bluuebunny/crossref_metadata_2025 huggingface dataset:
Performance Predictions on Low Permeability Gas Wells
Authors: Mullins J.R.
Published: December 2007

Frequently it becomes necessary for the reservoir engineer to predict the stabilized deliverability of a gas well with a minimum predict the stabilized deliverability of a gas well with a minimum of test and production data. Usually this must be done with limited test data obtained by venting the gas to the atmosphere. The pipeline may not be available, since the purpose of the test and the production forecast may be to justify the installation of the pipeline. Although venting does not degrade the quality of the test, it does frequently reduce the quantity of test data obtained. Since sizeable expenditures for pipeline installation and development drilling, or conversely, the abandonment of a structure, may be influenced by the well's predicted performance, it is essential the most accurate prediction possible be made with the data available. However, when conditions permit, the more desirable test, a prolonged drawdown into the pipeline followed by a pressure buildup test, should be conducted.

It will be shown that the typical short term one-point flow test taken on a well completed in a tight reservoir will indicate deliverabilities which are greatly exaggerated. Many wells in the Mid-Continent Area give indications of requiring several months to stabilize or reach simi-steady state flow conditions. A test of such duration is usually impractical. Frequently, time in addition to the cost preclude such a test. It, therefore, becomes necessary to obtain a reasonably accurate forecast in the absence of extensive field test data. It is the purpose of this paper to present a practical method of obtaining a reliable forecast.
Energy and the U. S. Economy
Authors: Cleary William B.
Published: December 2007

We've heard a great deal lately about the energy gap and the forthcoming energy crisis. Such a crisis is simply inconceivable to most of us who have lived all our lives with abundant supplies of cheap energy, but time has a way of rendering many established concepts obsolete. Imagine what our reaction would have been had the President of the United States said in 1956, one year prior to Sputnik, "We are going to place a man on the moon in the next decade." We would hurriedly have checked the Vice President's health. Yet in 1960, only three years after Sputnik, our President made such a statement and although President made such a statement and although it was received skeptically at the time, it was in fact fulfilled within the decade.

How could we possibly have an energy crisis? A few days ago I saw regular gasoline being advertised at 24.9 cents at a local station and remembered that I had paid more for it twenty five years ago. If we're short of oil, why doesn't gasoline cost more?, -bottled drinking water in New York City is considerably more expensive. I read recently that the Potential Gas Committee says we have well over 11 hundred trillion cubic feet of potential gas reserves in this country, we only use 22 trillion a year,-so how could we possibly have a shortage of natural gas? If we are supposedly short of crude, why did the state of Texas reduce its daily allowable this fall apparently allowing its wells to produce only 64% of the time. These are all logical questions and they are asked frequently by consumers of natural gas and oil.

The sad fact is that we do have an energy gap and we are approaching an energy crisis of major proportions. It's perhaps the most serious crisis that this nation has yet faced. Can we solve it?, - I think we can and I plan to outline for you a few of the steps that this nation must take to protect and insure adequate energy for its future. One of the most difficult parts of this solution will not be concerned with the technical or political problems but rather with the communications problem, -the elimination of the credibility gap.

In order to come up with reasonable solutions, let's look first at the problem. It would appear that the energy gap we are facing in the United States is the direct result of having no national energy policy. The problem has been aggravated by sex and by affluence. The part that sex plays of course, has to do with the population growth. Fifty years ago there were 100 million people in this country. Now there are over 200 million. By 1980, and reproduction is expected to boost us to over 240 million. Where does affluence come in? In 1950, each of our inhabitants used an amount of energy equal to 39 barrels of oil per year.
Understanding Foamy Oil Mechanisms for Heavy Oil Reservoirs During Primary Production
Authors: Huerta M. , Otero C. , Rico A. , Jimenez I. , de Mirabal M. , Rojas G.
Published: December 2007

A set of experiments in porous media was performed to determine oil recovery factor during natural depletion for a heavy oil reservoir. Results on "critical or mobile" gas saturation, produced fluid characterization, residual oil saturation, production profile and effective viscosity versus pressure are presented.

In order to characterize the ability of the heavy oil to trap the released gas, conventional and non conventional PVT tests were carried out.

By comparing the experimental results during differential liberation tests, a gas trapping factor for the oil was obtained. It accounts for the amount of solution gas that has been thermodynamically released but does not form instantaneously a free gas cap.

The so called pseudo-bubble pressure was obtained. In this work the hypothesis involved in the "Low Viscosity Model" was also tested.

Introduction

During the last years it has been a very large discussion about different production mechanisms to explain the production behavior observed in some heavy crude oil reservoirs specially in the Orinoco Belt in Venezuela and Lloydminster in Canada.

It has been characterized by high production rates and/or high primary oil recovery, besides a good pressure maintenance.

