hydrogen density. The cause for this difference has been called the excavation effect(1).

Calculations of the magnitude of the excavation effect are presented. In addition, the potential use of various combinations of neutron detector count rates as gas indicators is examined. Calculations suggest that these indicators may complement the traditional ϕdensity-ϕneutron gas signal in useful ways especially when deep invasion, very shaly sands, and thermal neutron absorbers weaken the traditional density-neutron diagnostic.
Facies Types and Reservoir Quality of the Rotliegendes Sandstone, North Sea
Authors: Robinson Alec E.
Published: December 2007

A study of the Rotliegendes sandstone in part of Quadrant 47 in the southern U.K. North Sea showed that of three facies types, eolian dune sandstones have the best reservoir properties. Proximity to a fault also has a dramatic local effect on reservoir quality and productivity as shown by an example from Indefatigable Field.
New Technology Improves Economics in Canada's Extensive Alberta Oil-Sands Region
Authors: Nibogie R. , Buske R. , Overstreet J. , Dick J.
Published: December 2007

Long-term elevated oil price stability has caused operators to apply new, high-end technology to extract bitumen from Alberta's extensive oil sands deposits (174 billion recoverable bbls). In the Fort McMurray Area, operators are utilizing a Steam Assisted Gravity Drainage (SAGD) project to get the low-gravity (≤10° API) hydrocarbons to the surface. These wells are attractive because there is no exploration risk and they typically have a 30-50 year life with no decline curve.

The project requires drilling relatively shallow (500m–700m TVD) wells, but to an extended measured depth up to 3000m, through soft, yet extremely abrasive sands. The wells have high build-rates (9°/30m) and typically the horizontal section averages around 1000m but lengths can reach 2000m or more. To achieve the well profile and run-length requirements and withstand instantaneous ROP up to 200m/hr, operators were utilizing steel-tooth bits for the build sections and PDC to complete the horizontal legs.

To improve economics/footage drilled in the build section, a service company has developed a new 14-3/4" (374.6mm) rollercone bit with an innovative steel-tooth cutting structure that provides extended wear resistance for drilling in these highly abrasive SAGD directional applications.

The new bit features a thick application of highly wear-resistant hardfacing materials and new cone design increases gauge holding ability allowing multiple runs without going undergauge. Finally, a metal-seal provides extended bearing life by resisting accelerated wear due to the sharp abrasive sand formations. Because of the new technology, operators are getting more meterage utilizing the new steel-tooth abrasive bits compared with conventional premium milled tooth products. This allows the operator to drill up to four build sections with one new technology bit compared to only one or two hole sections with conventional bits, thereby cutting costs substantially.
Field Pilot Tests for Tertiary Recovery Using Butane and Propane Injection
Authors: Pacheco Edgar F. , Garcia Alfredo I.
Published: December 2007

This paper describes a pilot project for tertiary recovery of liquid hydrocarbons through LPG injection in watered-out sections of the Bolivar reservoir in La Peña Field, Santa Cruz-Bolivia. The promising results obtained in the initial field misoibility tests, as well as the results from a mathematical model built to simulate and evaluate the tertiary recovery project, directed subsequent work into a cyclic scheme for enhanced recovery. This scheme is explained and injection production data is presented. Field facilities built to handle both the injected LPG and the produced Oil-LPG mixture are described. The Oil/LPG ratio and the LPG recovered/injected fraction are the main factors measured in this test to make further considerations for a full scale project.
The Role of Rock Mechanics in Optimizing Devonian Gas Production From the Appalachian Basin
Authors: Advani Sunder H. , Lee J. K. , Komar Charles A.
Published: December 2007

The phenomenological theories of gas production, from a rock mechanics vantage point, are related to the characteristics of the natural fracture systems and their subsequent interaction with the induced fracturing. The dominant role of the in situ stresses and formation mechanical properties for reservoir site selection and hydraulic fracture treatment are quantified in this paper. An illustration of basement-sedimentary cover interaction and salient mechanisms responsible for stress reorientation and tectonic relief in the Rome trough region of the Appalachian Plateau is given. In addition, examples detailing induced fracture dimension evaluations along with a discussion of factors governing fracture width, vertical fracture migration and fracture length are presented. Finally, the suitability of different stimulation treatments is discussed.
Use of Electric Immersion Heating Elements In Oilfield Heater-Treaters
Authors: Palastak James E.
Published: December 2007

