bluuebunny/crossref_metadata_2025 huggingface dataset:
Geological and Engineering Thinking in the Gulf Coast of Texas and Louisiana - Past, Present, and Future
Authors: Halbouty Michel T.
Published: December 2007

Introduction

To understand the present situation and the future possibilities of the Gulf Coastal province, it is important to go back to New Year's Day, 1901, and review the status of world production and the extent of the application of science to the finding of oil.

The world's annual production was about 138 million bbl. Russia was the leading oil producing nation with an annual output of 68 million bbl. Of the 58 million bbl being produced in the United States, 92 per cent, or 53 million, was from the so-called "oil region" of Ohio, West Virginia, Pennsylvania, Indiana and New York. Four million, or 6 per cent, was from California, and the remaining 1 million, or 2 per cent, was produced in Texas, solely from the Corsicana field.

Learned men, and the big-time operators of that day paid little attention to new oil possibilities of other areas. When a new field, such as that in Corsicana, was found, it disturbed the thinking of the young industry. Corsicana was not very exciting to producers because the average production per well was about that of the wells in the other fields in the country. As far as the Gulf Coast was concerned, the best brains in the business said that the area would never produce any oil whatsoever, that the unconsolidated sands underlying the Coast area could have no oil, and that the region as a whole was unworthy of testing with the drill.

The Spindletop Discovery

That was the setting on New Year's Day, 1901. Then suddenly, like the cascade of a torrential flash flood, 10 days later at 10:30 a.m. the discovery of Spindletop changed the thinking of man the world over. It completely revolutionized industrial engineering and gave birth to the liquid fuel age. This significant discovery made a revolutionary impact on the entire world. It made the United States the foremost oil producing nation overnight. It was to catapult the United States into the position of first world power, although it would take a few years and a world war to bring about the full realization of that fact.
General Heterogeneous Radial and Linear Models for Well-Test Analysis
Authors: Levitan M. M. , Crawford G. E.
Published: December 2007

This paper presents a new analytical method for solution of the pressure transient problems for general radial and linear models with heterogeneities. In these models, the storativity and the transmissivity coefficients are considered functions of the distance from the well. The solution method is based on a special transformation of variables that reduces the problem to a diffusivity equation with constant coefficients. This equation is then solved in the Laplace transform domain, and the solution is inverted into the real-time domain by the Stehfest algorithm. The solution method allows continuous variation as well as discontinuities of the rock and fluid properties. The new solution algorithm reproduces all known exact solutions for specific variation of properties including the multi-composite radial and linear model solutions.
Simultaneous Gravel Packing and Filter-Cake Cleanup With Shunt Tubes in Openhole Completions: A Case History From the Gulf of Mexico
Authors: Godwin Keith , Gadiyar Bala , Riordan Hal
Published: December 2007

A case history from the Gulf of Mexico is presented in this paper for drilling and completing a horizontal openhole well with simultaneous gravel-packing and filter-cake cleanup with shunt tube screens. The openhole section was 277 ft, deviated from 85 to 90°. The producing sand was normally pressured. The drill-in fluid and gravel-pack carrier/filter-cake removal fluid selection was based upon extensive laboratory testing consisting of cleanup, compatibility, and sand-suspension-capability tests. A reservoir drill-in fluid comprising brine, starch, biopolymer, and sized calcium carbonate was chosen for the project. A viscoelastic surfactant (VES) fluid in a chelating agent solution (CAS) containing an enzyme breaker to simultaneously attack both the starch and CaCO3 components of the filter cake was identified as the best carrier fluid for the gravel pack. Laboratory test results, field procedures, and production results are discussed in detail, along with the decision process that resulted in the selected drilling and completion plan.
Coiled-Tubing Failure Statistics Used To Develop CT Performance Indicators
Authors: van Adrichem Willem P. , Aslak Larsen Henrik
Published: December 2007

Coiled-tubing (CT) failures have not disappeared with a greater understanding of low-cycle fatigue in the industry. A comprehensive process to systematically analyze CT field failures has been in place since 1995. This paper describes the systematic failure-analysis process and the resulting CT failure database, which now includes more than 360 CT failures. The information reported here covers from 1995 to 2001 during a major service company's global CT operations.

The failure analysis delivers two types of statistics—the mode of failure during the event (failure mechanism) and the cause that led to it (failure cause). The failure trends for both mechanism and cause are discussed.