In the past, we have evaluated other drive mechanisms such as compaction, water drive and thermal process.

A considerable amount of laboratory and field work has been done to evaluate compaction effects in the area of our interest.

The results obtained from that study showed no evidence of subsidence or compaction, therefore it is not likely to be a major production mechanism. On the other hand, no active aquifer has been found either.

According to field (well head samples) and laboratory evidence, the heavy and extra heavy Hamaca oil exhibits "foaminess" when produced under solution gas drive. P. 671
Technical Advances Applied to Downhole DST Equipment Efficiently Solve Difficult Testing Problems (Pumping Wells, HPHT Wells, etc...)
Authors: Bouroumeau P. , Parra L. , Petel P.
Published: December 2007

The paper presents two technical advances applied to downhole DST equipment: Surface Read Out (SRO) with Wireless Transmited Data (WTD) where pressure/temperature measurements are received in real-time, using electro-magnetic transmission through the formation.High temperature DST string and memory gauges.

A test program was carried out with WTD in the Middle-East, where it was important to get pressure data in real-time during the test. Due to the presence of an ESP to flow the well, the selected solution was a real-time pressure/temperature electro-magnetic transmission tool which gave very positive results for: monitoring the complete operation.obtaining accurate data in real-time.optimizing the test program and the duration of the test.

The second part of the paper describes technical advances applied to components of the DST string and to the memory gauges.
Liquid Loading along the Completed Section of Horizontal and Inclined Wells may govern Inflow Performance
Authors: Asheim Harald , Oudeman Piet
Published: December 2007

For single phase flow, it is commonly accepted that wall friction along the completed wellbore may reduce inflow performance. For two-phase flow, interface friction and resulting liquid loading are usually more important than wall friction and may govern inflow performance. The paper provides quantitative understanding of how liquid loading along the wellbore affects inflow performance. It shows that liquid loading can be reduced and inflow performance improved by proper completion design.

Introduction

Pressure drop due along the completed section of the wellbore may have significant impact on the overall inflow performance. Methods to predict and counteract detrimental effects of such pressure drop have been proposed by different authors. They all assume single phase flow.

In multi-phase flow, heavier and more viscous fluids tend to flow at lower velocity than lighter fluids. This causes interface friction and relative accumulation, loading, of the heavier fluid, which contributes to pressure drops along the completed wellbore. Where the flow velocity in the wellbore is low, as towards the well bottom, liquid loading may govern the pressure drop. It may therefore be suspected that the production of a second fluid will result in quite different inflow performance than predicted by single phase flow models. Laboratory experiments by Ihara and others did not identify principal differences. However, this may be due to their design of equipment and choice of experimental conditions.

The current paper considers analytic and numerical modelling of two-phase, steady-state inflow performance, accounting for pressure drop along the completed section of the wellbore. The problem can be quantified by combination of concepts already used for modelling of inflow to wellbores and tubular two-phase flow. However, liquid loading in the wellbore leads to unusual boundary conditions, that require special solution methods.

The solution method developed in the paper enables fast and mathematically accurate prediction of two phase inflow performance. This also shows that liquid loading along the completed section may govern inflow performance. However, proper well design reduces liquid loading and improves the effective inflow performance.

The Model

For notational convenience, a gas reservoir with associated liquid is considered below. However, the model may with minor modifications be applied to other immiscible fluids such as oil and water, or to fluid with solids.

Basic Assumptions and Relations

The inflow to the wellbore is assumed proportional to pressure drawdown. Thus, the gas inflow rate per unit length of completed wellbore is expressed as

(1)

The reservoir pressure, is assumed to be in static equilibrium.

P. 395
A method for using the naturally-occurring negative geoskin in the description of fluvial reservoirs
Authors: Corbett Patrick W.M. , Mesmari Abdallah , Stewart George
Published: December 2007

In well testing, an important corroboration of the interpretation can be made from integrated analysis of core and geological information. The kh product, skin, and flow regimes from the pressure data should all be consistent with the petrophysical data and the geological interpretation.

It has been observed that certain types of reservoirs show negative skin despite the absence of any natural or induced fractures. This skin has been interpreted as due to the presence of thin high (with respect to the matrix) permeability channels. These channels have the well testing signature normally associated with fractures and are termed "Pseudo-fracture channels" (PFC). The skin (negative) due to the limited extent of these features around the well bore, results from purely geological phenomena and is termed "geoskin". Modelling studies have mapped out the relationship between thickness, radius, number and location of PFCs, the permeability contrast with the matrix, and the quantity of negative geoskin. With some understanding of the external limits of the reservoir the lateral extent of these phenomena can be estimated.