With the depletion of gas reserves, the increase in commercial demand and the rising cost of natural gas, alternatives for a reliable, safe, economical and efficient method for preheating produced fluids in heater treaters is sought. A case history on the performance of an electric immersion heater versus a conventional gas firetube is presented under similar pumping and climatic conditions. The immersion heater uses the principle of resistive type of heating (thermal energy). Some advantages of using electric immersion heater's are: They help reduce the possibility of fire or explosion hazards since there are no open flames. Explosion-proof units are available if required.They eliminate all inconveniences created by the pilot light blowing out in a gas-fired vessel thus requiring the fluid to be rerun through the treater.By the removal of selected in-line fuses, the quantity of heat can easily be adjusted to the requirement of the job (from the minimum to maximum unit capacity), giving a flexibility that cannot be obtained from the gas fired unit.Existing gas-fired heater treaters can be easily retrofitted with an electric immersion heater.

The test showed the cost of electric heating to be directly competitive with the cost of gas treating in one of Amoco's operated West Texas fields. In areas where residue gas is sold for a higher price (over $0.50 per MCF), the fuel cost difference might strongly favor the electric heating element. The heating element would have immediate application in areas where treater gas has to be purchased from a utility or is not available at all, and in areas where it is impossible or undesirable to make daily checks of gas-fired treaters.
Electrical Submersible Pumps for the Montrose Field - Their Application and Post Operational Experience
Authors: Way A. R. , Hewett M. A.
Published: December 2007

The North Sea Montrose Field has been on production since July 1976. Since mid 1979 artificial lift has been necessary on certain wells, due to their high water cuts.

This paper reviews the application of electrical submersible pumps for artificial lift on Montrose Field, the choice and sizing of equipment, completion design and the installation procedure. Problems encountered and post-appraisal of the electrical submersible pump installations, together with any changes made to remedy the problems and improve pump performance, are discussed. Specific items covered include the experience with rotary gas separators, the run life and performance of submersible pumps, and the economics of submersible pumps for artificial lift.

Submersible pumps have been used to maintain production which has decreased on certain wells in the Montrose Field due to increasing water cuts. The submersible pumps have been run in high angle holes (65°), at measured depths of approximately 10,000 ft., with production of high GOR (900 SCF/BBL) and in the presence of sand. The reservoir pressure is a maximum of 3000 psig and the reservoir temperature is 255°F. Experience gained by Amoco with submersible pumps in the offshore environment of the North Sea is applicable to other operators and their artificial lift requirements, especially where high production rates and hostile environments are encountered.

It has been shown to date that electrical submersible pumps can be run in the North Sea, but with only limited success. Advantages exhibited over gas lift (presently the only viable alternative to electrical submersible pumps in the North Sea), are the comparatively low initial installation costs and an application on a well by well basis, rather than a field wide basis; however, these advantages can only be achieved provided a satisfactory pump run life is obtained. A total of ten electrical submersible pumps have been installed on the Montrose Field, with an average run life of approximately four weeks, and a maximum run life of approximately three months.
Beyond The Concrete Gravity Platform
Authors: Mcleod Iain L.
Published: December 2007

Whilst large concrete gravity platforms have been operating successfully in the North Sea since installation of the Ekofisk Tank in 1973, new applications for floating concrete structures are emerging. The first concrete floating structure for the North Sea, an articulated loading column (ALC) for the Maureen field is under completion at the Howard Doris Group Loch Kishorn construction yard in North West Scotland.

Although massive, with for example the 600,000 tonnes displacement of the previous Ninian Central Platform built in the Kishorn dry dock, gravity platforms are required to float during a relatively short construction period. Conversely, the Maureen ALC at 5,000 tonnes displacement, is required to maintain buoyancy throughout its working life. It is thus the pioneer for the future use of concrete in North Sea Oilfield floating structures.