The CT volume used during these operations, in combination with the accumulated failures, allows for the introduction and discussion of CT performance indicators (CTPIs) that can be considered representative for the industry.
Oil/Water Separation by Induced-Air Flotation
Authors: Sylvester Nicholas D. , Byeseda John J.
Published: December 2007

The separation of oil, stabilized with an oil-soluble petroleum sulfonate, from brine solutions by induced-air flotation was studied in a continuous-flow pilot unit. The effects of inlet oil concentration, vessel residence time, air flow rate, bubble diameter, oil drop diameter, temperature, NaCl concentration, and cationic polyelectrolyte concentration were investigated. Oil drop and air bubble diameters, liquid residence time, and concentration of cationic polyelectrolyte were the most significant variables affecting overall flotation performance. Only drops larger than 2μm showed significant removal, while smaller drops were generated by the air-inducing rotor. The cationic polyelectrolyte improved flotation performance by increasing the number of large oil drops.

The removal rate for each oil drop size was first order with respect to oil drop concentration, and an experimental procedure permitting determination of the first-order rate constants for removal only due to bubble/drop interactions was developed. The oil drop and air bubble diameters were the only variables which affected these rate constants. Inceasing oil drop diameter and decreasing bubble diameter increased the rate constants. Comparison of the experimental and theoretically predicted rate constants showed that the mechanism of oil-droplet removal by bubbles from 0.2- to 0.7-mm is one of hydrodynamic capture in the wake behind the rising bubbles.
Perforating Unconsolidated Sands: An Experimental and Theoretical Investigation
Authors: Walton Ian C. , Atwood David C. , Halleck Phillip M. , Bianco Luis C. B.
Published: December 2007

This paper describes the experiments and modeling undertaken to develop a perforating strategy for unconsolidated sand formations. The experimental program consists of single-shot perforations in cylindrical samples of three sizes (4-, 7-, and 10.5-in. diameters) of unconsolidated sand saturated with kerosene at residual brine saturation and placed under a high effective stress in a pressure vessel. The amount of sand produced during perforating, as well as that produced during post-shot flow, is measured, and a video probe is used to observe post-shot sand production. Computerized tomography (CT) scan equipment is used to map the geometry of the cavity. The sand features behind the casing are examined and interpreted, providing essential insights into the interaction of the charge with the sand sample. A theoretical model of the failure mode of unconsolidated sands has been developed that supports the observations.

The main results so far from this study are as follows.

Perforating does not generate a tunnel in unconsolidated sands. The intense pressures set up by shaped-charge penetration in the weak sand sample fluidize it and cause the initial tunnel to collapse. Production flow creates a dilated zone around the tunnel entrance. At a critical flow rate, a large volume of sand is produced and the sample collapses. This occurs when flowing out of a hole in an unperforated sample as well.

The implications of these results for future work and for field applications are also addressed here.
Mankind's Stake in Middle East Oil
Authors: Jennings B. Brewster
Published: December 2007

To set the stage for discussing Middle East oil, let us review a few of the more important aspects of the world petroleum picture.

The Free World, outside the Iron Curtain, produced and used nearly 16 million B/D of petroleum last year. More than half of it, 57 per cent to be exact, was consumed in the United States. Free Europe used about a third as much as we did, or about a sixth of the total.

Big as oil consumption is today, it will soon be much larger. How big, how soon, is difficult to say because no reputable oil economist has ever yet made a long-range forecast of oil demand that was as high as consumption subsequently proved to be. There are a few straws in the wind which can be pointed out, however. Over the past five years demand in the United States has grown at the rate of about 5 per cent a year. In Europe during the same period demand has risen 12 per cent annually. Increases in oil use have been still faster in less developed countries. Last year's oil consumption in the Free World as a whole was double what it was only nine or 10 years ago. Whether such rates of growth continue, accelerate, or even slow down a little, it seems reasonable to expect that sometime between 1965 and 1975 if not sooner the Free World will need twice as much oil as it is using today.

Sources of More Oil

Where are we going to get it? Last year's oil production came primarily from the United States. Production in the United States, while less than our consumption, came to 48 per cent of the Free World's total. The Middle East supplied 23 per cent and Venezuela 17. Can we count on a continuance of supply in those proportions from those sources?

A look at the rates at which the various producing countries are drawing on their oil "bank accounts" may help us answer that question. United States petroleum production last year amounted to 8.1 per cent of our domestic proved reserves, and Venezuelan production was 6.8 per cent of its reserves. But Middle East production was only 1.3 per cent of Middle East reserves.

Obviously, the principal Western Hemisphere sources of oil the United States and Venezuela are being drawn on five to seven times as fast as those of the Middle East.

The United States, with roughly 20 per cent of the world's reserves, produces nearly 50 per cent of the world's oil output and consumes nearly 60 per cent. Overlooking the possibilities of getting oil from shale or tar sands, the facts suggest that if present trends persist, the Western Hemisphere will run out of oil before the Eastern Hemisphere does. This statement concerns only proved oil reserves. How about the chances of finding more oil?
Analyses of an Elmworth Hydraulic Fracture in Alberta
Authors: Wyman R.E. , Holditch S.A. , Randolph P.L.
Published: December 2007

A tight gas sand with 1-µd permeability was produced, after a large hydraulic foam fracture, at rates close to predicted values. The rates of about 300 Mcf/D (8495m3/d) after 23 days would not bear the cost of development at 1979 Canadian prices. However, it is estimated that, with higher netbacks and longer fractures, commercial development would be feasible.