We show the application of the model in a braided fluvial reservoir. The well test in two wells are solely the response to different architectural organisation of the same matrix and channel permeabilities. The model shows that the two wells lie at the extremes of a continuum in which the scale of channels is the only varying parameter. This knowledge is useful in the understanding of reservoir performance and allows the well test data to be used more effectively in the reservoir model.

This study also shows that the interpretation of the skin can be an important measure of the near well bore properties and should be expected in braided fluvial systems (i.e., high net: gross) where high permeability, small scale (relative to the tested volume) channels can be present. Other high net:gross reservoirs were there are high permeability contrasts may also show such phenomena.

Introduction

Braided fluvial reservoirs are important hydrocarbon reservoirs worldwide that are characteristically highly heterogeneous as a result of the sedimentary processes. In these systems, permeability is largely controlled by the primary textural parameters of the sediment. The variability in permeability is a function of sedimentary architecture and this determines the characteristics of the well performance as shown by, the well test response. P. 87
Plugging Potential Of Gravel Carrier Fluids, Contaminated By Satellite Particles Originating From Gravels
Authors: Reijnen P.H.F. , Trompert R.A. , Samuel A.J.
Published: December 2007

The fine materials present in the gravels used in gravel packing represent a largely unrecognised source of impairment. They form filter cakes on/in the perforation wall resulting in direct impairment and cause declining injectivity while placing gravel in perforations. This may cause poor perforation filling with gravel, which in turn leads to pack invasion on production and further impairment.

This study has revealed substantial levels of permeability impairment caused by injection of suspensions containing fine debris from originating gravels (clay, silt and satellite particles). This occurs for natural gravels that are well within the API specification limit of 1%w for silt and clay.

This work indicates that the API specification should be reduced to 0.005%w. In this case less than 10% of the fines, causing possible impairment in the completion phase, are originating from the gravel.

Washing of the gravels (if the gravel does not meet the proposed new specification) will reduce the fines content and is suggested for synthetic gravels; natural gravels require a more thorough washing step.

Introduction

Placement of gravel inside perforations relies on leak off of gravel carrier fluid into the formation. This process may however cause i) accumulation of fine solids present in the slurry at the perforation wall or within the formation, resulting in internal or external filter cake formation, and ii) reduced injectivity. The latter may cause incomplete filling of perforations with subsequent invasion of formation grains into the gravel or 'trapping' of fine solids by the gravel pack. In-house studies have proven that these two mechanisms and intermixed gravel with perforation debris are the major causes for internal gravel pack productivity impairment.

All gravels from natural sources and some synthetic materials are contaminated with fine materials viz. silt, clay and grain satellite particles. Even if good oil field practice is maintained (brine filtration, wellbore cleaning prior to gravel packing, minimal use of pipe dope etc.),the fines present in gravel slurries originating from the gravel itself,fines released by the crushing action of the pumps andfines released by the abrasive action of the flowing slurry remain sources of impairment.

Core flushing experiments have been carried out to evaluate the permeability impairment due to the fines present in several gravels. The results obtained are presented in this article.

EXPERIMENTAL PROCEDURES

Fluid preparation and analysis

Gravel slurries (479 g/l) were prepared using 0.45 m filtered 2% KCl brine for two minutes using a high speed (2000 rpm) propeller mixer. The gravel was removed by 80 mesh sieving, resulting in gravel carrier fluids contaminated with suspended fines from the gravel. These gravel carrier fluids were flushed at rates and volumes equivalent to oil field gravel packing practice in the core flushing tests.

P. 699
Meeting the Challenges of Deepwater Subsea Completion Design
Authors: Aldridge Don , Dodd Paul
Published: December 2007

Significant technological advances in methods and equipment have permitted increased drilling in deeper waters, often beyond continental shelves. Completion techniques have also advanced to allow efficient deepwater production. When designing a deepwater or subsea completion, traditional downhole challenges are complicated by subsea wellhead conditions that require advanced practices and equipment. This paper will acquaint the reader with characteristics unique to deepwater, subsea completions and present new completion accessories that maximize performance throughout the life of the well. Included will be a case study of a new use of electronics, dynamic seal assemblies and deepwater subsurface safety systems by an operator in deepwater Gulf of Mexico.

Introduction

When considering deepwater exploitation, not only are the issues of wellhead changed, but also downhole equipment must be modified due to surface and ocean floor conditions. In the design and installation phase of the completion and subsequent life of the well, the presence of certain design parameters and the ease of installation must be considered as well as how any future stimulation, intervention or workover will be accomplished and/or accommodated. This paper will put forth thought processes that must go into a subsea completion design and present a deepwater completion typical of those being used in the Gulf of Mexico.

Tubular design

Tubular design must address some unique aspects of a subsea completion. In addition to wellhead placement on the ocean floor, many wells are highly deviated to horizontal, with obvious impact on tubular and production string design.

