bluuebunny/crossref_metadata_2025 huggingface dataset:
Molecular Responses in Fish as Risk Parameters of Long-Term Effects of Produced Water
Authors: Aas Endre , Andersen Odd Ketil , Baussant Thierry , Balk Lennart , Klungsøyr Jarle
Published: December 2007

The amount of produced water from oil production is expected to increase in years to come, and presently most of it is released to sea. Oil residues are regarded as one of the main environmental hazards of produced water discharges. The presence of polyaromatic hydrocarbons (PAH) metabolites in bile, induction of detoxification enzymes (CYP1A) and the formation of DNA adducts in liver was studied in a laboratory experiment with Atlantic cod (Gadus morhua). Responses in these parameters (biomarkers) have been positively correlated with the occurrence of mutagenic and carcinogenic effects in fish. The laboratory study demonstrated that PAH from the oil were taken up, metabolised and bound to DNA molecules after a 30 days exposure to dispersed crude oil at nominal oil concentrations as low as 60 µg/l (ppb). These molecular responses are suggested as environmental risk parameters for potential adverse effects of produced water, and in particular effects of PAH.

Atlantic cod, haddock (Melanogrammus aeglefinus) and long rough dab (Hippoglossoides platessoides) caught in an environmental monitoring survey in the North Sea, did not show detectable levels of PAH metabolites in bile nor induction of CYP1A, which could be associated to oil activity. DNA adduct formation was not investigated during this survey.
Biopolymer Pilot Facilities - Coalinga
Authors: Baxter Dan , Bowman R.W. , Tinker Gordon , Bates Ted
Published: December 2007

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

Introduction

Shell Oil Co. and the Energy Research and Development Administration (ERDA) plan to demonstrate additional oil recovery by enhanced waterflooding technique in the East Coalinga Field of California, which is shown in Fig. 1. Shell will provide 70 percent of the funding required for the polymer-flooding demonstration pilot. pilot. In older fields in California having moderate viscosity oils, waterfloods have been marginally successful or potential projects have been delayed pending development of mobility control technology. Where justified, the optimum process for a supplemental recovery project would be polymer flooding directly project would be polymer flooding directly following primary oil production. The Coalinga project falls in this category, and it has been project falls in this category, and it has been designed to determine if the added expense of a polymer flood over a conventional waterflood is polymer flood over a conventional waterflood is justified in the Temblor Zone II reservoir. This reservoir has produced primary oil since 1901 and has an unfavorable water displacement mobility ratio of 14.

Background

Fig. 2 indicates the Coalinga Field and pilot project area. The magnitude of the pilot project area. The magnitude of the full-scale project from Shell's Temblor Zone II reservoir in Coalinga is 35 million bbl from polymer flooding. Of this amount, 8 million bbl polymer flooding. Of this amount, 8 million bbl would be recovered in excess of a waterflood. These parameters for the full-scale project are outlined in Table I.

The initial phase of the project is scheduled to commence July 1976 with the injection of 5,000 B/D water into four injection wells. Following 1 year of water injection, biopolymer will be injected for about 1.5 years to increase the water viscosity and thus reduce the mobility ratio. The choice of this polymer is discussed in Ref. 1. After polymer injection, additional water injection will follow. Ultimate additional oil above primary from the 130-acre project area is expected to amount to 2,600,000 bbl, project area is expected to amount to 2,600,000 bbl, including 600,000 bbl resulting from polymer injection instead of just water. Daily production will increase to 1,000 bbl oil and production will increase to 1,000 bbl oil and 4,000 bbl water. Using improved estimates of fluid properties and reservoir description from the demonstration project, a numerical simulator would be applied to compare the performance of polymer flooding and waterflooding. Following polymer flooding and waterflooding. Following a reliable comparison, full-scale expansion would be made. Pilot parameters with some typical reservoir parameters and a type log from the Temblor Zone II reservoir are included in Tables II and III and Fig. 3.
Sulfonation of Petroleum Feedstocks in a Wiped Film Reactor
Authors: Ashcraft T.L. , Saunders R.K.
Published: December 2007

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

This paper summarizes the yields of broad spectrum sulfonates obtained from the sulfonation of selected petroleum fractions using gaseous SO3 in a wiped film reactor. Sulfonation is selective toward molecules having more than two aromatic rings; however, SO3 treats well in excess of 1.0 moles SO3/mole feed aromatics are required to achieve aromatics conversions in excess of 50–70%. Sulfonic acid decomposition with concomitant formation of SO2 can significantly reduce sulfonates yield. Sulfonic acid decomposition, which can be minimized by rapid neutralization of the acid product, is an important consideration in the design of a sulfonation process.