Introduction

The Elmworth gas field is located within the Deep basin near Grande Prairie, Alberta (Fig. 1). The Deep basin covers about 26,000 sq miles and appears to contain an enormous amount of gas in different-quality rocks. Masters1 has estimated the Deep basin could contain more than 400 Tcf of gas, recoverable at various levels of price and technology.

Canadian Hunter visualizes the gas distribution in the Deep basin as a resource triangle. In such a distribution, the sands and conglomerates of highest porosity and permeability are at the very top of the triangle. As reservoir quality decreases, the resource triangle indicates larger and larger quantities of gas in lower-porosity and lower-permeability rocks. Near the bottom of the triangle are sands approaching 7% porosity and 1 µd in-situ permeability. Within these lower porosity rocks (7 to 11%) resides a huge ultimate potential. Detailed analyses were made of logs, cores, and tests of about 20 zones from 57 wells in a 60-township area around the Elmworth field. This study indicated that, with sufficient but reasonable economic incentives, it would be possible to recover more than 200 Tcf from the lower-quality rocks within the Deep basin.2

To obtain more information on the technology and economics required to recover this gas, Canadian Hunter performed a large hydraulic fracture over the Cretaceous Falher Zones A and B in the Canhunter Texcan Elmworth Well 11–12–71–13W6. This paper presents a description and analysis of the fracture.

Petrophysical Properties

The Falher Zones A and B were cored completely, and a full suite of openhole logs was run. This suite included the induction-electrical, acoustic with variable density display, compensated neutron-density, and microlog. Selected logs and the core analysis (made at atmospheric conditions) are shown in Fig. 2. Although the entire cross section of 164 ft is considered gas-bearing, less than one-half of the section is estimated to be net pay, based on analysis of logs, cores, and pressure buildups. Sixty-six feet of this section have measured core porosities equal to or above 7%; this is shown by the shaded area on the porosity curve in Fig. 2. Permeabilities above 0.1 md also are shaded. Sonic log and pressure buildup analysis indicate a net pay closer to 45 ft. The relation between fractional core porosities (f) measured at 200 psi and sonic travel time (?t) in µs/ft is described byf=0.0054?t-0.2865.
Development and Testing of Two-Phase Relative Permeability Predictors Using Artificial Neural Networks
Authors: Silpngarmlers N. , Guler B. , Ertekin T. , Grader A. S.
Published: December 2007

In this paper, we report liquid/liquid and liquid/gas two-phase relative permeability predictors that are developed using artificial neural networks (ANNs). In the development stage, some of the relative permeability data from literature are used during the training stage while some other sets are preserved to test the prediction capabilities of the models. Various rock and fluid properties, including endpoint saturations, porosity, permeability, viscosity and interfacial tension, and some functional links (mathematical groups coupling various rock and fluid properties) constitute the input parameters of the models. The models are found to successfully predict the field and experimental relative permeability data.
Characterizing Disproportionate Permeability Reduction Using Synchrotron X-Ray Computed Microtomography
Authors: Seright R.S. , Liang J. , Lindquist W. Brent , Dunsmuir John H.
Published: December 2007

X-ray computed microtomography was used to investigate why gels reduce permeability to water more than that to oil in strongly water-wet Berea sandstone and in an oil-wet porous polyethylene core. Although the two porous media had very different porosities (22% vs. 40%), the distributions of pore sizes and aspect ratios were similar. A Cr(III)-acetate-HPAM gel caused comparable oil and water permeability reductions in both porous media. In both cores, the gel reduced permeability to water by a factor 80 to 90 times more than that to oil. However, the distributions of water and oil saturations (vs. pore size) were substantially different before, during, and after gel placement. This paper examines the mechanism for the disproportionate permeability reduction in the two porous media.
Fine-Scale Simulation of Complex Water Encroachment in a Large Carbonate Reservoir in Saudi Arabia
Authors: Pavlas Emmerick Joe
Published: December 2007

Reservoir simulation has entered a new era with the advent of massively parallel processing (MPP) and its ability to handle millions of cells. In this study, a simulation model was constructed from a geologic model without scaleup, with the resulting model having 1.38 million cells. The majority of the effort in reservoir simulation was spent on reviewing geologic and engineering data. History-match changes were made at the well level and interpolated in kH and kV arrays with a deterministic mapping routine. Despite the complexity, the model size, and 30 years of history, a successful history match was achieved after 40 runs. The model has been used to identify well locations for bypassed oil recovery. To date, these locations have not been drilled.
A Field Comparison of Wet and Dry Combustion
Authors: Joseph C. , Pusch W.H.
Published: December 2007

The injection of water during an in-situ combustion process has been shown with laboratory studies to be more efficient than dry combustion. This paper substantiates the superiority of wet combustion over dry burning with field data from the Bodcau in-situ combustion project in Bossier Parish, LA.

