bluuebunny/crossref_metadata_2025 huggingface dataset:
Coal Analysis From Well Logs
Authors: Kowalski John J. , Holter Milton E.
Published: December 2007

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

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Well logs can provide an analysis of coal which is comparable to core analysis through the use of new interpretation methods which were developed for use in the United States, Canada and Europe. By using well logging methods, two problems encountered in core analysis are reduced. The answers are available in a very short period of time, there are few storage problems.

Introduction

Log evaluation of coal is not a new concept. One of the early applications of well logs was to delineate coal seams in Europe. However, a more economical, cleaner, and more versatile energy source was found in crude oil, and wireline geophysical techniques were primarily adapted to evaluation of this resource. In the past 10 years, an increased interest in coal led to the development of log evaluation techniques using devices designed for petroleum applications.

The first technique that was developed used an Acoustilog and Densilog combination which could be supplemented with neutron and resistivity devices. This system had several limitations most important of which was hole size. Many coal companies take about 2-1/2" diameter cores (open hole diameter is 4") and logging devices are usually larger than this. Drilling the larger holes adds a considerable amount to the cost. A second objection was that there were few oil wells drilled in coal areas which fit this particular combination of logs so very few oil well recordings would be usable in the coal evaluations. In 1974, Dresser Atlas developed a method which utilized two logs, the Induction Electrolog and Densilog which are frequently encountered in the petroleum industry. This method was later modified to accommodate three other combinations of services.

The techniques used in the past to evaluate coal seams consisted of coring the seams and doing a laboratory analysis of the core for carbon, ash, and moisture. Two major difficulties are encountered with this method. The first is keeping the core in its original condition so that the analysis of the data reflects the true condition of the coal. The second problem occurs when core recovery is poor or whenever the coal is drilled into before the commencement of coring. Both of these problems can lead to a poor evaluation of the reserves, however, well logs offer a solution to them.
Jay-Lec Waterflood Pattern Performs Successfully
Authors: Shirer J.A.
Published: December 2007

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

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Early waterflood performance in the Jay-LEC Fields indicates that the 3:1 Staggered Line Drive pattern is operating successfully. The rapid reservoir pressure decline has been completely arrested and the oil allowable of 93,500 STB/D has been maintained. The waterflood was initiated in March, 1974, and is expected to increase ultimate oil recovery by more than 200 million STB.

Introduction

The large oil accumulation in the Jay-Little Escambia Creek Fields located in northwest Florida and southern Alabama was discovered in June, 1970, and production was initiated in December, 1970. However, reservoir pressure declined rapidly along with additional development and withdrawals. Low ultimate oil recovery and early loss of well capability were eminent.

A 3:1 Staggered Line Drive pattern was selected to initiate a waterflood program after comparative evaluations using a two-dimensional reservoir simulator model indicated that the highest oil recovery and economic potential would be realized. The necessary equipment was installed to service the 3:1 pattern concurrent with field development and unitization. Water injection was initiated on March 5, 1974, four days after the effective date of the Unit.

This paper presents a summary of early waterflood performance which indicates that the 3:1 Staggered Line Drive pattern is operating successfully. The rapid reservoir pressure decline experienced during primary pressure decline experienced during primary operations has been completely arrested by injecting 180,000 BPD of fresh water and the oil allowable rate of 93,500 STB/D has been maintained. Volumetric sweep efficiency appears to be satisfactory since injection water breakthrough has occurred in only two of the 65 oil wells. In each case, breakthrough was predictable and a result of limited, nonrepresentative flood conditions.

Ultimate oil recovery from the Jay-LEC Fields should be increased by more than 200 million STB as a result of a successful waterflood program.

RESERVOIR DESCRIPTION

Geology

The primary oil accumulation in the Jay-LEC Fields is located in the upper Smackover formation. Figure 1 is a structure map contoured on top of the Smackover. Structurally, the reservoir is a southeast plunging nose uncomplicated by faulting.
Synergism in Thickened Water Systems for Improved Oil Recovery
Authors: Norton Charles J. , Falk David O.
Published: December 2007

Synergism is demonstrated among several bicomponent water soluble polymer systems used to thicken water for improved oil recovery. Extensive screening experiments indicate viscosity and screen factor synergisms are unpredictable from chemical nature and structure of the polymers. In some cases screen factor synergism carries over to improved oil recovery in Berea core floods under Maraflood TM process conditions. Several synergistic polymer systems offer potentials for economic savings and potentials for economic savings and operational flexibility together with improved oil recoveries under both secondary and tertiary flooding conditions.