Introduction

Sulfonates produced from lube boiling range petroleum fractions are potentially important as tertiary oil potentially important as tertiary oil recovery surfactants. This type of broad spectrum sulfonate can be produced from one of several processes which utilize either oleum or SO3 as the primary sulfonating agent. Hydrocarbon primary sulfonating agent. Hydrocarbon sulfonates are a major component in many micellar formulations. As a result, their cost is an important element in micellar flood economics. Both the yield of hydrocarbon sulfonate per unit feedstock and the type and distribution of sulfonation by-products will strongly influence projected surfactant manufacturing costs.

The objective of this study was to investigate the sulfonation of selected lube boiling range petroleum fractions under a variety of reaction conditions utilizing a wiped film reactor and gaseous SO3. Product distributions and yields are correlated against feed molecular weight and type, SO3/oil feed ratio, sulfonic acid soak time and reactor effluent temperature.

CHEMISTRY

The formation of broad spectrum petroleum sulfonates occurs primarily petroleum sulfonates occurs primarily through reaction of SO3 with molecules in the oil which contain at least one aromatic ring followed by neutralization of the resulting free acid.
Chemical Mass Balance Model – A Tool to Predict Present and Future Chemical Discharges with Produced Water
Authors: Bakke S. , Vik E. A. , Stang P. , Kelley A. , Ravnestad M. , Voldum K. , Jensen R. D.
Published: December 2007

A chemical mass balance model was developed for the Ekofisk area in the North Sea, operated by Phillips Petroleum Company Norway. The present model includes 13 platforms. There are continuous produced water discharges from five of these. Only production, pipeline and injection chemicals are included in the model. The model predicts the amount of chemicals in produced water at each discharge point, the chemical content in the exported oil, as well as chemical consumption and costs. Based on current chemical treatment philosophy and the fall 1999 long-term production forecast for the Ekofisk Area fields, prognoses for chemical consumption and discharge over the lifetime of the individual platforms and for the total Ekofisk Area were established. Examples from the model predictions are presented in this paper.

The most important parameter in the model is the oil/water partitioning; i.e. the discharge factors of the individual chemicals. The paper presents results from initial validation studies including comparison of the partitioning factors applied in this model with results obtained from laboratory and field studies.
Hydrogen Sulfide Forecasting Under PWRI (Produced Water Reinjection)
Authors: Oen Amy M. P. , Vik Eilen A.
Published: December 2007

An initial evaluation of the hydrogen sulfide (H2S) formation potential under produced water reinjection (PWRI) for samples taken from the A/S Norske Shell operated Draugen platform has been performed using the Sawyer and McCarthy model. This model provides an estimate to the maximum H2S generation potential. The modeling results have been considered to be adequate for input to preliminary PWRI evaluations and can together with laboratory experiments and field trials be used to design reinjection operations and keep extra costs to a minimum.
Fracture Flow Capacity - A Key to Sustained Production after Hydraulic Fracturing
Authors: Jennings A.R. , Lord D.L.
Published: December 2007

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

The objective of a hydraulic fracturing treatment is to place a conductive fracture deep into the producing formation. Fracture flow capacity, or ability of the propped fracture to conduct fluids, is one of the most important aspects of the treatment. Several laboratory test procedures have been developed to evaluate proppants under a wide range of closure pressures and concentrations.

As well depths increase, it is necessary to adjust proppant systems to compensate for additional loads under producing conditions. Recently, success has been encountered using mixtures of sand and high strength proppants in deep formations in proppants in deep formations in Northern Louisiana, East Texas, and Oklahoma.

Information provided in this work will offer guidelines which should be considered for any fracturing treatment using propping agent. Fracture flow capacity of the fracture system is of utmost importance currently because many marginal zones are being completed and fractured. Sustained production increase is also very production increase is also very important. Laboratory and field application data indicate proppant systems initially selected have an influence on well production behavior throughout the producing life of the well.

Introduction

With the current emphasis on oil and gas production, much attention is being given to means of well stimulation. The objective of these stimulation treatments is to improve well production beyond what it will produce naturally.

Several methods of well production stimulation presently are available. These methods include wellbore clean-out treatments, chemical treatments in the formation matrix surrounding the wellbore, fracture acidizing, and hydraulic fracturing with proppant.

In many low permeability formations, wellbore improvement methods may not provide a large increase in production. provide a large increase in production.
Comparison Between Full Scale Experimental Data and Calculations with Kameleon FireEx, A Simulator for Gas Dispersions and Fires
Authors: Spaggiari Laura F. , Blotto Paola , Vembe Bjørn E. , Lilleheie Nils I. , Magnussen Bjørn F.
Published: December 2007

A study has been performed to investigate the efficiency of Kameleon FireEx, a three dimensional transient simulator for fire and gas dispersion scenarios. Kameleon FireEx can handle hydrocarbon pool and jet fires within complex geometry, solving problems typical of oil and gas companies.