Introduction

Cities Service Co. operates an in-situ combustion project in the Bellevue field of Bossier Parish, LA (Fig. 1). The field was discovered in 1921 and covers approximately 900 acres (3.64 km2). Production is from the Upper Cretaceous Nacatoch sand occuring between 300 and 400 R (91 and 122 m). Porosity and permeability of the unconsolidated reservoir average 33.9% and 700 md, respectively. The 19 degrees API (931-kg/m3) gravity crude has a viscosity of 676 cp (0.68 Pas) at the reservoir temperature of 75 degrees F (24 degrees C). Due to the low reservoir pressure and high viscosity of the oil at reservoir temperature, typical producing rates are 1 or 2 BOPD (0.16 to 0.32 m3/d) per well. Reservoir properties are summarized in Table 1.Dry forward combustion was tested by Cities Service in a pilot started in 1971. Other production stimulation techniques had been tried in the field, but none were economically successful. Production from the four 2.5-acre (10 117-m2) inverted nine-spot patterns during the 3-year combustion phase was in excess of 167,000 bbl (26 550 m3). The pilot area is still under waterflood, and ultimate recovery will exceed 40% of the original oil in place. Although the pilot test demonstrated that dry combustion could recover the low-gravity crude economically, laboratory studies indicated that wet combustion would be superior to dry combustion in the Bellevue field. To compare the two combustion processes directly, a field test was begun in 1974.Successful results from the field test led to the development of eight additional patterns using wet combustion, including five operating under a contract with the U.S. DOE. The DOE project demonstrates the technical efficiency and economics of a commercial combustion project. Eight more patterns have been drilled and presently are being developed, while additional acreage is being prepared for future fireflooding operations (Fig. 2).

Description of Test Area

Two 2.5-acre (10 117-m2) inverted nine-spot patterns were developed as shown in Fig. 3. Pattern 6 was to be processed by dry combustion, while Pattern 5 would make use of a type of wet combustion specifically designed for this reservoir. To monitor the progress of the combustion and water fronts, 18 temperature observation wells were drilled within two patterns.Producing wells were completed with 7-in. casing cemented to surface. The entire pay interval was perforated at a density of two hots per foot, and the wells were equipped for beam pumping. Injection wells also were completed with 7-in. (18-cm) casing, but only the bottom 15 ft (4.6 m) of pay were perforated for air injection.

JPT

P. 1523^
Advanced Slip-Crushing Considerations for Deepwater Drilling
Authors: Sathuvalli U. B. , Payne M. L. , Suryanarayana P. V. , Shepard J.
Published: December 2007

This paper addresses a problem pertinent to the design of landing strings and drillstrings for deepwater operations. These landing strings are designed to run long and heavy casings, tiebacks, or liners (typically deep intermediate and production tubulars), and the total weight may approach or exceed 1,000 kilo lbf (klbf) at the mudline. Adding the weight of the landing string to the rotary results in a serious design problem regarding both the landing string itself and the handling equipment. Slip-based handling systems work well in most instances but lead to biaxial loading from the tensile and radial loads exerted by slip inserts. As a result of biaxial loads, the axial load rating of the landing string is reduced.

The current understanding of slip-crushing phenomena is based on testing and modeling work dating to 1959 by Reinhold and Spiri1 and Vreeland.2 This paper assembles all available data regarding slip crushing and places it in the perspective of current understanding. A secondary aim is to describe the physics of the slip-drillpipe interaction in some detail (i.e., extend the Reinhold-Spiri analysis1 to the next level).

The analysis presented in this paper shows variations between the historical Reinhold-Spiri model and test results, and it indicates an unconservative margin of ~20%. These trends can be accounted for with a more accurate model of slip-crushing mechanics. The improved model supports a nonlinear stress distribution in the pipe, and its prediction of peak stresses is consistent with general test observations. With better quantification of the friction factors between the slip and the bowl, load uniformity, and equipment tolerancing and fits, this new model and its underlying approach provide an appropriate framework for a more accurate tubular rating for slip-crushing performance. Until such time as these refinements are made and available, drilling personnel should consider and implement appropriate safety factors when dealing with marginal designs for slip-crushing scenarios.
Controlling Numerical Dispersion by Variably Timed Flux Updating in One Dimension
Authors: Larson R. G.
Published: December 2007