Introduction

Our attention is largely directed toward tertiary recovery systems using the Maraflood process. This paper summarizes our laboratory investigations and results with bicomponent water-soluble high molecular weight polymer mixtures for improved oil recovery under enhanced recovery conditions.

A review of the literature suggested the potential of significant synergism in viscosity. We were impressed by the disparity between the viscosity and screen factor measurements in some systems and decided to give more weight to the latter measurement. We found that screen factor measurement is a useful screening tool that has led us to a number of synergistic systems which give improved oil recovery under laboratory conditions. Studies of many systems indicated that screen factor synergism in bicomponent polymer systems is very rare, unpredictable and not directly correlated with the chemical nature and structure of the polymers under investigation.

EXPERIMENTAL

REAGENTS. Materials investigated are summarized in Table 1. Viscosities and screen factors were determined in deionized water and a soft water formulation (Palestine water).
Casing Plungers: Colorado Project Delivers Promising Results
Authors: Cramer John W.
Published: December 2007

This paper will discuss the history, theory of operation, candidate selection, installation procedure, and operation of casing plungers. Approximately 2000 casing plungers have been installed, primarily in the Appalachian Basin area of the US. The casing plunger is used to remove fluid from the well using only reservoir pressure to lift fluid from the wellbore. When fluid is removed from the wellbore, hydrostatic pressure is reduced and gas production can increase. As the name implies, the casing plunger operates in the production casing of the well. When installed in an appropriate well, casing plungers can help improve production and possibly reduce operating expenses. This paper will summarize current Appalachian Basin casing plunger practices. This paper will describe in depth a five well pilot project operating in Northeastern Colorado. The paper will review the planning, candidate selection, equipment installation, operation, maintenance, and evaluation of the project.

The concept of casing plungers can be traced back to 1956. Casing plungers have been operating successfully in some areas of the Appalachian Basin as early as the late 1980's. Swab wells, open-flow wells, tubing plunger, and pumping unit wells have all proven to be appropriate candidates for conversion to casing plunger production. Casing plungers are an accepted method of production and are currently being installed in new wells as well as in producing wells.

This paper will offer some of the experiences gained in casing plunger operations in the Appalachian Basin area to assist operators to determine if casing plunger technology may be applicable in the Rocky Mountain Region.
Reasonable Lightning Protection for Electric Submersible Pumps
Authors: Brinner T. R.
Published: December 2007

High cost, questionable efficacy and justifiable mistrust are the usual factors that must be overcome when applying lightning protection to ESP's. These factors are true of any product when its performance is difficult to measure and thereby almost impossible to compare with competing products. The intent here is to pull together those aspects of ESP lightning protection that are variable, and once they have been analyzed to recommend ways to organize effective protection.

The most bothersome variable is ground resistance. Basically it depends on soil moisture and mineral content. Soil moisture changes with the seasons. However, ground resistance can be measured, and even in arid regions of the world it is possible to construct low-resistance grounds. Resistance combines with the inductance of the lead wire to form a total ground impedance. When only a single Transient Voltage Surge Suppressor (TVSS) is used, the devices to be protected are always subjected to a minimum voltage equal to the ground impedance times the surge current.

A lightning filter remedies this problem by having separate inputs and outputs and running different ground connections to each. Consequently the lightning-stroke voltage does not appear instantaneously at the output terminals. Further the rate at which voltage increases is reduced, an important factor when trying to protect turn-to-turn insulation in the ESP motor. Being able to justify the added expense of a complete filter depends on how high the ground impedance gets and how critical it is to protect a given ESP.

Testing and verification of protection are major credibility concerns. Any device designed for lightning protection should be subjected to high-voltage impulse tests. Certainly some type of production tests should also be performed. Verification of protection in operation should involve some type of indicator lamp, which turns off when a line-to-ground fault occurs, a component fails or the bulb burns out.