Stimulation. The tubular design must address any future well intervention or stimulation modes. The stimulation mode differs in a subsea completion from that of a surface completion. Temperature versus depth, from the surface, increases in a linear fashion in most surface or shallow water completions (Fig 1).

The subsea completion temperature increase is not linear. As fluids are pumped from the surface, they are cooled by surrounding waters until the wellhead depth is reached, at which time the temperature versus depth begins to increase in a linear fashion (Fig 2).

P. 279
Hazardous Wastes In Petroleum Activities Issues on Spent Catalyst : A Case Study
Authors: Suwasono Djoko
Published: December 2007

On April 1994, The Government of Indonesia enacted the Government Regulation Number 19 concerning the Hazardous Waste Management which will be come into effect as from April 1, 1995. Despite all the efforts made, petroleum activities in their operations may use or explore hazardous materials which eventually will produce hazardous wastes. The material, among others are catalyst.

The Appendix of this Government Regulation had categorized the Spent Catalyst as hazardous waste, therefore the handling of this waste (material) should follow the process and procedures as indicated by the regulations.

The new oil refinery at Balongan, West Java, will utilize catalyst, thus produce spent catalyst in quite a big amount, amount, i.e. more than 30 tons per day.

The comparison of treating this bulk of wastes if categorized as hazardous waste ton non-hazardous are quite enormous, and the discussion in this paper will elaborate on the efforts made by Pertamina to appeal to the Government under the co-ordination of BAPEDAL (The Environmental Impact Management Agency), to exclude this specific Spent Catalyst from hazardous waste categories. This references are made to the definitions and criteria set up in this regulation as well as comparison studies with similar industries in other countries.

The exclusion of this Balongan refinery spent catalyst from the present status with categorized as hazardous waste to non-hazardous will eventually meet the requirements of sustainable development operation achievable in most efficient way.

Introduction

The Treatment of Spent Catalyst at PERTAMINA

In processing crude oil into fuel oil such as premium, diesel oil, LPG, etc. the following processes are employed : distillation, vacuum, cracking and reforming.

The cracking process is the breaking of long CH chain into a short chain generally employing a catalyst to accelerate the said chemical reaction. In addition, the catalyst is also employed at the Hydrogen Plant unit; to help accelerate the reaction between steam and gases from the unit passing through the tube reformer, catalyst of the zinc type is also utilized

In the cracking reaction, the catalyst employed is in the form of sand which mainly contains aluminum and magnesium silica; this catalyst is getting more and more saturated, so it needs to be degenerated or replaced with the new one when it does not function any more.

P. 391
About Kinds of Breakthrough and Maximum Recovery Factor in Dual Coning
Authors: Pietraru V. , Le Bars Ph.
Published: December 2007

A new analytical method of gas and water coning evaluation for horizontal (H) and vertical (V) wells is presented. In dual coning there are five kinds of breakthrough (BT). Both gas and water apex have a parallel evolution and this fact is very important for behaviour of recovery factor (RF). Then analytical correlations for RF are presented followed by examples of calculation. RF depends mainly on well position (and its perforation), oil rate, anisotropy and capillarity.

Introduction

The most remarkable papers on coning phenomenon are Muskat and Wickoff, Sobocinski and Cornelius, Bournazel and Jeanson and Weiping and Wattenbarger. The main sources for analytical solutions are classical books by Carslaw and Jaeger and Muskat and recently books by Chaumet and Streltsova.

Pietraru and Cosentino published in 1993 a new fully analytical approach. This method has been generalized and extented for dual coning. Muskat and Wickoff (figs. 4 and 5) was the source for the new concept of "radius coning". The references, were used for analytical solution of diffusion equations, with various boundary conditions.

This paper presents briefly the new method, after references, then presents criteria for different kinds of breakthrough and new correlations for recovery factor (actual and maximum) in dual coning.

Dual coning

Correlations for dual coning parameters

Fig. 1 presents a geometrical scheme for dual coning. Main hypothesis is that gas oil contact (GOC) and oil water contact (OWC) are influenced by one well only (no interference). Dupuit's hypothesis is accepted (when the vertical flow composants are neglected). The pressure drop controls both gas and water apex and if gas-cap and aquifere are very strong the pressure drop in gas and water are neglected. Then the heights of apexes are given by the following expressions:

(1)

(2)

where po is the pressure drop in oil between the initial pressure and the pressure at the apex. In this condition both height of gas and water apexes are directly proportional to the po and inversely proportional to density difference. Constant C1 depends of unit system (see Table 1).

Coning Radius. Pietraru proposes the new concept of "coning radius" and its empirical expression:

(3)

The radius coning is a very important parameter. It defines the value of abscissa controlling the critical coning height.