The code has been developed by SINTEF Energy Research Division Applied Thermodynamics and Fluid Dynamics, within a Joint Industry Project sponsored by Ruhrgas, Gaz de France, Statoil, Elf and ENI.

The paper presents some validation cases of the code, carried out with the support of full-scale measurements.

A natural gas release from a vertical vent stack is considered: six jet fires resulting from the ignition of subsonic releases and ten unignited gas dispersions (two sonic jets included).

The size and the shape of the flame obtained are realistic and close to the measurements. The radiation levels predicted show a good agreement with the experimental data, even though in some cases the differences between Kameleon FireEx and the measurements are significant.

The gas concentrations, resulting from subsonic releases, are calculated with reasonable agreement with experiments, while the use of a simple pseudo diameter method for the sonic jet release results in overestimated plume sizes.
Determination of Gas Well Deliverability of Vertically Fractured Wells
Authors: Hadinoto Nino , Raghavan R. , Thomas G.W.
Published: December 2007

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

The applicability of commonly accepted radial flow solutions to estimate deliverability of vertically fractured gas wells was examined. Synthetic deliverability data (isochronal and flow after flow) were generated using a two-dimensional single-phase gas simulator. The effect of fracture length and pressure level and PVT data was investigated. Flow-after-flow data PVT data was investigated. Flow-after-flow data also were used to investigate the application of the Odeh-Jones method for analyzing variable rate drawdown data to determine formation permeability and skin factor (fracture length) permeability and skin factor (fracture length) for a vertically fractured gas well.

It is shown in this study that conventional methods of predicting deliverability from short-time isochronal and flow-after-flow tests will lead to calculation of erroneous values of absolute open flow (AOF) than that which would be obtained from long-time flow tests. Depending on specific conditions, these errors can be either lower or higher than actual values. It is also shown that flow exponents different from unity can be obtained from short time flow tests even though laminar flow prevails. This result is a consequence of prevails. This result is a consequence of changing flow regimes that result due to the vertical fracture.

This study also indicates that if the Odeh-Jones method of analysis is used, then data obtained for analysis should correspond to the pseudo radial flow period. If early data where linear flow controls pressure behavior are used, then erroneous results will be obtained.

Introduction

Gas well deliverability tests are multipoint tests consisting of three or more flows with pressures, rates, and other data being recorded as a function of time. These tests are usually required by state regulatory agencies for proration purposes and to obtain an allowable. In addition, these tests can provide information for reservoir and provide information for reservoir and production engineering studies. production engineering studies. Basically there are two different types of deliverability tests:flow-after-flow tests andisochronal tests.

Both of these are very well documented in the literature. Gas deliverability is often determined by use of the empirical equation:

......................(1)
The Improved Birdwell Casing Finder
Authors: Baltosser R.W. , Honea Cecil
Published: December 2007

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

The Birdwell Casing Finder is designed to locate lost or abandoned oil well casing at depth in the ground. It does this by means of a system of sensors which measure the differential in the horizontal component of the magnetic field. This measurement provides information as to the depth to the provides information as to the depth to the top of the abandoned casing as well as the distance and direction to the casing from an exploratory borehole drilled in the vicinity of the lost casing. The casing can be detected at distances of fifteen to eighteen feet horizontally.

Introduction

During the three years that the Birdwell Casing Finder has been in use, it has become apparent that certain modifications to the basic instrument were desirable.

An analysis of these modifications suggested that if improved resolution of the data plus an accurate orientation could be achieved, along with changing of housing materials, the instrument could be used to depths as great as 10,000 feet in the heaviest drilling muds.

A design review of the basic instrument suggested that if the existing detection system was duplicated and placed at right angles to the existing system, then the requirement of improved resolution would be me" Also, it was theoretically possible to use a pair of crossed fluxgate detectors as a magnetic compass sensitive to the earth's magnetic field. Since many of the existing borehole inclinometers use the earth's field as their orientation reference and the existing detection system uses fluxgate magnetic detectors, this appeared to be a reasonable solution. An analysis of existing borehole inclinometer data suggested that such a compass would be reliable to a distance of fifty feet above the casing top, though in some orientations it would be reliable to within ten feet from the casing top. This data suggested that the development of such a fluxgate compass was desirable and a research project was subsequently set up and satisfactorily completed.
Laboratory Steamfloods in Half of a Five-Spot
Authors: Huygen Hans H.
Published: December 2007

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

Eight crudes were steamflooded at different temperatures and pressures in a 3-dimensional model of a five-spot pattern.