In conclusion both the lightning filter and the TVSS provide much needed ESP lightning protection. The decision on which device to employ depends on ground impedance and the level of ESP protection the operator deems necessary.
Conventional Core vs. Mini-Permeameter Permeability Measurements: Tensleep Formation
Authors: Taylor L. H. , Vinopal R. J.
Published: December 2007

Conventional air horizontal permeability measurements collected at one foot sample intervals from the Tensleep Formation were compared to permeability values collected over the same depth range using a mini-permeameter with a sample frequency of 8 to 10 measurements per foot. The lithologies analyzed consisted of sandstone and dolostone from eolian dune, shoreface, sandflat, and shallow marine shelf facies. Comparison of mini-permeameter measurements averaged over one-foot intervals with the plug permeability value showed that the mini-permeameter average permeability value was higher in the shallow marine shelf and eolian lithologies. In the sandflat and shoreface lithologies, mini-permeameter values averaged over a one-foot interval were not significantly different from the single core plug permeability. Lithologies were analyzed by low power optical microscopy, thin section petrography, and scanning electron microscopy to characterize the pore system. The shallow marine shelf facies consists of dolomite with patchy sucrosic, vuggy, and fracture porosity. The average of the mini-permeameter measurements over a one-foot interval gave a better representation of all the pore system types observed. Eolian sandstones contain a matrix and fracture porosity system. The matrix porosity system shows variability in the size of pores and pore throats due to differential cementation by silica and dolomite and due to differences in grain size and sorting. Variability in the pore system is on a scale larger than a core plug in the eolian and shallow marine shelf facies which causes the deviation between the core plug and averaged mini-permeameter values. Shoreface units consist of homogeneously bioturbated fine-grained sandstone. The sandflat lithology is a ripple laminated fine-grained sandstone. In the shoreface and sandflat units, the pore system is largely uniform through the core on the scale of a core plug which causes no significant difference between core plug and averaged mini-permeameter values. The applicability of the mini-permeameter in providing a more detailed view of permeability distribution in a core is dependent on the uniformity of the pore system on a core scale.
The Effect of Surfactant-Bearing Fluids on Permeability Behavior in Oil-Producing Formations
Authors: Jennings Alfred R.
Published: December 2007

The Effect of Surfactant-Bearing Fluids on Permeability Behavior in Permeability Behavior in Oil-Producing Formations

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

The use of surfactants during various types of fracturing and acidizing treatments on oil wells is a commonly accepted practice. It is known and has been verified by several laboratory studies that surfactants have a marked effect on formation rock permeability in the treated wells. During hydraulic fracturing treatments, for example, large volumes of surfactant-bearing fluids are pumped deep into the formation matrix through the created fracture system.

This paper presents the results of an investigation of the behavior of fluid flow on formation core plugs that have been subjected to either aqueous base fluids or hydrocarbon fluids containing various types of oil-wetting or water-wetting surfactants. Guidelines as to the most efficient types of workover fluid and surfactant combinations for maintaining hydrocarbon permeability are indicated from the data obtained.

A method of "water-block" removal and restoring formation hydrocarbon permeability has also been observed permeability has also been observed and is discussed in this paper.

Introduction

When a fluid is pumped into a semistable environment such as a petroleum reservoir, vast changes in fluid saturations can occur in the area where the encroaching fluid is in contact with the formation and the formation fluids. The fluid pumped into the reservoir may be a fracturing fluid or some other type of workover fluid and may be an aqueous or hydrocarbon fluid.

The presence of the fluid can cause changes in the permeability and flow behavior of the formation. Due to the wide ranges and various types of fluids that are used in oil wells, the investigations discussed in this paper will be primarily related to fracturing fluids. primarily related to fracturing fluids. When a hydraulic fracture is produced in a formation, a breakdown or produced in a formation, a breakdown or actual parting of the rock occurs.
Development of Oil Soluble Resin Mixture for Control of Fluid Loss in Water Base Workover and Completion Fluids
Authors: Crowe C.W. , Cryar H.B.
Published: December 2007

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

A new oil soluble additive has been developed to reduce fluid loss of workover and completion brines. This additive is composed of a mixture of finely divided friable and pliable oil soluble resins and is effective in all brine systems at temperatures up to 250 deg. F. Laboratory tests show good fluid loss control against permeabilities up to at least 900 md. An permeabilities up to at least 900 md. An additional oil soluble bridging agent is used with the additive in fractured or more permeable formations. permeable formations. Unlike the commonly used calcium carbonate type additives, which require acidizing following their use, this product forms a filter cake which is completely soluble in the produced oil. As a result, the danger of formation produced oil. As a result, the danger of formation damage is minimized. No supplemental water soluble gums or polymers are required for fluid loss control although they may be added to increase viscosity and solids carrying ability of the fluid.