Correlation of oil rate versus time of BT

Fig. 2 presents the main correlation of dimensionless rate as function of three dimensionless parameters (see Appendix A)

(4)

General solution. A new solution is given with the hypothesis that the oil rate is the sum of three terms: first term is the rate of an horizontal drain (with length 4, see appendix A) and both second and third terms are equal to half rate of V well.

P. 169
Underbalanced-Directional Drilling with Coiled Tubing - Challenges and Solutions
Authors: Scherschel S. R. , Graves D. G.
Published: December 2007

The inherent advantages and limitations of drilling with coiled tubing have been the subject of many presentations in the last several years. The potential benefits that coiled tubing drilling systems offer have prompted development of several competing systems that are now being brought to the market. Although each of these approaches share some similarities, unique features have been introduced that enhance the value of the available systems.

Full exploitation of coiled tubing drilling systems dictate that a practical approach be taken. Specifically, the most attractive approach is the one most highly leveraged to deriving the benefits offered by using coiled tubing. Because the coiled tubing drilling system is subject to limitations with respect to force delivery and the inability to rotate, the application of this emerging technology needs to be directed to a niche where it provides the operator best value.

Coincident with the developments in coiled tubing drilling, industry's acceptance of underbalanced drilling techniques has been growing. It is now widely understood that the advantages of coiled tubing drilling are most evident in underbalanced operations. These advantages of technology will be applied to a wide range of well-finishing and re-entry operations to increase both the productivity and recovery of hydrocarbons from existing fields.

This paper presents the latest technology being applied in underbalanced coiled tubing drilling operations and highlights the additional advantages of using a pressure deployment system. Operations conducted in the first ten months of 1996 using these tools are reviewed.
Pressure Transient Analysis for Horizontal Well and Multi-Branched Horizontal Wells
Authors: Kong X.Y. , Xu X.Z. , Lu D.T.
Published: December 2007

Transient pressure for cases of a horizontal wellbore axis with any angle inclined to a fault or a constant pressure supply boundary in anisotropic formations were studied. This axis parallel to or perpendicular to a fault is only its a simple special case. Particularly, the cases of multi-branched horizontal wells and horizontal well in pinch angle (wedge angle) were developed.

The table of the analysis solutions of transient pressures for various arrangements of horizontals are provided. The wellbore pressures took into account wellbore storage coefficients and skin factor are handled by the help of Laplace transforms.

Introduction

Transient pressure analysis for horizontal wells have presented in several publications, Refs. 1–20. These literatures considered the cases of horizontal wellbore axis parallel to a fault, a horizontal well in infinite formation and in rectangular bounded formations (box-shaped drainage, well parallel to or perpendicular to side faces), respectively.

In this paper, we first give the line source solutions with no wellbore storage and no skin for cases of horizontal wellbore axis parallel to or perpendicular to a fault or constant pressure supply boundary. Then we present the line source solution of multi-branched horizontal wells, i.e. drilling several horizontal wells with various directions from main vertical well. It is equivalent to a horizontal well in a pinch angle in certain conditions. The line source solutions for a definite problem are based on the use of source and Green's functions. Then we take into account wellbore storage and skin used Laplace transforms. A table of Green's functions of transient pressures was prepared in this study for multi-branched horizontal wells and horizontal well in pinch angle (wedge angle) as well as horizontal wells near a fault or constant pressure boundary.

Physical Model and Governing Equations

The model considered in this study is assumed as followingThe fluid is slightly compressible, its viscosity and compressibility c1 are constants.The formation is horizontal and equal in thickness h.The well is assumed to be parallel to the top and bottom which may be impermeable or constant pressures, to be locate at any location, zw, from the bottom, its length is 2L.The formation is anisotropic system with KH KVGravity effects are considered to be negligible.

The equation governing flow is the diffusivity equation as derived from the continuity equation, an equation of state, and Darcy's Law

(1)

where p(x,y,z,t) is pressure, and

(2)

in Eq. (2) c is total compressibility.

Horizontal Wells near a Fault or constant Pressure Boundary

Horizontal wells parallel to a fault

For a horizontal well parallel to a linear fault, the x-coordinate direction is oriented along he horizontal wellbore axis, z-coordinate direction upward vertically. P. 285
Formation Damage from Workover and Completion Fluids
Authors: Eaton Ben A. , Smithey Mack
Published: December 2007

Wellbore damage that occurs during initial well completion or workover operations is the subject of this paper. The linear and radial fluid flow equations are reviewed in relation to this problem and in relation to the laboratory procedures used to test for such damage. procedures used to test for such damage. Return permeability testing methods are discussed, as are the results of such tests. Several commonly used completion and workover fluid systems were compared and these comparisons are included.

The merits of the relatively new and almost nondamaging systems are given. Several cases of their application are discussed in the form of field case studies.