Following from the concrete loading column, the Group have detailed the design of a heavy duty concrete Semi Submersible vessel for the North Sea.
Recent Advances in Cathodic Protection Surveys of Subsea Pipelines
Authors: Backhouse Geoffrey H.
Published: December 2007

Over the last three years, a new system for measuring the cathodic protection potential of subsea pipelines has been developed. The equipment consists of a dual silver/silver chloride electrode probe, mounted on a remote controlled submarine, a silver/silver chloride reference electrode which is maintained at a distance from the pipeline and support ship, and a monitor console. As the submarine moves along, over the pipe, the monitor console records the cathodic protection potential profile and radial field gradient on a continuous chart recorder and also on a strip printer. At intervals, contacts with anode bracelets or bare pipe are used to calibrate the system. A complete potential profile is obtained, together with measurements of current density on damaged areas, and anode output currents.

Typical results obtained from a number of North Sea pipelines are discussed.
Comparison of Preconditioners for the Conjugate Gradient Method in Reservoir Simulation
Authors: Towler Brian F. , Killough John E.
Published: December 2007

Five methods of partial decomposition are compared as preconditioners for the conjugate gradient method for solving the pressure matrix equation of a sequential mode reservoir simulator. Three unsymmetric decompositions, Strongly Implicit Procedure; Dupont, Kendall, Rachford method; and Additional Bands (AB) proved effective and comparable, with AB being the most efficient when used on a scalar computer. The two symmetric Incomplete Cholesky methods did not prove as effective as the three unsymmetric methods.

On the CRAY-1 computer, the SIP-conjugate gradient method was most efficient because it could be vectorized, and in comparison to Red-Black LSOR it was far superior for the example problem considered here.

The insensitivity of the SIP-conjugate gradient method to the iteration parameter was an additional advantage of the method.
Application of D4 Ordering And Minimization In An Effective Partial Matrix Inverse Iterative Method
Authors: Tan Thomas B. S. , Letkeman John P.
Published: December 2007

A new algorithm is presented for solving simulation problems which employs minimization and a partial decomposition of the matrix resulting from an alternate diagonal ordering. The method also maintains material balance in its formulation, important for severely ill-conditioned problems.

The technique has been applied to problems in two and three dimensions with good results and examples are given to show the convergence of the method. Examples include heterogeneous, ill-conditioned problems as well as ones with negative and positive co-efficients. Comparisons are made with currently available methods such as SIP, ORTHOMIN, the semi-direct algorithm of Letkeman and the diagonal method of Watts.

The results show that the new method achieves convergence with less work than the other methods. In two dimensions, Stone's heterogeneous model problem with homogeneous sub-regions was solved with seven equivalent SIP iterations compared with 20.5 for the diagonal method. Coats, problem 1 in three dimensions was solved in 21 equivalent SIP iterations. SIP did not converge for this problem.

Unlike SIP and similar to the Watts’ diagonal method, a sequence of iteration parameters is not required and this feature together with the stability of the method makes it relatively easy to use.
The Mathematical Basis of the Adaptive Implicit Method
Authors: Thomas G. W. , Thurnau D. H.
Published: December 2007

The adaptive implicit method enables a reservoir simulator to choose the degree of implicitness in a grid block to guarantee stability. At any moment different grid blocks can have different degrees of implicitness. As a calculation proceeds these shift in space and time depending on simulator-supplied criteria. The technique can be applied to any simulation problem involving N unknowns. The advantage is substantial reduction in computing time and storage requirements compared to fully implicit formulations.

The mathematical procedure involves labeling the implicit/explicit mix of unknowns and then composing the matrix problem. The latter is reducible as long as there is one or more unknowns to be computed explicitly; consequently, appropriate operations are performed to put it in reduced form. This leads to matrix equations of lower order than the original problem which are solved at less cost. We demonstrate each step of the procedure with an example.
Grid Orientation During Steam Displacement
Authors: Abou-Kassem Jamal Hussein , Aziz Khalid
Published: December 2007

The simulation of oil displacement by steam injection is affected by the orientation of the grid. Under certain situations vastly different results are obtained when grid lines are parallel or diagonal to the line joining an injector-producer pair in a five-spot flood pattern. The same problem exists in the displacement of oil by water under conditions of unfavorable mobility ratio.

Several approaches have been used by investigators to reduce the effect of grid orientation. Three of these are investigated in this paper: (1) use of a nine-point finite-difference operator as opposed to a five-point finite-difference operator, (2) use of the two-point upstream mobility instead of a single-point, and (3) use of harmonic total mobility average for calculation of flow across a boundary.

A compositional, three-phase, two-dimensional steam model was developed to investigate the grid orientation problem during steam displacement.