The non-damaging nature of the additive is demonstrated by laboratory formation damage tests and the results of well treatments.

Introduction

In recent years, considerable effort has been directed toward the development of new techniques and materials to minimize formation damage during workover and completion operations. Many workover fluids previously in common use have been replaced by previously in common use have been replaced by newer non-damaging systems.

Solids free brines are finding increased use. These brines are designed to minimize formation damage and can be weighted by the addition of high concentrations of inorganic salts. Sodium chloride, potassium chloride, calcium chloride and calcium bromide are often used as weighting agents. Brine densities of up to 15.1 pounds per gallon are possible using mixtures of calcium chloride and calcium bromide.

A commonly encountered problem in the use of solids free workover brines is loss of the fluid to the formation.
Application of Kinetic Hydrate Inhibitor in Black-Oil Flowlines
Authors: Mitchell G. F. , Talley L. D.
Published: December 2007

This paper presents the first commercial application in a crude oil system of a kinetic hydrate inhibitor (KHI) developed by Exxon. KHIs are water-soluble, non-toxic polymers that inhibit hydrate formation in pipelines at much lower dose rates than methanol or glycol by greatly slowing the rate of hydrate nucleation.

Following laboratory testing in Exxon's 4-in diameter hydrate flowloop at pressures up to 1800 psig, the KHI was field-tested in a 2-in diameter, 1.5-mi gas flowline in Alberta, Canada in 1996-97. The KHI was then commercialized in May 1998 and has since been used commercially in a variety of locations, including an 8-in diameter, 28-mi gas pipeline in the Gulf of Mexico. The economic and operating benefits of KHI have been clearly shown in these early applications.

In the application discussed here, KHI is being injected into a high-GOR flowline operated by Imperial Oil in the West Pembina field in Alberta, Canada. Prior to the winter of 1998-99, hydrate formation in this system was sporadic and was remediated by batch methanol treatment. KHI injection began February 1, 1999 and has since eliminated downtime due to hydrates. The KHI was proven effective at very low dose rates (0.5 gal/day in 16 bbl/day of produced water) and has not caused any observable impact in downstream facilities.

Results will be presented for subcooling performance, operability, shut-in performance, and economics relative to methanol. Imperial Oil has since elected to use KHI in three other flowlines in the West Pembina field.

The major conclusion of this work is that Exxon's KHI is effective in a crude oil system. The economic benefit of KHI is evident, as it was in earlier applications in gas-condensate fields. Operability of kinetic inhibitors is similar to methanol, and successful shut-ins and restarts are achievable.
Production of Biosurfactant and Biopolymer from Malaysian Oil Fields Isolated Microorganisms
Authors: Illias R. M. , Ooi S. W. , Idris A. K. , Rahman W. A. W. A.
Published: December 2007

Facultative thermophilic microorganisms were isolated from oil and water samples from Malaysian oil wells. The isolated microorganisms grow in an enrichment medium containing kerosene (hydrocarbon) as the source of carbon and energy. Batch-growth kinetic studies were carried out in a 500 ml shake flask and the production of biosurfactant and biopolymer were found to be cell growth associated. Two of the isolated microorganisms (S24A and S21A) are capable of producing biosurfactant in sucrose and glucose containing medium. These are indicated by the reduction of interfacial tension (IFT) of the supernatant. These two strains obtained the IFT reduction in both sucrose and glucose medium for more than 20 dynes/cm. Strain S19 and S12A can reduce the surface activity of growth medium only in sucrose and glucose medium respectively. Strain S19 can reduce the IFT of sucrose growth medium for 25.27 dynes/cm and no decreased in surface tension and interfacial tension were observed when S19 was grown in glucose medium. Adversely strain S12A can only reduce the IFT of glucose growth medium for more than 30 dynes/cm. Another two isolated bacteria was found to produce biopolymer and increase the viscosity of supernatant from 1 cp to 4 cp are strain S13 and S17A. These isolates produce exopolymer like material when grown on agar medium containing 5% sucrose.
Direct Finite Difference Simulation of A Gas Well with a Finite Capacity Vertical Fracture
Authors: Crafton J.W. , Harris C.D.
Published: December 2007