Introduction

A subject that has received a great deal of attention in recent years is that of formation or skin damage around a wellbore. Most of this attention has been directed to the problem of skin damage caused by drilling and cementing productive zones. Such damage normally is of a productive zones. Such damage normally is of a shallow penetrating nature and good perforating, stimulating and completion practices overcome much of the problem. However, poor completion and workover fluids and practices may cause considerable damage to a formation long after the formation was drilled, cemented and perforated. The damage to producing formations caused by workover and completion fluids is the subject of this paper.

Many forces tend to change the natural virgin permeability of producing formations during initial completion and/or workover operations. The net result is usually a reduction in permeability in the vicinity of the wellbore or perforations, and a decreased ability of a well to produce.

Operations considered here to be completion or workover functions include the following: perforating casing, under-reaming pay zones for perforating casing, under-reaming pay zones for gravel-packing, under-reaming injection zones for gravel-packing for disposal purposes, gravel packing, plastic sand consolidating, all workover packing, plastic sand consolidating, all workover operations in which a producing zone must be killed, all workover or completion operations in which wellbore fluids are lost to the formation and drilling into a pay zone after casing has been set on top of the zone.
A New Intelligent Computer System for Horizontal Wells Gravel-Packing
Authors: Pu Chunsheng
Published: December 2007

A new mathematical and intelligent computer system for the optimal design of horizontal wells gravel-packing was developed. The mathematical models in this computer system were established by the use of non-Newtonian fluid flow and fluid-solid two phase equilibrium characteristics in the tailpipe-screen annulus and the open channel above an equilibrium bank of the horizontal well. A new propagation algorithm based on Grey and fuzzy theory was used to construct the inference engine of the computer system to give the sanding potentials assessment of a poorly lithified or uncemented sandstone formation. This computer system can be used to predict the flow velocity of the carrying fluid, the pressure distribution of the flow field, the concentration distribution of the gravel sand and the packing efficiency. So, this system can be easily used for the optimal design of horizontal wells gravel-packing. A practical application example was introduced and rather satisfactory results were obtained.
Correction Routines for Production Logs in High Productivity Wells with Open Hole Completions and Screens
Authors: Mustad D. , Berg K.B. , Haheim S.A.
Published: December 2007

A number of production logs in the Troll Oil production wells have been performed. Horizontal screen sections up to 2000 m required logging tool deployment by coiled tubing. All wells flowed monophase oil. Practical correction procedures for the logs are proposed. The corrections cover annular flow between screen and open hole, coiled tubing displacement flow, coiled tubing influence on drawdown and productivity due to reduced flow area. The correction procedures are essential for interpretation of individual layer productivities, which is demonstrated on field examples.

Introduction

The Troll Oil field is located in 300 m water depth offshore Norway. The field is characterized by a thin oil zone (13–26 m) sandwiched between a large gas cap and active aquifers. The reservoir contains several highly permeable unconsolidated sands separated by low permeability micaceous sands. Impermeable calcite layers occur within the high permeable sands. Several publications describing the Troll Oil horizontal well development are available.

The production logs performed on the Troll oil wells had two main objectives:verify cleanup of the well after setting of kill pill,determine the productivity and permeability profiles along the well.

In long horizontal wells with small drawdowns (a typical value during logging at 2000 Sm3/d of the Troll Oil wells is 0.2 Bar), the production log analysis is not straightforward, and a number of corrections to the measured data must be performed to obtain representative production inflow profile along the completion interval. The most important corrections identified for the Troll Oil wells are (1) coiled tubing displacement flow, (2) coiled tubing influence on drawdown and productivity due to reduced flow area, and (3) annular flow between screen and open hole. In addition water or kill fluid accumulation at low points in the well may corrupt the spinner flowmeter response. This paper discusses possible methods to correct for these effects. A possible disturbance of the velocity profile in the screen due to radial inflow has not been accounted for.

Mathematical Modeling

Fig. 1 and 2 show the flow in the screen section with and without coiled tubing present. To understand the influence of the coiled tubing mass and momentum balance of a horizontal well section with and without a coiled tubing is required. The analysis is similar to that performed by Dikken, with the addition of the acceleration pressure drop and the coiled tubing effects.

Mass Analysis. From Fig. 3 the following mass balance equations are obtained for a control volume with coiled tubing partly inserted

(1)

or, equivalently,

(2)

For a control volume without coiled tubing we get

(3)

P. 699
Production Optimization Of Re-Entries By Means Of Electrical Submersible Pump
Authors: Joubert G. , Brito H. , Yibirin J.
Published: December 2007

This paper presents the results of the optimization process carried out in wells JOM-38, JN-3, CD-l and CC-7 located in the Jobo and Cerro Negro Fields, using horizontal drilling techniques and electrical submersible pumping as a lifting system.