Oil production and steam sweep data are fitted with exponential curves whose parameters are correlated with oil and steam characteristics as are steam sweep and fraction of ultimate recovery occurring at steam breakthrough.

In several correlations, crude viscosity as a correlator is replaced by distillation residue as determined by a simple test. Implications of the correlations are discussed.

Introduction

Enhanced recovery of oil by steam injection is practiced widely by the huff and puff method of stimulation. Several large-scale projects, among them Getty's huge Kern River, are being converted to steamflooding. However, few thermal projects are operated from the start as a projects are operated from the start as a steamflood. This is caused in part by the lack of information on how efficient and economic a continuous steam drive will be in a given field, and in part by the greater payout time that steamflooding part by the greater payout time that steamflooding necessitates. Furthermore, much of the oil needing enhanced recovery schemes falls in the category of heavy oil, and it is thought that oils of several thousand mPa-s (cp) will not allow a satisfactory steam sweep to be made.

To obtain data on the applicability of steamflooding, eight crudes were selected from formations whose pressure was below 6.89 MPa (1000 psia)(at a depth of 2250 ft), thus allowing psia)(at a depth of 2250 ft), thus allowing real-pressure floods to be performed in a 3-dimensional model of half of a 5-spot pattern. To render the problem tractable, influence of gravity segregation is not taken into account, thus excluding modeling of steam override. For the same reason, inhomogeneities due to stratification are not examined, nor are pemeability variations. Moreover, steam injection rate is constant from test to test so as to keep the number of tests manageable. Even so, statistical analysis of the results yields useful correlations.
Chemical Diversion of Heat Will improve Thermal Oil Recovery
Authors: Fitch Jon P. , Minter Rick B.
Published: December 2007

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

Cyclic steam injection has been employed to improve recovery in "heavy oil" (8–16 degrees API) reservoirs for several years. The major factor in maximizing recovery is the ability to ensure uniform distribution of heat across the productive intervals.

A unique chemical process to control steam injection profiles has been developed to divert heat away from depleted, high permeability sands. The product has increased permeability sands. The product has increased injection pressures, has altered downhole survey profiles, and has shown substantial incremental oil when compared to the response of the wells' prior cycles. Treatment costs are minimal in that the diverting agent is carried into the reservoir with injected steam and no special well preparation is necessary. This paper will summarize work accomplished over a two-year period beginning with initial field testing in 1973. The test area is located in Midway Sunset Field, 40 miles west of Bakersfield, California (Figure 1).

Introduction

Poor injection profiles are a major Poor injection profiles are a major detriment to success in waterflooding and most other secondary recovery techniques. Cyclic steam stimulation is no exception and the problem in the subject area is magnified by the massive, unconsolidated Potter sands. These sands, at an average depth of 1400 feet and an average thickness of 400 feet, display permeabilities in excess of three darcies and an average porosity of 35%. The erratic grain size, porosity of 35%. The erratic grain size, varying from fine oil silts to large cobbles, suggests a fluvial fan deposit whose complex intra-stratigraphic framework is the result of interbedded, braided stream systems. The production of low gravity crudes in this area is production of low gravity crudes in this area is influenced by gravity drainage, the dominant reservoir mechanism, and requires gravel packs for sand control. Localized depletion occurs in the upper portions of the major sand bodies which, when coupled with the loss of steam and production control due to gravel packs and production control due to gravel packs and essentially no initial reservoir pressure, compounds steam "thief" problems. These "thiefs" are present at the time the well is completed or they occur through continued steaming.
The Effect Of Void And Filled Perforations On Well Productivity
Authors: Dietrich James K. , Bondor Paul L.
Published: December 2007

Numerical simulation using cylindrical coordinates provides a powerful technique for analyzing the fluid flow behavior in the formation immediately adjacent to production and injection wells. This technique was used to study the effect of both void and filled (gravel- packed) perforations on well productivity. packed) perforations on well productivity. The results indicate that perforating (even without formation damage) causes a more severe level of impairment than heretofore recognized. We found in both the void and filled (gravel-packed) perforation cases that radial flow does not occur as close to the wellbore as previous investigators have assumed. This previous investigators have assumed. This larger than previously expected non-radial flow region will create a skin or damage effect.

In the case of filled perforations, permeability of the gravel pack of perforating permeability of the gravel pack of perforating debris has a very large influence on productivity. Results appearing in the literature concerning productivity through perforated casing (all of productivity through perforated casing (all of which assume the perforation has empty cavity), are unduly optimistic when applied to unconsolidated reservoirs.