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

Numerical simulation of a well in a vertically fractured reservoir is described. Real gas potential is the dependent variable. A fractional step numerical method which simultaneously integrates the difference expressions of the reservoir and fracture in an economical manner is used. Simulations of well performance with constant well potential and at several fracture extents are shown and discussed.

Introduction

The increasing demand for an adequate supply of natural gas has caused the development of extremely low permeability gas reservoirs. This is now possible because hydraulic fracturing can produce fractures with radii of 500 feet or more and thus stimulate production to levels that are economic. Estimation of the benefits to result from the hydraulic generation of a fracture in a particular formation is desirable.

It is the authors' belief that the numerical model given here is sufficiently novel and advantageous to merit attention.

Real gas potential is the dependent variable. The fracture is taken to occupy a negligible volume when compared to the volume of the reservoir. Then there is not the difficult problem of giving numerical representation of the small fracture width and the large reservoir extent in the one model. Yet one-dimensional Darcy flow is modeled in the fracture and two-dimensional Darcy flow is modeled in the reservoir. The numerical replacements of those differential expressions are solved simultaneously with relative ease.

The numerical method used is from a class of methods called fractional step methods. Some recent results show how these methods lend themselves to the treatment of third type boundary conditions such as occur for this problem. Also, it is recognized that numerical methods of this type may yield solutions that exhibit peculiar behavior near boundaries. peculiar behavior near boundaries.
Field Application of an Alternative Foaming Agent for Coalbed Methane in the Nora Field in Southwestern Virginia
Authors: Myers R. R. , Mack D. J. , Awny J. A. , Creech G.
Published: December 2007

All surfactants used in hydraulic fracturing adsorb a thin film on the surface of coal within its cleat structure. Foaming agents have been known to persist in produced fluids for long periods of time post-treatment. When methane gas trapped in the coal's matrix begins to desorb and flow through the cleat network in the presence of water and a surfactant film, foam bubbles can form blocking flow of gas to the cleat system and the propped fracture. The net effect is a decrease in the relative gas permeability. The direct result is less gas production.

A novel surfactant or foaming agent has been identified as being much less damaging to relative gas permeability. This paper documents the move from the laboratory to the field of this foaming agent in the first known field trial to validate its potential to improve gas production.
Analysis of Worldwide Natural Gas Production
Authors: Al-Fattah S. M. , Startzman R. A.
Published: December 2007

Natural gas is an increasingly important source of the world's energy. Estimating future supplies of this valuable commodity is an important economic and strategic endeavor. This paper analyses historical natural gas production trends for the 53 countries that produce virtually all of the world's natural gas. Using a multicyclic Hubbert method, we forecast the world's future supply of natural gas to the year 2050.

Our analysis showed that the world ultimate reserves of conventional natural gas will be around 10,000 Tcf, of which about 7,900 Tcf of gas reserves remains to be recovered at the end of 1997. The world production of natural gas is expected to peak by 2014 at a production rate extending from 2012 until 2017 of approximately 99 Tcf/yr. Based on the 1997 world gas production and the results of this study, the world supply of conventional natural gas will continue for 96 years with reserves depletion rate of 1%/yr.

In his 1956, and later 1980, predictions of U.S. natural gas production, M. King Hubbert1 - 4 used one complete production cycle to forecast production and estimate ultimate recovery of natural gas for the United States. Several authors have shown that Hubbert's model with one production cycle is generally adequate for predicting crude oil production. However, this study shows that, in the case of natural gas production, most countries exhibit two or more Hubbert-type production cycles. These additional cycles apparently result from changing exploration technology, regulations, and economic and/or political events. Using a Hubbert model with a single production cycle did not allow for these factors. We found that most of the 53 countries apparently exhibit multicyclic gas production. To account for additional production cycles we used a modified version of the Hubbert model which is referred to as the "multicyclic Hubbert" model. A nonlinear least-squares regression was used to determine the parameters of the multicyclic model for each country. Exploration data, when available, were used to calibrate country models with production data. We also present a mathematical analysis of the Hubbert model by deriving equations for determining the production rates at inflection points and their time of occurrence on the Hubbert curve. We will demonstrate a graphical technique to verify the results.
An Effective Technique to Integrate Core and Wireline NMR Log Data through Relaxivity Grouping or NMR Facies Identification
Authors: Ohen Henry A. , Enwere Paulinus M. , Egwim Rising C.
Published: December 2007