A realistic steam displacement problem for a highly viscous oil reservoir was selected for detailed study. The effects of grid orientation on important primary variables and recovery performance curves are presented for this problem. It is shown that, at least for the problem considered, the nine-point scheme alleviates the effect of grid orientation, while the two-point upstream mobility and the harmonic total mobility approaches aggravate the problem. It is also shown that use of the two-point upstream mobility is not appropriate for thermal process simulation. The present model does not suffer from the " bullet-like" displacement front reported by other investigators.

The test problem was chosen to maximize the effect of grid orientation.
Source Distributed Fracture Model for the Numerical Modelling of Oil Sands Steam Stimulation
Authors: Geshelin Borys Michail , Grabowski Janusz Wojciech
Published: December 2007

This paper describes a source distributed dynamic fracture model. The model, coupled with the thermal simulator ISCOM, was used to investigate oil sand reservoir performance during steam stimulation.

The source distributed fracture model developed is based on the following assumptions: The fracture can propagate through a given path of adjacent reservoir blocks, creating a fracture channel within a reservoir. The number of fracture channels and reservoir geometry are not restricted. The position of a fracture or microfracture system inside a given reservoir block is not defined - the fracture is represented as an effective source of fluid and heat transferred to the block. Fracture volume is disregarded. The mass and heat balances are solved exactly for each fracture channel. Fractures can be operational only during the injection period. Fracture opening and closure are governed by calculated values of opening, propagation and closure pressures. Effective absolute permeability and conductivity inside a drainage area are treated as adjustable parameters.

Results of this investigation show that reservoir performance is strongly affected by the variation of effective fracture parameters, especially changes in effective fracture conductivity in the vicinity of a wellbore and the mobile and connate water saturations.
Solution of Pressure Equations for Large Reservoir Models Using Block Successive Overrelaxation and an Array Processor
Authors: Emanuel Alan S. , Lee Seong H. , Chung Ernest Y.
Published: December 2007

Block successive overrelaxation is used to solve the pressure equations of large 3-dimensional reservoir models with limited or zero permeability between layers. Each block consists of several vertical planes of the model. Composing the blocks of vertical planes allows wellbore pressure equations to be included along with the reservoir cell block equations to implicitly couple wellbore pressure to reservoir grid block pressure. The equations for each block are solved simultaneously using sparse elimination techniques. The work of factorization, forward and backward substitution is transferred from the host computer to an attached array processor. The host computer is an IBM 168 or a VAX 11/780, and the attached processor an FPS 190L or FPS 120B.

For large anisotropic multi-layer models with limited vertical permeability between layers, the block technique shows two or three times better convergence than plane SOR. Convergence may be further improved by overlapping a few planes in adjacent blocks. Host computer CPU time and cost may be reduced by up to a factor of two to five for these models. Two hypothetical test problems and three reservoir problems are described.
A Study on Some New Water-Soluble Copolymers and Polymer Blends Used for Exploitation of Oil Field
Authors: Xi Xu , Qin-gong He , Qi-jiang Zhuo , Wei-you Mao
Published: December 2007

Some water-soluble copolymers used for oil recovery were prepared by copolymerizing acryloraide and acrylonitrile using ammonium persulfate as initiator. The properties of the mixed aqueous solution of a natural and synthetic polymer blend (carboxymethyl cellulose-partially hydrolyzed polyacrylamide) were modified by ultrasonic technique, a new type material for oil field exploitation is thus provided. In addition, the gel characteristics of several etherified poly(vinyl alcohol) and their blends were also studied in this paper, some new applications of poly(vinyl alcohol)were exploited.
Scale Inhibition for Injection of Incompatible Waters
Authors: Vetter O. J. , Kandarpa V.
Published: December 2007

The utilization of scale inhibitors is the most common and promising method of combatting the scale problems in oil and gas field operations. The extension of the scale inhibition technique to geothermal operations faces some problems mainly due to the high temperature and high salinity of the brines. In addition, the injection of foreign waters and their associated mixing of incompatible waters give rise to some additional problems in chosing proper inhibitors. The brines resulting from incompatible water mixing contain non-equilibrium concentrations of anionic and cationic species and sometimes at extremely high supersaturations of scale forming compounds.