Introduction

Details of flow in the vicinity of a cased, perforated well are useful for predicting and evaluating completion methods, impairment, and formation and casing stresses. All previous investigations have assumed that the hole in the formation and the tunnel in the casing formed by the perforating action remain void of any solid material. Thus, in these earlier studies there was no pressure drop between the wellbore and perforation block. Under this assumption, a perforation block. Under this assumption, a perforated wellbore may actually lead to perforated wellbore may actually lead to improved productivity, as compared to the case of an open-hole completion. For example, the results of previous work indicates that a ratio in excess of unity can be achieved when perforating with more than about four 1/2 inch perforations per foot. per foot. In these earlier studies, the fluid was assumed to have a small and constant compressibility and the distance at which azimuthal pressure gradients become insignificant (ro) was pressure gradients become insignificant (ro) was generally specified arbitrarily in the range 18 rw less ro less 30 rw.

A three-dimensional finite difference simulator was used to model the effects of void perforations on the flow of both real gas and a perforations on the flow of both real gas and a fluid of small and constant compressibility. In the case of filled perforations, the effect of pack permeability was examined using constant pack permeability was examined using constant compressibility fluid flow.
The Areal Sweep Efficiency of the In-Situ Recovery of Subbituminous Coal
Authors: Jennings James W. , Gunn Robert D. , Brandenburg Charles F. , Whitman David L.
Published: December 2007

Jennings, James W., Member SPE-AIME, Texas A and M U. and Laramie Energy Research Center, Gunn, Robert D., U. of Wyoming and Laramie Energy Research Center, Brandenburg, Charles F., Laramie Energy Research Center, and Whitman, David L., U. of Wyoming and Laramie Energy Research Center

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

This paper presents the results of applying particle tracking techniques to the prediction of areal sweep for the in-situ prediction of areal sweep for the in-situ recovery of subbituminous coal. Comparison of field data with calculated values indicate that these techniques are applicable and support the theory that the in-situ recovery of subbituminous coal as encountered at Hanna, Wyoming, is a permeation process. The model predicts breakthrough of the flame front at the production well and intermediate points with sufficient accuracy for preliminary design purposes.

Introduction

A brief study of the areal sweep efficiency of underground coal gasification (UCG) has been made in connection with the field experimentation being conducted by the Laramie Energy Research Center (LERC), U.S. ERDA, near Hanna, Wyoming. One of the most important questions raised when discussing commercialization of the process is that of resource recovery efficiency and the effect of recovery efficiency on the economics. In addition, with the energy shortage situation of the recent past, more emphasis is being placed on the development of processes which produce a maximum amount of the in place energy. The following discussion describes a simple approach to determining the areal sweep efficiency for UCG and compares the results with field experimental results.

Background

The process being utilized by LERC in the ongoing experimentation near Hanna, Wyoming, is known as the linked vertical well process. This process uses reverse combustion to modify the natural permeability such that gasification in the forward mode can be conducted. This basic process has been described previously.

This study concerns two parts of the LERC program, Phases I and II of the Hanna II experiment. Data from Phase I was presented earlier. The field data reported presented earlier. The field data reported in this paper are from Phase II of the Hanna II experiment which utilized a four well square pattern with 60 feet spacing. The four injection-production wells were drilled into the Hanna #1 coal seam, a subbituminous coal which is 30 feet thick and at a depth of 275 feet at this site.
Dispersion and Tortuosity in Sandstones
Authors: Donaldson Erle C. , Kendall Ronald F. , Manning Francis S.
Published: December 2007

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

Linear dispersion and mass transfer coefficients were measured for Bandera, Berea, Cottage Grove, Noxie and Torpedo sandstones ranging in permeability from 12 to 420 md. Experimental data were permeability from 12 to 420 md. Experimental data were obtained from analysis of effluent concentration changes resulting from a step increase of the influent tracer concentration. Brine and a tritium-labeled brine solution were used as tracers. Coefficients of dispersion were calculated by comparing the experimental data with solutions of the diffusion equation by three methods:analytical solution of the diffusivity equation,a graphical method, andnumerical, finite difference, solution.

The three methods yielded equivalent results.

Tailing of the effluent response curves was interpreted by introducing two additional parameters to the diffusivity equation: (1) the immobile parameters to the diffusivity equation:the immobile fluid fraction of the porous medium determined independently by capillary pressure measurement anda mass transfer coefficient to account for tracer interaction with the immobile fluid fraction.

The Berea sandstone exhibited the sharpest displacement front and the least amount of tailing, making it the best selection for experiments in which steep displacement fronts are encountered, such as miscible displacement.