Interpretation of nuclear magnetic resonance (NMR) logs is challenged by the following three factors (1) incpnrect-critical T2 cutoff foF free fluid index (2) incorrect permeability model and (3) effect of unusual.relaxivity properties of the rock on relaxation times. Some of these challenges can be addressed through the use of NMR core spectrometry data for log calibration. The major difficulty lies in the ability or inability to apply the core data correctly in log calibration.

In this work, we demonstrate that the identification and delineation of NMR relaxivity group or NMR facies are critical in the application of laboratory NMR calibration data to log analysis. The method presented also allows direct application of laboratory-based model for log interpretation irrespective of tool-dependent factors like logging speed, borehole conditions, fluid types and saturation.

In developing this technique, the following were taken into consideration (1), the fundamental physics of the behaviour of the magnetic dipole of hydrogen nuclei in the presence of an applied (external) magnetic field, (2), the mathematical relationship between the relaxation rates of magnetisation, the pore size that contain the liquid and other surface properties of the porous media, and (3), the mineralogital attributes of the formation.

We define NMR facies as units in the reservoir that have similar NMR relaxation characteristics. These units are delineated into groups referred to as relaxivity groups. Each relaxivity group has similar T2 cut off and relaxivity product. The combined influence of mineralogicai and textural attributes on relaxation rate is captured in this method.

Delineation of these groups is based on NMR porosity and normalised median value of the relaxation time, T2m. These data can be obtained directly from NMR log data.

The validity and applicability of the methodology is demonstrated by a regional study of NMR transverse relaxation time constant T2. Measurement were carried out on over 400 core plugs, and mineralogical, textural and pore size attributes on selected samples.

The benefits of NMR relaxivity grouping include:

Basis for tool calibration and enhanced interpretation of NMR log output. Algorithm for permeaoility and residual oil saturation determination.
The Sensitivity of Micellar Flooding to Reservoir Heterogeneities
Authors: Kossack C.A. , Bilhartz H.L.
Published: December 2007

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

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines.

This paper provides a comparative evaluation of the effect of reservoir heterogeneity on a miscible-tertiary micellar flood. The sensitivity of slug size, preflush volume, surfactant loss, and miscibility saturation of this complex displacement process was evaluated for a homogeneous, randomly heterogeneous, non-communicating layered and partially communicating layered model partially communicating layered model reservoir. The five-component, finite-difference reservoir simulator used for this study is described in detail.

The results show that reservoir heterogeneity is a dominant factor, adversely affecting the performance of micellar flooding to such an extent that the process may not be feasible in many non-homogeneous reservoirs. In the partially communicating layered model reservoir large volumes of preflush were required; and even after adequate preflushing, 50 to 70 percent of the post waterflood oil in place was unrecoverable. The results indicate place was unrecoverable. The results indicate that for a heterogeneous reservoir the most economical slug size may be a very small surfactant slug that displaces only the easily mobilized oil. This work also shows that a reduction in the surfactant's adsorption properties and a micellar fluid that mobilizes properties and a micellar fluid that mobilizes oil at low surfactant concentrations will, for a micellar flood with a given slug size, both substantially improve recovery.

Introduction

The objective of this work was to study the effect of reservoir heterogeneity on the performance of micellar flooding using a performance of micellar flooding using a numerical simulator. The four reservoir descriptions used in this study were homogeneous, randomly heterogeneous, noncommunicating layered, and partially communicating layered models.
Using Enzymatic Breakers in Horizontal Wells to Enhance Wellbore Clean-up
Authors: Hembling Drew , Chan Albert , Garner Jay , Beall Brian
Published: December 2007

This paper describes the lab testing procedures and results for testing formation core material and used drill-in fluid samples to optimize wellbore clean-up procedures. In addition, a three well case history reviewing completion damage of horizontal wells in the Kuparuk Field on the North Slope of Alaska will be discussed. The case history will compare three separate horizontal completions all completed in the same fault block, one of which, includes the use of enzymatic type breaker system for enhanced wellbore clean-up. Production data, spinner log surveys, and pressure transient testing results will be reviewed from all three completions. Matching the drilling fluid with the formation properties and understanding the completion effect on well performance can be critical to economic success of most sand control and slotted liner type completions.