The one-dimensional (1D) material balance equations for multiphase, multicomponent transport in porous media can be cast into forms, analogous to characteristic equations, that express explicitly the velocities at which fixed values of concentration are propagated. Use of these concentration-velocity equations to control the frequency with which component fluxes from finite-difference gridblocks are updated leads to greatly reduced numerical dispersion, as demonstrated in miscible flooding, waterflooding, surfactant flooding, and other example problems.
Processing and Interpretation of Long-Term Data Acquired From Permanent Pressure Gauges
Authors: Athichanagorn Suwat , Horne Roland N. , Kikani Jitendra
Published: December 2007

Long-term data from permanent gauges have the potential to provide more information about a reservoir than data from traditional pressure-transient tests that last for a relatively small duration. Besides reducing ambiguity and uncertainties in the interpretation, long-term data also provide an insight on how reservoir properties may change as the reservoir is produced. This study developed a multistep procedure for the processing and interpretation of long-term pressure data. The procedure was tested with several sets of simulated and actual field data. It was found to be an effective approach for the analysis of long-term pressure data from permanent gauges.
Analysis of Interference Test Data Influenced by Wellbore Storage and Skin at the Flowing Well
Authors: Chu Wei Chun , Garcia-Rivera J. , Rajagopoal Raghavan
Published: December 2007

This paper presents new solutions for analyzing interference test data affected by wellbore storage and skin effects at the flowing well. Three parameters of interest - wellbore storage phenomenon, skin effects, and distance between two wells - are considered simultaneously. The new type curves should improve significantly the ability to analyze such data.

Introduction

With the advent of sensitive pressure gauges and because of the need to obtain precise information on reservoir heterogeneity for implementation of tertiary recovery programs, interference tests have become popular. It is well-established that the results of a multiwell test are influenced more by reservoir heterogeneity than those of a single-well test. The line source solution presented first by Theis1 serves as a starting point for the analysis of interference test data. This solution assumes that the storage capacity of the flowing well and the skin region around the sand-face have a negligible effect on the observation-well response. This assumption is valid if the distance between the flowing well and the observation well is large. However, if the distance is small, then the effect of storage and skin on the observation-well response can be significant. The pressure response at any point in the reservoir will be damped and delayed as a result of the storage effect at the active well (with or without the skin effect), because the main effect of the storage capacity of the flowing well is to cause a lag in the time required for the surface rate to equal the sand-face rate. For given reservoir properties, the magnitude of the delay depends on the wellbore volume, the nature of the storage phenomenon, and the skin effect.

To our knowledge, the effect of wellbore storage on interference data was examined first in the groundwater hydrology literature.2,3 In petroleum engineering literature, Prats and Scott4 were the first to consider the effect of wellbore storage on the response of a pulse test. They concluded that the porosity-compressibility product, fct, of the formation would be overestimated and the hydraulic diffusivity, k/fctµ, would be underestimated if the wellbore storage effect was significant and not considered in the data analysis. Also, they noted that care should be taken in measuring pressure data if the wellbore storage effect was significant, because the magnitude of the actual pressure response would be lower than expected.

They did not quantify the effect of a skin region around the well but did discuss qualitatively the influence of the skin factor. However, Prats and Scott assumed that the storage effect existed at the observation well and not the flowing well. In a subsequent paper, we show that their results can be used to analyze pulse test data influenced by the storage effect at the active well.
Aconcagua, Camden Hills, and King's Peak Fields, Gulf of Mexico, Employ Intelligent Completion Technology in Unique Field-Development Scenario
Authors: Jackson Nielsen Victoria B. , Piedras Jose , Stimatz Gregory P. , Webb Tamara R.
Published: December 2007

The economic success of deepwater and ultradeepwater developments often depends on the use of innovative technologies that can increase production and minimize workover needs to achieve the sought-after field efficiency during the productive life of the field. Intelligent completion technology, a new concept for the oil field, is one of the technologies that can support these needs. This well-completion concept allows the operator to obtain real-time or near-real-time reservoir data, then reconfig. the wellbore production/ injection architecture to adapt to the information obtained.

Along with pipeline, platform, and subsea system synergies, three fields in the Gulf of Mexico—Aconcagua, Camden Hills, and King's Peak—use intelligent completion technology to optimize a marginal reserve base. Located in Mississippi Canyon Blocks 173, 217, 305, and 348 and Desoto Canyon Blocks 133 and 177 in 6,200 to 7,200 ft of water, the three fields’ production will be tied to the Canyon Station host platform, 55 miles from the most distant well location.
Producing Viscous Fluids
Authors: Lebourgeois Guy
Published: December 2007

The discovery in March, 1946, of the Boscan low gravity-high viscosity crude oil accumulation presented the Richmond Exploration Co. with a multitude of problems almost unique in the industry.

Solution of these problems through experience and cut-and-try methods has resulted in the successful development of a large source of rod-building materials.