These wells originally had been drilled vertically, in an unconsolidated formation of reservoirs with strong water drive, obtaining initial oil production rates in the order of 250 STB/D of 8.5 API and 2500 cP at reservoir conditions. However, because of the adverse mobility ratio, the oil production dropped drastically with time and water production increased substantially (less than 50 STB/D and 85% water-cut) making these wells uneconomical.

Due to the low performance, the wells were re-entered with an average horizontal sections of 1550', obtaining production rates in the range of 350 - 500 BOPD/well using progressing cavity pumps as means of artificial lift. These rates were still below the expected 1000 BOPD predicted.

In view of these results and considering the high productivity index measured in these reentry wells, a pilot project was developed, changing the existing lifting system for an electrically driven submersible pump. The new production rates thus obtained varied from 700 to 1300 BOPD/well, with a watercut in the order of 10 percent.

Introduction

Venezuela possesses one of the largest heavy crude oil and bitumen (8.5 - 9.0 API) accumulation in the world; located in the Orinoco Belt region and Jobo field.

Heavy and extra-heavy oils have been traditionally produced by means of vertical wells with sucker rods as the lifting system, achieving a cold production of up to 250 STB/D.

In the last years, new technologies have been applied in the oil industry to optimize oil production. A combination of horizontal well and lifting methods such as sucker rods, screw pumps and electrosubmersible pumping have been evaluated to determine an efficient and economic way to exploit the huge heavy oil reserves.

Among the lifting methods, electrosubmersible pumping seems to be an attractive system to produce heavy oil wells with high productivity index (able to produce more than 1000 STB/D).

Four horizontal re-entries with high productivity index (two in Jobo field and two in Cerro Negro field) were selected for electrical submersible pump installation, obtaining substantial increase in production.

The pilot test was carried out injecting diluent (diesel refinery cut) at different rates and monitoring the dynamic fluid levels while the pump frequency was increased from 40 to 60 Hz. In this paper, the results of the tests are presented.

Geographic Location.

Wells JOM-38, JN-3, CD-1 and CC-7 are located in the Jobo and Cerro Negro fields in the Eastern part of Venezuela just North of the Orinoco river at Monagas State (Figure 1).

P. 817
Is There a Correlation Between Wettability From Corefloods and Contact Angles?
Authors: Rao Dandina N.
Published: December 2007

Laboratory coretloods have constituted a major step in understanding many aspects of fluids flow behaviour in reservoirs. The reservoir rock samples, having been retrieved from the oil-bearing formations, have been most valuable since they represent the actual solid phase of the reservoir rock-fluids system in laboratory studies. Therefore, it is only natural that we try to maximize the information that can be extracted from these cores and corefloods Oil-water relative permeabilities are perhaps the most widely derived parameters from such corefloods and they are the only recourse to account for all the rock-fluids interactions in the mathematical models developed to describe the reservoir flow phenomena Thus, coring, core preservation, core analysis, core flooding, and coreflood data analysis have formed the basis of our knowledge on reservoir fluid mechanics.

One of the factors that has a strong influence on reservoir fluid mechanics is rock wettability. Therefore, attempts to derive wettability from corefloods are abundant in the literature that spans several decades. On the other hand, contact angles observed in crude oil-water-solid systems have been traditionally regarded as a true or universal measure of wettability. Hence the obvious question - is there a correlation between wettability derived from corefloods and contact angles?

A definitive answer does not seem to emerge from the literature for two main reasons: (1) Craig's broad rules-of-thumb, while enabling approximate comparisons especially between extreme cases of wettability, do not allow direct deduction of rock-fluids interactions to the extent that is required to characterize wettability, and (2) the conventional contact angle measurements have had their own share of problems in terms of reproducibility. The dual-drop-dual-crystal (DDDC) contact angle technique, recently reported in the literature1, appears to resolve this long-standing repr- oducibility problem with contact angle measurements. This presentation aims to compare wettability derived from reproducible DDDC tests in widely differing rock-fluids systems with their corresponding oil-water relative permeabilities derived from waterflood experiments using reservoir and Berea cores In all, a total of six different case studies are compared in which four rock-fluids systems appear to yield similar wettabilities from corefloods and contact angles while the others differ markedly Explanations are sought for these agreements and differences in an effort to shed more light on this important aspect of correlating core analysis with distribution and flow mechanics of reservoir fluids.
Onset Crystallization Temperature and Deposit Amount for Waxy Crudes: Experimental Determination and Thermodynamic Modelling
Authors: Calange Sandra , Ruffier-Meray Véronique , Behar Emmanuel
Published: December 2007

Paraffinic crude oils are often transported at conditions where heavy hydrocarbons contained in the oil may precipitate as a solid waxy material. This precipitation may plug the processing equipment. In the design of oil production facilities, it is therefore essential to be able to predict the conditions where wax crystallization may take place and the amounts of wax which may form. Several models have been proposed in the literature for the prediction of wax precipitation from natural crude oils. But they generally overestimate considerably the amount of wax precipitation below the wax appearance temperature (WAT).