Extensive laboratory studies were conducted to determine the extent of damage occurring while drilling the pay zone section, especially in horizontal wells using a starch / xanthan based drill-in fluid. This study also defined and evaluated filter-cake removal methods using actual drill-in fluids from the field and formation core samples. Results of these laboratory studies as well as case histories will be presented to illustrate the benefit of using Polymer Specific Enzymes1 (PSE) to reduce drill-in fluid damage in horizontal wells where slotted liner type completions are used.
A Laboratory Drilling Mud Overbalance Formation Damage Study Utilising Cryogenic SEM Techniques
Authors: Byrne M. T. , Spark I. S. C. , Patey I. T. M. , Twynam A. J.
Published: December 2007

Laboratory reservoir conditions flood tests were used to determine the clean up efficiency of a drilling mud that was applied at two different overbalance pressures. The test was designed to simulate, as closely as possible, the conditions occurring in the reservoir during the drilling operation. Relevant core material was used and the pore/overburden pressures, mud overbalance pressures, temperature and production drawdown pressures/rates applicable to field conditions were applied in the laboratory simulation. Drilling mud filtrate volume loss versus time measurements were made at reservoir conditions using sophisticated pumps. All wetted parts of the rig were constructed of hastelloy C276 alloy to avoid corrosion artifacts interfering with the test. Permeability measurements were made prior to mud application and again at the end of the flood test analysis to determine the level of any formation damage. In order to determine the nature of the formation damage mechanisms, geological techniques which included dry and cryogenic SEM and thin section analyses were undertaken. These techniques were applied to the plug trims prior to testing (untreated samples) to determine the natural state of the rock, paying particular attention to the clay mineral and cement types, morphologies and distributions. The plug samples were examined at the end of testing (treated samples) and any variations noted which would highlight the damage mechanisms. The dry SEM and thin section analyses were used to determine solid damage mechanisms such as clay fines migration, scale precipitation and drilling mud solids invasion. The cryogenic SEM analyses were used to examine any fluid damage mechanisms such as wettablity alteration, microemulsion formation, water/oil blocks or fluid retention.

A new technique of cryogenic SEM using EDX (Energy Dispersive X-Ray) analysis was used for X-ray mapping of the remnant mud bodies to determine solid and fluid distributions.
Controlled Debris Perforating Systems: Prevention of an Unexpected Source of Formation Damage
Authors: Javora P. H. , Ali S. A. , Miller R.
Published: December 2007

An unexpected source of potential formation damage can be generated when controlled debris perforating systems are detonated in clear completion brines. This paper presents the results of a systematic laboratory study of this potential damage, previously unreported in the published technical literature.

One source of the damage is related to the powdered metals and metal alloys incorporated into controlled debris perforating systems for the purpose of generating, upon detonation, highly desirable, finely divided residues consisting mostly of particles 200 mesh or smaller. When sprayed into clear completion brine at the high detonation temperatures, high surface area particles become activated and then react with water to form metal oxides, metal hydroxides and hydrogen gas.

However, when the activated particles are sprayed into clear completion brines with certain specific compositions, cemented by-products are also generated at the formation face. These by-products can be extremely formation damaging. Fortunately, the nature and damaging characteristics of the cemented byproducts can be altered and prevented by the addition of a chemical inhibitor into the clear completion brine.

Objectives of this paper are therefore to: 1) Identify clear completion brines which generate cemented byproducts and those which do not; 2) determine brine properties that control the cementing process and inhibit damage from by-products; 3) review operating conditions that accentuate the damage caused by cemented by-products; and 4) provide a chemical inhibitor for clear completion brines which prevents the formation of cemented by-products and damage to the formation.