Introduction

Among the oil companies operating in Venezuela, to which heavy crude means some 14° to 15° API gravity oil, the name Boscan has practically become a synonym of "viscous fluid." Indeed, Boscan crude has an average 10° API gravity fluctuating from 9° to 12° and an average viscosity of 26,000 SSU at 122°F fluctuating from 17,000 to 50,000 SSU. This asphalt-looking oil has to be pumped out of the ground, shipped 25 miles away and loaded on tankers.

When the Boscan field was discovered, the technical obstacles brought up by the physical characteristics of its crude made questionable the commercial exploitation of a petroleum so difficult to produce. However, three years later, Richmond was shipping 14,000 B/D of Boscan crude. Even if the figure does not seem impressive, it means the practical answers to a large sequence of major production problems which had to be solved within the rates of the available equipment through constantly improving methods and designs. The drilling of a Boscan well is not a difficult task; it is when the rig is removed that obstacles start arising.

Geology

The Boscan field is located 26 miles southwest of Maracaibo in the State of Zulia in the western part of the Maracaibo basin.

The stratigraphic sequence encountered in and above the production section in the Boscan area includes Eocene, Oligocene, Miocene and Pliocene sediments. The Upper Eocene consists of the Las Flores formation with interbedded sands and dark gray carbonaceous shales. In the upper part, two zones of beach and bar sands (designated as Upper Boscan and Lower Boscan) produce heavy oil.

The Lower Oligocene overlies the Eocene and contains poor to well developed beach sands interbedded with light gray sandy claystone. Effectively permeable sands in this formation (designated Basal Icotea) locally are oil productive. The middle of Oligocene, principally claystone, contains thin sands which are oil productive in the eastern part of the field. This is Middle Icotea.
Reservoir Oil Resaturation with Gas During Pressure Build-up
Authors: Cheney M.G.
Published: December 2007

A sand-packed cell was used to determine the pressure-volume relationship of confined oil and gas by applying both increasing and decreasing pressures. Then the same hydrocarbon fluid was given a routine PV analysis over the same pressure and temperature ranges. The relationship between pressure and hydrocarbon volumes proved to be practically the same for all runs. Equilibrium conditions between phases were very rapidly established within the sand-packed cell.

A small, closed reservoir was produced until free gas developed in the oil leg; then the reservoir was gas-injected to restore a third of the pressure decline. By volumetric balance considerations it was indicated that as the pressure was raised the oil dissolved gas; and within experimental error, the gas maintained the oil saturated.

It was concluded that for both the laboratory and reservoir tests, the dispersed gas in the oil maintained the oil saturated during pressure increase.

Introduction

In Eastern Venezuela, the question of resaturation of reservoir oil in the oil leg through pressure build-up has often arisen. Should oil leg resaturation take place, increased effective permeability will develop with increasing pressure. Decreased viscosity and increased oil formation volume factor from increased solution of gas in oil, would lead to reduced residual oil. These benefits would be reflected in increased ultimate recovery and improved well productivity. However, they could be limited, e.g., active water or solution gas drives. In the case of water drive, loss by backflow of oil into the water leg might result from pressure build-up. With an active solution gas drive that has led to a relatively high free gas saturation, to attain equal reservoir volumes of residual oil through gas injection, higher abandonment gas:oil ratios are necessary at higher pressures. The cost of handling greater volumes of gas could outweigh the advantages of an increased formation volume factor associated with a higher pressure. There are a number of conflicting articles (pro and con) in the literature concerning resaturation.
Streamline-Based Production Data Integration With Gravity and Changing Field Conditions
Authors: He Zhong , Yoon Seongsik , Datta-Gupta Akhil
Published: December 2007

Recently, streamline-based flow simulation models have offered significant potential in integrating dynamic data into high-resolution reservoir models. A unique feature of the streamline-based production data integration has been the concept of a travel-time match that is analogous to seismic tomography, allowing the use of efficient and proven techniques from geophysics. In this paper, we propose a generalized travel-time inversion method for production data integration that is particularly well-suited for large-scale field applications with gravity and changing conditions. Instead of matching the production data directly, we minimize a travel-time shift derived by maximizing a cross-correlation between the observed and computed production response at each well. There are several advantages of our proposed method. First, it is general and extremely computationally efficient. The travel-time sensitivities can be computed analytically with a single forward streamline simulation that can be much faster than a conventional reservoir simulator. Second, it is robust and the minimization is relatively insensitive to the choice of the initial model. Finally, it is field-proven because we utilize established techniques from geophysical inverse theory.