Molecular diffusion measurements were used to calculate tortuosity factors for each of the five sandstones using two pairs of gases: hydrogenair and hydrogen-nitrogen. These results are equivalent to tortuosities independently determined by electrical conductivity measurements. The coefficient of dispersion and the tortuosity of sandstones are shown to be excellent parameters for characterization of geologic materials for the study of fluid flow properties.

Introduction

Knowledge of the flow patterns of solutes in flowing streams through porous geologic materials is important in applying the technology for miscible phase displacement for recovery of petroleum and injection of mobility- and wettability-control agents. Kaufman and Orlob also emphasized the use of tracers for analysis of saline water intrusion into fresh water aquifers and evaluation of proposals for the underground storage of radioactive materials.
Field Application of Pressure Buildup Tests, Jay-Little Escambia Creek Fields
Authors: Langston E.P.
Published: December 2007

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

Pressure buildup tests are a valuable reservoir description and well evaluation tool in the Jay-Little Escambia Creek (Jay-LEC) Fields of Alabama and Florida. Four practical applications are demonstrated from the results of forty-three tests conducted to date. A comprehensive coring program coupled with high quality, consistent test data have made such applications possible. Buildup tests have provided the basis for arithmetic averaging of core provided the basis for arithmetic averaging of core data to determine effective reservoir permeability and are a significant guide in the permeability and are a significant guide in the planning and evaluation of workovers. Remedial planning and evaluation of workovers. Remedial action taken as a result of such tests will substantially improve waterflood conformance. These tests have also provided information that are an aid in the solution of reservoir description problems.

Introduction

This paper will briefly describe the test and interpretation procedures used by Exxon in the Jay-LEC Field and will demonstrate practical applications of test results to solve specific reservoir and production engineering problems. These applications were made as the field was developed, unitized, moved into a secondary recovery program, and underwent a major stimulation workover program. Specific demonstrated applications are:Buildup test permeability thickness values, correlated with those from core analysis data, provided the basis for arithmetically averaging core data to determine effective reservoir permeability. Well deliverabilities were predicted, and two reservoir models were constructed utilizing these data.Horizontal barriers to vertical flow were determined to exist in massive Smackoverpay sections. As a result, workover planning and implementation was significantly influenced.Buildup tests were used to determine the need for well stimulation to open total pay section and to evaluate the effectiveness of workovers which were designed to accomplish this objective.Reservoir limits, as defined by geological interpretation, were confirmed by buildup tests.

The Jay Field was discovered in Northwest Florida during June 1970 when the St. Regis No. 1 well penetrated the Smackover Formation. Further drilling expanded field limits into Alabama, and development of this (15,500 feet) deep reservoir proceeded rapidly on 160-acre spacing. The Alabama portion of this common reservoir was designated as the Little Escambia Creek Field. During development, a comprehensive data gathering program was maintained. Each well, in addition to being logged with gamma ray, resistivity and porosity tools, was conventionally cored through the Smackover and Norphlet pay zones with core recovery averaging 82 pay zones with core recovery averaging 82 percent. percent.
On the Mechanism of Foam Formation in Porous Media
Authors: Kanda M. , Schechter R.S.
Published: December 2007

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

Foam can be created within the interstices of a porous medium by displacing a resident surfactant solution with a gas. This process of in-situ foam formation has a number of potential applications. Thus, it is of potential applications. Thus, it is of interest to establish those properties of surfactants which improve the performance of a given process.

Both anionic and nonionic surfactants were studied. Each was characterized by its surface tension, surface viscosity, foaming ability, foam stability, bulk viscosity and wettability.

The effectiveness of a particular surfactant solution was determined by measuring the breakthrough time, displacement efficiency and permeability reduction attending the permeability reduction attending the displacement of the solution from a sand pack by nitrogen. It was found that:the breakthrough time is increased by increasing the surface tension and surface viscosity;the displacement efficiency is increased by increasing the surface viscosity and by decreasing the surface tension; andthe permeability to gas is a sensitive function of the surfactant solution wettability.

The presence of salt in the surfactant solutions did not significantly change the results. For most systems its effect can be neglected. On the other hand, the presence of oil, even in very small amounts, cannot be ignored. Oil can have a very deleterious effect on performance.