The present paper gives the results of evaluating commercially available inhibitors in preventing CaSO4 and BaSO4 precipitation from supersaturated solutions. Four different types of commercial inhibitors have been chosen for this evaluation. They are phosphonates, polymaleic acids, polymers and phosphate esters. The conditions chosen for the evaluation represent the conditions found in the injection wellbore (for CaSO4 precipitation) and at the surface facilities of the producing well (for BaSO4 precipitation). The effect of the presence of iron in the producing brine on the efficiencies of the inhibitors were also studied as part of the present work.

Several inhibitors have been found to perform with high efficiencies againat CaSO4 precipitation at 135°C from solution at a supersaturaion of 8. In general, the phosphonate based inhibitors have been found to perform better than the inhibitors based on polymers, pbosphate eaters and polymaleic acids.

All the inhibitors performed poorly against BaSO4 at high supersaturations. Using high concentrations of the inhibitors and/or mixtures of some specific inhibitors, their efficiencies have been brought to values larger than 0.6. However, the presence of iron in the brine solution caused drastic decreases in the efficiencies of even the best inhibitors and inhibitor mixtures. In the presence of iron, Dequest 2010 (phosphonate inhibitor) in combination with a few of the other inhibitors showed efficiencies larger than 0.4 for times greater than 4 hours. At 120°C the time for failure of the inhibitors is 2 hours or less in the presence of iron.

The paper gives all the data in the form of tables.
Salinity Tolerance and Solution Property Correlations of Petroleum Sulfonate-Cosurfactant Blends
Authors: Shankar P. K. , Bae J. H. , Enick R. M.
Published: December 2007

A petroleum sulfonate (Petrostep 465/420) was combined with commercially available ethoxylated and other cosurfactants. Salt tolerance, phase volume behavior, interfacial tensions, and viscosities were measured; correlations among these parameters are presented for the 21 systems studied. Salinity tolerance levels as high as 120 g/kg NaCl, optimal salinities as high as 95 g/kg NaCl, and ultralow interfacial tensions on the order of 1 × 10-4 mN/m were exhibited by some systems. Optimal salinities were accompanied by ultralow interfacial tensions and lower microemulsion viscosities only when the range of salinity over which the three-phase region persisted was narrow. Furthermore, some systems were characterized by almost 95% microemulsion volume at optimal salinity. The width of the three-phase region decreased as the middle-phase microemulsion volume at optimal salinity increased. Consequently, the microemulsion viscosities were lower for systems that displayed a narrower three-phase region. It was also concluded from our results that optimal salinity does not necessarily occur at the middle of the three-phase region. For most of the systems studied, it occurred at lower values. The plots for the interfacial tension versus solubilization parameter were similar to those reported by Reed and Healy.13 The interfacial tension between the microemulsion phase and the excess phases was correlated with the excess phase volumes. We also found that the interfacial tension between the excess oil and brine was close to and parallel to that between the microemulsion and excess brine phases.
Clay Stabilization — Criteria for Best Performance
Authors: Hill Donald G.
Published: December 2007

A recent study has demonstrated the importance of cation exchange capacity in determining optimum use concentrations of cationic clay control agents.

Determining the concentration of polymer required to adequately stabilize clays is dependent upon many factors. Normally, the concentration required for clay control is based only on the clay content of the reservoir. In addition to the clay content, careful consideration should also be given to the type of clay, the natural wettability of the reservoir, the adsorbed cations in equilibrium with the formation, the treating fluid and the additive concentration in the treating fluid. It is important to consider all of these factors for each reservoir to be treated; however, some of the factors may not be known. The most important factor is the cation exchange capacity of the reservoir rock. This may be determined in the laboratory and used to predict the required concentration of the cationic additive to obtain stabilization.
Filtration of Oil Field Brines — A Conceptual Overview
Authors: Sharp Keith W. , Allen Barrington T.
Published: December 2007

The use of solids free brines as completion/work-over fluids has given rise to the need for methods of fine solids removal. Filtration of clear brines has become a major concern to operators. This paper will address the problem of removal of fine suspended particles in the .5-50 micron range.