We demonstrate the power and utility of our proposed method using synthetic and field examples. The synthetic examples include a large-scale 3D example with a quarter-million grid cells involving infill drilling and pattern conversions. The field example is from the Goldsmith San Andres Unit (GSAU) in West Texas and includes multiple patterns with 11 injectors and 31 producers. Starting with a reservoir model based on well-log and seismic data, we integrate water-cut history for 20 years in less than 2 hours on a PC.
Application of Statistics to the Analysis of Production Decline Data
Authors: Chatas A.T. , Yankie W.W.
Published: December 2007

Introduction

The appraisal of an oil lease may often be made through production decline analysis, which requires description of the functional relationship between the oil production rate and either cumulative production or time. Heretofore, attempts to define the function appropriate to a given set of production data have depended to some extent on subjective procedures. The purpose here is to introduce an objective solution, obtained by combining the principle of least squares with the theory of equations.
Cupiagua: Modeling of a Complex Fractured Reservoir Using Compositional Upscaling
Authors: Ballin P. R. , Clifford P. J. , Christie M. A.
Published: December 2007

The first application of compositional upscaling to the routine modeling of a major reservoir is described. The reservoir— Cupiagua, in Colombia—is a rich gas condensate field. Given that Cupiagua falls rapidly below dewpoint and produced gas is recycled, the main recovery process is the vaporization of liquid components into the gas phase, in which they are transported to producers. Therefore, the process is compositional, but flow is dominantly in one phase.

Cupiagua is a heterogeneous reservoir dominated by natural fracture corridors that provide more than 80% of the permeability in some areas. It is not possible to represent these features explicitly within the full-field model (FFM), nor do they fit a conventional dual-porosity representation. Therefore, an upscaling process is required.

The process described is the use of alpha-factor compositional upscaling functions, which modify the velocities of individual pseudocomponents. We show how fine-grid cross-section modeling, with a range of sensitivities, may be used to generate an appropriate set of alpha-factor functions, which are validated against detailed sector models and may then be used as the principal history-match parameter in the FFM.
Whole-Core Analysis Methods and Interpretation of Data from Carbonate Reservoirs
Authors: Bynum R.S. , Koepf E.H.
Published: December 2007

Introduction

During recent years reservoirs where the hydrocarbon storage capacity and the permeability characteristics are due chiefly to fractures and vugs, and tight formations with non-homogeneous porosity development, have become of major importance in West Texas oil production. Diamond coring equipment and methods were devised which permitted excellent recovery of cores from these formations. Examination of these cores with erratic porosity development frequently indicated individual fracture or vug volume greater than the "perm-plug" sample normally used in conventional analysis. It is evident that actual reservoir properties are more closely approached in the sample as the sample size is increased and that the entire core from this type of formation should be analyzed.

Although the literature on general whole-core analysis procedures has been rather limited many innovations have been introduced, both in methods of analysis and in the interpretation and application of the data. The experienced core analyst has determined a set of optimum conditions which permit a confident approach to his specialized work. These optimum conditions include a completely cored interval, beginning several feet above the pay zone, cut with large diameter coring equipment at maximum speed in a properly selected drilling fluid, pulled to the derrick floor in minimum time, described and logged by an experienced man, properly preserved by quick-freezing in dry ice or by sealing in plastic or other suitable means, and delivered immediately to a well-equipped laboratory where the tests are made on maximum-sized samples. Current coring equipment and practices permit a close approach to these optimum conditions.

Coring and Sampling of Core

Although the successful application of the diamond bit was a great step forward in the coring of dense carbonate reservoirs, there still is no means available to recover a sample of the reservoir in an undisturbed condition. Normally, the drilling mud filtrate flushes the core to an irreducible oil saturation. As the core is brought to the surface, the gas in solution in this residual oil is evolved, expands and expels oil and water until liquid saturations are reduced to the point where only gas will flow. The core, as recovered at the surface, then, contains residual oil after water flushing and solution gas drive, some original water and some mud filtrate, and solution gas from the oil. There appears to be a relationship between the formation volume factor of the oil and the efficiency of liquid expulsion by the gas as it expands with pressure reduction.
Quality Assurance Tool for PVT Simulator Predictions
Authors: Varotsis N. , Gaganis V. , Nighswander J.
Published: December 2007

The currently available pressure/volume/temperature (PVT) simulators predict the physical properties of reservoir fluids with varying degrees of accuracy depending on the type of model used, the nature of the fluid, and the prevailing conditions. Nevertheless, they all exhibit the significant drawback of lacking the ability to estimate the quality of their answers.

Artificial Neural Networks (ANNs) trained by large PVT databases are increasingly used to provide accurate predictions of physical properties mainly because of their ability to learn from experience. The use of such models offers the unique capability of estimating the quality of their predictions, as the degree of competence can be evaluated for each unknown test case. The accuracy of the ANN-based PVT simulators depends heavily on the density of the database compositional mapping around the coordinates of the unknown reservoir fluid. Unknown test cases found outside the available training space may lead to poor predictions.