The objective of this study has been to develop a reliable compositional thermodynamic model to compute wax appearance temperature as well as the amount and the composition of waxy deposits as a function of temperature and to verify the proposed model with experimental results. This paper will describe the thermodynamic model and the complementary laboratory test methods. The agreement between the measured and predicted values for two crudes of different production areas is good.
PARA-Based (Paraffin-Aromatic-Resin-Asphaltene) Reservoir Oil Characterizations
Authors: Leontaritis Kosta J.
Published: December 2007

Conventional, carbon number compositional analysis techniques provide the weight or mole fraction of pure components up to Cg-and carbon number pseudo-components that represent the C7+ fraction. These typically reported carbon number oil compositions cannot be used with asphaltene and/or wax phase behavior models and are not suitable for interpretation of experimental asphaltene and wax studies, because they do not provide direct phase compositional information on the waxes, resins, and asphaltenes. Waxes, resins, and asphaltenes are usually distributed among the heavier carbon number pseudo-components in these carbon number-type compositional analyses. Hence, new techniques and methodologies are required for analyzing hydrocarbon fluids for the amount and type of waxes, resins, and asphaltenes and for developing EOS oil characterizations suitable for predicting PVT, wax, and asphaltene phenomena. This will eliminate the traditional guess-work that is involved in the development of EOS oil characterizations of asphaltenic and/or waxy fluids.

A new, efficient, and more accurate technique for analyzing crude oil and its fractions to determine hydrocarbon group types, i.e., paraffins (including paraffin waxes), aromatics, resins, and asphaltenes is the PARA analysis. Distillation, solvent extraction, high performance liquid chromatography (HPLC), gel permeation chromatography (GPC), and other techniques are used to perform the oil analyses and obtain the compositional and structural data required for characterizing each hydrocarbon group with its individual pseudo-components. The analyses, in addition to providing weight and/or mole percent for each fraction, provides a starting a priori oil characterization suitable for EOS type modeling methods. The starting oil characterization includes an experimentally assisted selection of pseudo-components for each hydrocarbon group type together with an initial estimate of their critical properties, molecular weight, and acentric factor. This paper discusses the PARA-Based (Paraffin-Aromatic-Resin-Asphaltene) EOS reservoir fluid characterization technique and presents an example application of PVT and wax phase behavior modeling.
Application of Imaging X-Ray Photoelectron Spectroscopy (IXPS) to Pore Surface Analysis
Authors: Hill P.I. , Hughes C.R. , Isaac K.P. , Jordan M.J. , Hazell L.
Published: December 2007

Imaging X-ray Photoelectron Spectroscopy (IXPS) has been evaluated for its application to derive information on scale inhibitor distribution directly, and the wettability of pore surfaces indirectly, from a number of North Sea reservoir core samples. The technique derived elemental composition of an area of approximately 2 × 3 mm, with more detailed image mapping for individual elements over an area of 700 m.

An hexaphosphonate inhibitor was applied by both adsorption and precipitation methods. Phosphorous, a major component of the inhibitor, was only detected in the precipitated treated core. The level of detection though was below that necessary for more detailed mapping of inhibitor distribution. At this stage of the evaluation IXPS was found not to be appropriate for deriving detail of inhibitor distribution, however, results of this evaluation indicate that surface carbon distribution (wettability) is clearly affected by inhibitor treatment.

IXPS has also been used to compare different core cleaning and conditioning treatments of oil wet North Sea reservoir core samples. Results show that hot solvent cleaned core has a reduced mean carbon surface composition density relative to core that has been mild solvent cleaned. This confirms the removal of significantly more oil by hot solvent cleaning, indicating that core surface wettability characteristics are modified differently by different treatments, even though both treatments are thought to preserve an oil wet state.

Introduction

Wettability of reservoir rock is a critical parameter in reservoir characterisation Reservoir management and the understanding of oil recovery mechanisms require data on wettability, especially as it affects relative permeability and influences the effectiveness of production operations, e.g., surfactant-inhibitor treatments against scale formation. Current techniques for the measurement of wettability are unreliable and can take many months to complete. IXPS can derive such information rapidly.

IXPS also has potential to be implemented to a number of wider applications during reservoir evaluation. It can derive information on the distribution of elements which may relate to core mineralogy or from chemical treatments applied i.e. scale inhibitors.

Objectives

To evaluate the effects of different core cleaning methods on wettability.

To evaluate the application of surface analysis for mapping inhibitor distribution.

To evaluate the use of surface analysis to correlate 'wettability' and/or inhibitor distribution with reservoir framework mineralogy.