The body of the paper deals with the removal of fine solids by flow through porous media. The mechanics of removal discussed include sieving, bridging, adsorption, and settling within the porous matrix. Parameters such as flow density or velocity and pressure drop will be defined. Each of the removal mechanisms will be discussed in terms of how the operational parameters affect filtration efficiency. A discussion of surface and depth filtration will be included. Also, performance parameters such as effluent quality, dirt capacity, and clear pressure drop will be discussed. Design of the porous media will be covered along with a discussion of how filters are rated. Current filtration techniques used in the oilfield will be reviewed and classified. The classification will include the type of removal mechanism whereby the specific filter operates, the effect of operating conditions on efficiency, and what kind of performance can be expected.
Nondamaging Fluid Loss Additives for Use in Hydraulic Fracturing of Gas Wells
Authors: Penny Glenn S.
Published: December 2007

An effective fluid loss control measure that has recently found application in the hydraulic fracturing of gas wells is the addition of an iramiscible hydrocarbon phase to aqueous fracturing fluids. In this work the effectiveness and regained permeabilities after employing hydrocarbon and common particulates are assessed. Laboratory studies indicate that reduced hydrocarbon concentrations (<5%) may be beneficial in achieving efficient fracture cleanup. A detailed evaluation of the parameters controlling fluid loss of an immiscible hydrocarbon phase in aqueous fluids has led to an optimized hydrocarbon-surfactant system, with which excellent regained permeabilities and efficient fluid loss control are achieved at reduced hydrocarbon concentrations.
Short Interval Gravel Packing Technique
Authors: Sokoll Robert Edward , Rogers Alan Kent
Published: December 2007

Conventional slurry packing methods involve a screen and from 120′ to 160′ (36.5m to 48.7m) of blank pipe above the screen. The blank pipe acts as a sand reservoir for the gravel pack screen. Sand settles after the gravel pack is completed and after the gel breaks. To help ensure a good gravel pack job in a well that has less blank pipe than screen, a multiple stage slurry pack process was designed along with a multiple stage crossover tool.
Alteration of Rock Properties by Adsorption of Petroleum Heavy Ends: Implications for Enhanced Oil Recovery
Authors: Clementz David M.
Published: December 2007

Clay mineral properties are irreversibly altered by adsorption of petroleum heavy ends. As a result of this alteration, rock sensitivity to injected fluids is reduced; rock wettability is changed from "water wet" to "neutral"; adsorption of surfactants is reduced; rock property measurements are changed; and cores can be irreversibly altered. All of these changes can affect enhanced recovery processes and related laboratory studies.

The extent of this interaction has been found to depend upon the type of clay minerals present in the rock, the composition of the petroleum heavy ends, and the interaction environment. After the adsorption occurs, a clay-organic complex is formed which is hydrophobic and very stable. Expansion of swelling clays is reduced and clay surface area and cation exchange capacity are reduced.

Practical implications of these observations are demonstrated in Berea sandstone cores and in friable California sand cores when the clays were stabilized against dispersion and subsequent migration. Berea sandstone permeability is rendered insensitive to fresh water and the friable sand, in which clays are the primary cementing material, is stabilized against failure under increased flow rates. In other studies, surfactant adsorption on montmorillonite was found to be three to ten times lower when the clay was pretreated with petroleum heavy ends. Surfactant retention in clean Nevada sand is also reduced when a surface layer of heavy ends is present on the sand grains.
The Modelling of Multisegment Production Profiles Using Hybrid Systems and Ordinary Differential Equations
Authors: Haavardsson Nils F. , Huseby Arne Bang
Published: December 2007

When an oil- or gasfield project is evaluated, it is crucial to have a satisfactory model for the production. Knowledge about the properties of the reservoir should be included in such a model. When used in a total value chain analysis, however, also economic and strategic factors need to be taken into account. In order to do this, more flexible modelling tools are needed. In this paper we demonstrate how this can be done using hybrid system models. In such models the production is modelled using ordinary differential equations representing both the reservoir dynamics as well as strategic control variables. The approach also allows us to break the production model into a sequence of segments. Thus, it is possible to represent various discrete events affecting the production in different ways. The flexibility of the modelling framework makes it possible to obtain realistic approximations to real-life production profiles. As the calculations can be done very efficiently, the framework can be incorporated in a full scale uncertainty analysis based on Monte Carlo simulation.
Measuring Well Injection Profiles of Polymer-Containing Fluids
Authors: Bragg J. R. , Roesner R. E. , Strassner J. E.
Published: December 2007

Determining injection flow profiles for various injected fluids was part of the surveillance program for monitoring the performance of Exxon's surfactant flood pilot test recently conducted in the Loudon Field, Fayette County, Illinois. Injection profiles for brine, microemulsion, and polymer drive water were measured using a radioactive tracer flow log. Profiles measured for brine injected prior to the microemulsion flood were in reasonable agreement with absolute permeability profiles determined by core analysis. However, for microemulsion injected in these same intervals, the profiles were found to be erroneous and completely misleading. For the viscous microemulsion, the profiles consistently indicated that all injected fluid was entering the upper one foot of the 13-foot-thick open-hole sandstone interval, thus suggesting the existence of horizontal fractures.