In this work, a quality assurance tool is presented that is integrated to the PVT Expert,* which is an ANN-based PVT properties prediction model. In the case of an unknown fluid, this tool qualifies the predictions of the PVT simulator based on the evaluation of the affinity of the test case with the training data sets contained in the database used. Subsequently, the competence with which the ANN model has learned the general trend in the area around any new test case is assessed numerically through the development of one ANN sextuple model per property. Finally, the use of the average predicted value eliminates the risk of considerable deviations.

This innovative approach was tested successfully against a large set of studies unseen by the ANN model. The ability to provide confidence for the accuracy of the PVT predictions and to assess their quality significantly upgrades the applicability of the PVT simulator as a valuable reservoir management tool.
Modeling In-Situ Scale Deposition: The Impact of Reservoir and Well Geometries and Kinetic Reaction Rates
Authors: Mackay E. J.
Published: December 2007

Previous work has demonstrated how and where the mixing of incompatible brines occurs in waterflooded reservoirs and what the impact on scale prevention strategies is in terms of timing and placing squeeze treatments. This paper extends this work by modeling the resulting in-situ deposition process. The location of maximum scale deposition and the resulting brine compositions at the production well are calculated for a range of sensitivities, including reservoir geometry (1D, 2D areal and vertical, and 3D), well geometry (location and orientation within the field and with respect to other wells and the aquifer), and the reaction rate (ranging from no precipitation to equilibrium).

In conventional systems with no aquifer, it is demonstrated that maximum scale deposition occurs in the immediate vicinity of the production wellbore; therefore, low produced-cation concentrations indicate inadequate squeeze treatments. In systems in which water injection is into the aquifer, low cation concentrations may also result from deposition deeper within the reservoir. Maximum scale dropout still occurs as the fluids approach the production well but is sufficiently far from the wellbore to be unaffected by squeeze treatments or to have any major impact on productivity. The reaction rate is critical in determining the amount of scale deposition; however, even under equilibrium conditions, sufficient concentrations of scaling ions are delivered to the production well to necessitate squeezing it but with lower inhibitor volumes. Once cation concentrations have been reduced, it is predicted that they will never increase again.

This paper also discusses some of the limitations of modeling such systems, including determination of kinetic reaction rates, mixing zone size, and impact on permeability. Although the thermodynamics are fairly well understood, the kinetics are much more difficult. The size of the mixing zone is affected by numerical dispersion, and computationally intensive techniques are required to overcome this problem. Previous experience shows that formation damage factors are very difficult to extrapolate from coreflood data because there is a great difference between the dimensions of the mixing zone in the reservoir and the core plug.
New Calibration and Conversion Techniques for Radioactivity Logs
Authors: Mercier V.J. , Redford W.H.
Published: December 2007

A new approach to an old problem has made it possible to analyze and quantitatively evaluate a radio-activity log in a relatively short time, whereas in the past it was necessary to calculate and plot a "neutron-derived porosity curve" then transpose that information to other logs.

The new calibration technique is discussed and introduces the terms "radiation units", "environmental units" and "well strata index". The application of these units to each radioactivity log, regardless of detector type, source spacing or well condition, is explained and illustrated.

Neutron curve conversion charts are introduced. The accompanying charts provide a means for comparing neutron curve responses obtained under empty or liquid-filled openhole (uncased borehole) conditions, in borehole ranging from 4 to 9 in. in diameter, with several types of neutron logging instruments operated at various source to detector spacings.

Given the neutron curve response under one set of borehole conditions the charts may be used to determine the response which would be obtained in similar rock under a different set of borehole conditions. In this way the neutron curve of a given well may be converted to obtain the curve which would have resulted had the borehole conditions been altered. Similarly, several neutron curves obtained under different well conditions may be converted to a common basis to determine whether or not certain formations observed in the several wells are alike.
Two-Phase Flow Performance for Electrical Submersible Pump Stages
Authors: Pessoa Rui , Prado Mauricio
Published: December 2007

Two-phase flow behavior prediction for centrifugal pumps is a difficult task because of the complexity involved in modeling multiphase flow inside turbo machines. An experimental study has been conducted at the U. of Tulsa Artificial Lift Projects (TUALP) with a 513-series, 22-stage, mixed-flow-type pump to gather data for pump performance under two-phase flow conditions. Air and water were used as the working fluids. This study differs from other experimental works because the pressure changes were recorded stage by stage. The results of previous works have been reported as an average of the intake and discharge conditions and depend on the number of stages used.

Phenomena such as surging and gas locking were observed during these tests, and their boundaries have been mapped.

The pressure increment and total hydraulic horsepower for the average pump, those per stage as a function of the liquid flow rate, and each gas flow rate considered are presented. The pump's average brake horsepower and efficiency also are plotted for the variables mentioned.

The results indicate that average pump behavior is significantly different from that observed per stage.