Introduction

The presence of foam within the interstices of a porous medium can substantially reduce the permeability to gas while leaving the permeability to liquid essentially unchanged. Various applications which utilize this phenomenon have been proposed. For example, it has been suggested that foams may help reduce the leakage of gas through fractures in reservoir rocks (1), (2), reduce gas coning (3) and be used as an oil displacing agent (3), (4), (5), (6), (7), (8), (9). These processes generally involve the injection of processes generally involve the injection of an aqueous phase containing a surfactant followed by gas, although in some cases it has been suggested that the liquid and the gas be injected simultaneously. In either case the purpose is to create a zone following the purpose is to create a zone following the liquid-gas contact which contains a stable foam.
Application of Risk Management Principles to Pipeline Leak Prevention in the Niger Delta
Authors: Abifarin O. , Mishael S. J.
Published: December 2007

Recent oil spills in the Niger Delta have challenged the industry to reassess and more aggressively pursue spill prevention efforts. Further, many production locations are situated in close proximity to local populations, who are skeptical of the industry's commitment to spill prevention. Responding to these concerns, Chevron Nigeria Limited has implemented a Risk Management based Pipeline Integrity Project to significantly enhance leak prevention efforts. Operations comprise approximately 700 pipelines and flowlines situated in various habitats including environmentally sensitive mangrove swamp, agricultural lands and offshore. The Risk Management process estimates likelihood and consequences of potential leak scenarios, both corrosion and non-corrosion. Leak prevention proposals are then evaluated based on how effective they are at reducing risk. A structured project management process is concurrently used allowing rapid transition of project recommendations to project implementation.
Analytic-Numeric Hybrid Modeling Approach for Interpreting Transient Tests in Horizontal Wells
Authors: Su Ho-Jeen , Kabir C. S. , Dismuke C. T.
Published: December 2007

Uncertainties arise while interpreting transient tests in horizontal wells. This study presents a hybrid approach in that both analytic and numeric models are used to circumvent most of the problems associated with the conventional analytic interpretation.

This novel approach entails multiple steps. Initially, reservoir parameters are estimated by identifying as many flow regimes as possible using the analytic method. Thereafter, a numeric simulation model is built using a coupled wellbore-reservoir simulator. Herein, we seek to match the wellbore flow profile data, collected by production logs (PL), by adjusting local permeability and skin. This PL-matched model then allows rate calculation during the transient-test periods, using measured bottomhole pressure as the inner-boundary condition. Finally, the computed rate is convolved with pressure to interpret the drawdown data for seeking reconciliation with buildup interpretation.

We present two field examples to illustrate the application of the notion presented here. Complications arise while interpreting flow and buildup tests using conventional tools, because of complex well trajectories penetrating this heterogeneous carbonate reservoir. Results show that reservoir anisotropy (kv/kh) is a very sensitive parameter and is therefore well determined. The history-matched model was quite successful in predicting the water cut behavior over 18 months in one of the wells.
Advances in Multilayer Reservoir Testing and Analysis using Numerical Well Testing and Reservoir Simulation
Authors: Jackson R. R. , Banerjee R.
Published: December 2007

This paper presents multilayer testing and analysis techniques to obtain layer permeabilities and skin factors using pressure and flowrate transient data from sequential flow tests acquired with production logging tools. The analysis of these tests by application of numerical well test analysis is highlighted. An integrated workflow is shown and a new analysis technique is presented which incorporates numerical reservoir simulation and an automated history matching procedure. A gradient method has been successfully applied to modify simulation model input parameters to match synthetic and field examples of multilayer transient tests. The study also highlights the potential for the application of this method and for automated history matching techniques to pressure transient and flowrate transient analysis and multilayer test analysis and interpretation.
Vertical Interference Testing Method Using Dual Completions with Downhole Water Sink
Authors: Ramos Luis R. , Shirman Ephim I. , Wojtanowicz Andrew K.
Published: December 2007

Downhole Water Sink (DWS) well completions segregate production in the wellbore by producing water from the water leg in the reservoir and oil from the upper oil bearing portion of the reservoir. A downhole pump drains water from the bottom completion and creates pressure drawdown that inhibits water coning up to the upper producing zone. The pump injects the water to a disposal zone lower in the wellbore.

Successful application of DWS technology in wells with water coning problem requires effective zonal isolation between the top and bottom completions of the well and good knowledge of permeability anisotropy. As these wells are dual completed, they are uniquely configured for vertical interference testing. The problem is that such test involves two fluids, water and oil, and is typically performed in a reservoir rock with no isolating layer between the top and bottom completion.