Poor dispersion of the radioactive tracer in the viscous microemulsion was believed to be responsible for the anomalous responses. To study the performance of the tracer flow log tool in water and in viscous solutions containing polymer, tests were performed in a visual flow loop using colored dye as a substitute for the radioactive tracer. Results confirmed that the tracer ejection system of the conventional tool usually ejected the tracer directly onto the casing wall where the velocity was substantially less than the average fluid velocity in the casing-tool annulus. When the flowing fluid was water, the turbulent jet of ejected tracer rebounded from the casing wall and was dispersed. However, when the fluid contained polymer, viscous laminar flow dampened dispersion of the tracer and retained it near the pipe wall, thus causing the interpreted flow rate to be essentially near zero.

To mitigate this problem, the ejection system of the tool was modified to allow tracer to be ejected closer to the center of the casing-tool annulus where the tracer velocity would be in better agreement with the average fluid velocity. A modified tracer flow log was subsequently used to redetermine injection profiles for microemulsion and polymer drive fluid in the Loudon pilot wells. Profiles measured by this modified tool were in reasonable agreement with profiles measured earlier for brine injection and with profiles of absolute permeability from core data.

Results of these experiments therefore show that injection profiles for viscous fluids measured by a conventional radioactive tracer flow log are likely to be unreliable. However, the log tool can be modified to provide reasonable results.
Applicability of Water Shutoff Treatment for Horizontal Wells in Heavy-Oil Reservoirs
Authors: Verre Francesco , Blunt Martin , Morrison Alan , McGarva Tony
Published: December 2007

The applicability of water shut-off treatment for horizontal wells in heavy oil reservoirs is analyzed in this study considering two different treatments: inorganic gel and relative permeability modifier (RPM).

In the first part of this paper, a general description of heavy oil reservoirs behavior is given, investigating the suitability of the treatment for this type of reservoir. The analysis is then applied to a real case, the Captain field. Captain is a heavy oil, largely homogeneous reservoir exploited with horizontal wells. Due to the presence of many production wells with high water cut, it has been considered a candidate for a water shut-off pilot project. Six different scenarios in a simulation study were considered with the reservoir properties of Captain in order to test the effectiveness of the treatment on production wells. These are typical producer/injector configurations found in a heavy oil field exploited with horizontal wells.

The aim is to analyze different water production mechanisms and evaluate the effectiveness of the treatment under different reservoir conditions. The influence of injection rate, oil viscosity, treatment of the injector and polymer adsorption were also investigated.

The study showed that the water production mechanism has a strong influence on the effectiveness of water shut-off treatment. In particular, water coning in heavy oil reservoirs can be effectively treated with gel if it is applied to the entire section of the well. Noteworthy is the effect of permeability variations: with lower kv/kh ratios it is possible to achieve a preferential path for treatment injection delaying effectively the water coming from a lateral injector/aquifer rather than from the water cone. Polymer adsorption has a negative influence on performance for high permeable zones. The treatment is not effective for low water cut wells, low oil viscosities and it is not suitable for injection wells.
Numerically Derived Type Curves for Assessing Matrix Recovery Factors
Authors: Pirker Barbara , Mittermeir Georg M. , Heinemann Zoltán E.
Published: December 2007

This paper presents a methodology for creating and running single matrix block models with a reservoir simulator. The small cell sizes lead to numerical problems that were successfully solved. Additionally recovery curves derived from numerous simulation runs under varying reservoir conditions are presented. These curves enable estimating matrix recoveries without running a simulation by only defining rock type and production conditions.

The investigations are based on undersaturated oil produced by water displacement. Imbibition forces, gravity drainage and capillary continuity are allowed for. Emphasis is put on the influence of wettability, matrix shape factor and permeability on recovery.

The common approach for simulating naturally fractured reservoirs is the dual continuum concept. Not so for the single matrix block model, in which a matrix block and the surrounding fractures are discretized by gird cells. The size of the resulting grid model equals the extensions of a matrix block described by the shape factor in a dual continuum simulation model.

Representing both the fracture and the matrix by grid cells makes a matrix-fracture transfer function obsolete, enabling a detailed investigation of matrix-fracture interaction. Consequently, numerical transfer functions and correlations for assessing recovery factors can be derived for certain reservoir conditions.

Naturally fractured reservoirs are a challenging task for the E&P industry for old and new oil fields. Many of the newly developed reservoirs happen to be fractured and therefore they are becoming more and more subject of extensive studies. In such systems most of the oil is stored in matrix blocks acting as fluid sources/sinks to the surrounding fracture planes in which fluid transport and production/injection takes place. Consequently, the matrix recovery factor is of special interest, and efficient and accurate methods to estimate the matrix depletion efficiency and matrix-fracture interaction should be found.
A New Polymer for Enhanced Oil Recovery
Authors: Bauer Richard G. , Klemmensen Daniel F.
Published: December 2007

A new water soluble acrylic polymer has been developed for use as a mobility control agent in enhanced oil recovery. This polymer was designed to meet the fundamental requirements for a mobility control application, including cost effectiveness, stability to mechanical shear, non-plugging in porous media, demonstrable tertiary oil recovery, stability in the presence of salts and chemicals, and retention of viscosity after extended exposure to elevated temperatures. This polymer has been extensively tested in the laboratory and compared to existing mobility control polymers, such as partially hydrolyzed polyacrylamides and polysaccharides. One of the major attributes that this polymer demonstrated was a retention of viscosity after extended aging at elevated temperatures in various media, including high brine conditions.

Laboratory core floods have shown this polymer to be equally effective in tertiary oil recovery in both polymer-augmented waterfloods and caustic-polymer waterfloods when compared to commercial partially hydrolyzed polyacrylamides. This new polymer is available in a liquid form (latex) and does not contain any hydrocarbon vehicle, such as those present in inverse- emulsion polyacrylamides.

The question of cost-effectiveness will not be addressed in this paper since it involves so many parameters that are beyond the scope of this technical evaluation.

Not all of the polymers evaluated were compared in each of the various test programs, but every effort was made to compare polymer types generically, i.e., polyacrylamides and a polysaccharide to rule out any glaring differences which might be inherent in their physical form, liquid or dry, molecular weight, or method of preparation. The only polysaccharide investigated was a dry powder product.
Fracturing Water-Sensitive Tuffaceous Reservoirs
Authors: Yang Y. , Han H. X. , Dusseault M. B. , Xu B. C. , Wang X. J. , Yu Y.
Published: December 2007

We present successful hydraulic fracture treatment practices in water sensitive tuffaceous reservoirs in Hailar Basin, China. The reservoirs are of too low permeability to be placed onto production without massive hydraulic fracture treatments. The article describes the geological engineering framework, mineralogy investigation, hydrolytic weakening experiments, as well as application and results of new kinds of fracturing fluids.

Rock mineralogy investigations indicated that rocks in the reservoir have a strong water sensitive property and a strong component of plastic behavior. Some tuffaceous rocks are rich in alkali minerals and become soft when exposed to aqueous fracture fluids. Although the fracture opening mechanism is the same as for normal sandstone, fracture extension is relatively suppressed and the fracture width is different from elastic predictions for normal sandstone.

The analysis led to the changes in treatment stratages. The key difference from previous treatment is that clay content and concentration of different minerals were taken into consideration of fracture fluid design. Different kinds of emulsified fracturing fluid were designed used to mitigate swelling and hydrolytic weakening effects. By the end of 2005, 163 intervals in 66 wells have been treated using these new kinds of fracturing fluids, with a success rate of 97%.
High-Temperature Drilling Fluid for Geothermal and Deep Sensitive Formations
Authors: Hilscher Larry W. , Clements William R.
Published: December 2007

A new high temperature drilling fluid system has been developed. The system which uses a thermally stable deflocculant and fluid loss additive has been tested in the laboratory at temperatures up to 450°F (232°C). It provides stable rheological properties and good filtration control even in the presence of severe cement contamination. Lime may be used with the system to inhibit shale swelling and dispersion.