The paper presents a new mathematical model and analysis method for vertical interference testing using top completion (in the oil leg) for production, and bottom completion (in the water leg) for observation. The model is analytical and accommodates partial penetration and permeability anisotropy. The analysis method employs a family of type curves. Also shown in the paper are examples of possible applications of this new testing method.
Pompano Paraffin Calibration Field Trials
Authors: Kleinhans J. W. , Niesen V. G. , Brown T. S.
Published: December 2007

Models exist for predicting paraffin deposition in wellbore tubulars and flowlines. However, with increasing water depths and subsea offset distances approaching 15 - 30 miles and more, the need to properly design black oil, multiphase subsea systems for wax management is critical to successful project delivery. To increase the confidence level for using one of these theoretical models to predict paraffin deposition in a multiphase seabed line, the Pompano 4-1/2 mile subsea tie-back system was used to validate the theoretical model predictions. This paper describes the model and predictions, the field trials that were done to obtain comparison information, and the results. Field conditions required sequential modeling of six subsea wells that were each produced through a single line to the host Pompano Platform test separator. Multiphase fluids included a wide range of individual well oil, water and gas rates. The wax deposition modeling was done without knowledge of the related field paraffin cutting observations. Thus, the close agreement that was obtained between the predicted and observed paraffin deposition increased confidence level in the model results.
Compositional Simulation of Water-Alternating-Gas Processes
Authors: Christensen J. R. , Larse M. , Nicolaisen H.
Published: December 2007

In recent years several authors have demonstrated that relative permeability hysteresis effects may be significant in the physically correct modelling of general gas injection processes and WAG processes in particular. Today simple hysteresis models are available in most simulators, but more recent and advanced models are still not standard tools. Especially when compositional simulation is needed the choice of hysteresis models is generally limited to very simple models.

In this work we have combined a compositional simulator with a calculation method for relative permeabilities developed for Water Alternating Gas (WAG) injection (Ref. 1). The model can roughly be categorised as an extension of the well known Killough hysteresis model from two to three phases. Hysteresis behaviour is implemented for the water and gas phases (wetting and non-wetting phases). The residual oil saturation (intermediate phase) is dependent on the trapped gas saturation if the Stone1 method is used for calculation of relative permeabilities for the oil phase.

The paper describes a few simplifications made to the model and its implementation in a compositional simulator. Special attention is given to compositional effects such as solution of gas components in the oil phase. We then present simulation results showing the impact of the hysteresis model on oil production, first for a synthetic model (5th SPE comparative solution project), then for a real North Sea oil reservoir with WAG as primary recovery mechanism. The model is found to give a more physically correct description of three phase flow than exisiting hysteresis models and will be an enhanced tool for history matching and simulation of production forecasts.
Analysis of Measured Bottomhole Treating Pressures During Fracturing: Do Not Believe Those Calculated Bottomhole Pressures
Authors: Keck Richard G. , Reiter Doris F. , Lynch Keith W. , Upchurch Eric R.
Published: December 2007

This paper presents the analysis of measured bottom hole pressure data for 45 hydraulic fracture treatments pumped in Alaska and California in the past three years. On 30 of these wells, bottom hole data was obtained from memory gauges deployed on the tubing or in side-pocket mandrels, while the other 15 wells had reflected pressure up an open annulus. The fluid systems were either delayed borate guars, or linear gel HECs.

The paper starts with a comparison of these measurements with the Keck et al4 correlation. The results show that there are large systematic errors both in the magnitude and trends of the correlation. We illustrate the effects these errors have on net pressure analysis and on the success of executing these tip screen out treatments. The data also shows an unexpected transient effect in almost all the wells, whereby changes in surface pressure of 100’s to 1000’s of psi are found to change the bottom hole pressure by 10’s or 100’s of psi, respectively. We speculate on possible causes for this phenomenon, but conclude that additional work is needed for accurate predictions of bottom hole pressures during fracturing treatments.
Selecting Drilling Fluid Properties and Flow Rates for Effective Hole Cleaning in High-Angle and Horizontal Wells
Authors: Adari Rishi B. , Miska Stefan , Kuru Ergun , Bern Peter , Saasen Arild
Published: December 2007

This paper presents a method to determine optimum drilling fluid properties and flow rates to minimize cuttings bed height and circulation time in high angle and horizontal wells. The method uses empirical models relating the cuttings bed height and the bed erosion time to drilling fluid properties and flow rates.

Bed erosion tests have been conducted using a cuttings transport facility available at the University of Tulsa. Cuttings bed height as a function of time has been investigated by using variable flow rates (200 – 400 gpm) and four different drilling fluid compositions. Experimental results were used together with a non-linear regression analysis program to establish a functional relationship among drilling fluid properties, flow rate, cuttings bed height and the time required to circulate the borehole clean.

A numerical example is provided to explain the field application of the method. The sequential calculations involved in determining optimum combination of the Power Law viscosity parameters n and K, and the flow rate to minimize the cuttings bed height and circulation time are also given.

Field implementation of the proposed empirical correlations and the new method can aid optimization of circulation practices before tripping, and so reduce the associated risk of nonproductive time.