Guidelines for the selection, modification and field application of clear completion brines used with controlled debris perforating systems based are presented.
Fracture Containment Mechanisms in Soft Rock Frac-Packs
Authors: Buie Ronald P. , Yen H. Dang
Published: December 2007

This study presents a 9-well case history that examines fracture height containment and how variable rock properties affect soft-rock fracture geometry. All frac-packs were designed to remove near wellbore damage while simultaneously installing sand control. Several completions have perforation intervals close to water sands or underlying water contacts. Even with aggressive pump schedules, contrasts in rock properties successfully kept fractures contained. This study examines what reservoirs can be fracpacked without fracturing into water; how contrasts in rock properties will keep a fracture contained; and how variable rock types affect soft-rock frac-packs.

Case histories for depleted, normal pressured, and slightly geopressured reservoirs are included in this study. Bottom hole pressure data during pumping operations, radioactive tracer logs, and production histories were used to evaluate the completions.

Evaluation of this study has minimized the concerns of fracturing into water; led to aggressive treatment schedules when fracturing around water; increased the awareness and importance of alternate path technology; and changed overall perforating strategies.
Application of Inflatable Packers for Production Testing and Conformance Problems in Algeria
Authors: Poitrenaud H. , Souilah B. Y. , Fragachán F. E.
Published: December 2007

Through tubing inflatable packers conveyed with coiled tubing have proved to be ideally suited for multiple zones stimulation, water and/or gas control intervention where accurate fluid placement is essential for the success of the job. The high expansion ratio and sealing capabilities of modern elastomers used today in through tubing Inflatable have allowed operations in more hostile wells than previously possible, increasing job reliability.

Conformance problems related to non desired water and/or gas production is drastically affecting the oil production of certain fields in Algeria. The exclusion of this water and/or gas represents a challenging task by itself. Even more under the hostility of multiple zones intervals open for simultaneous production, making the problem diagnosis a key factor for the success of the intervention.

This paper presents the successful application of a methodology to diagnose and effectively exclude the non desired production with a novel technique using through tubing inflatable packers. A thorough discussion about the inflatable packers, deployment, inflation procedures, zone isolation and selective placement is presented. In addition, four case studies corresponding to the application of this methodology are discussed in detail. Two corresponding to exclusion of water and gas production, respectively, by selective placement of a x-link rigid polymer gel and two corresponding to production testing of isolated intervals.

Finally, results of these interventions are presented. Including stabilized production before and after each treatment.
Floating Production and Offloading Vessels with Dynamic Positioning: An Approach for the Future
Authors: Delgado-Saldivar Gabriel
Published: December 2007

This document describes briefly some aspects on the possibility of using FPSOs for the production of oil in fields that have been developed at deep or ultra-deep water as well as marginal fields or fields where the environmental hazard is high. Both the FPSO components and DP capabilities are briefly described, some issues regarding classification and existing regulations are indicated. The document is presented more in a conceptual manner, although there are several units with this combination working around the world, the concept has not been fully developed, and there is plenty of research and study to be done, and the alternative should be explored as a very feasible possibility.
Effect of Drag-Reducing Agents in Multiphase, Oil/Gas Horizontal Flow
Authors: Kang C. , Jepson W. P.
Published: December 2007

An experimental study has been carried out in a 36-m long, 10-cm diameter in horizontal multiphase system. Oil with a viscosity of 2.5 cP was used as the liquid phase and carbon dioxide was the gas phase. The effect of drag reducing agents (DRA) on average pressure drop, maximum pressure drop and slug characteristics for superficial liquid and gas velocities of 0.5 to 1.5 m/s and 2 to 12 m/s, respectively, was studied at DRA concentrations of 0, 20 and 50 ppm. Temperature was kept at 25 °C and pressure was maintained at 0.13 MPa.

The DRA was effective in reducing the average pressure drop significantly for all superficial liquid and gas velocities in both slug and annular flow. The average pressure drop reduction of up to 82% for slug flow and 47% for annular flow was achieved. For slug flow, the effectiveness generally decreased with increase in superficial liquid velocity. The maximum pressure drop across the slug also reduced with addition of DRA. The effectiveness for maximum pressure drop was over 28% at a superficial liquid velocity of 1.5 m/s for all gas velocities.

At superficial liquid and gas velocities of 0.5 and 2 m/s, the flow pattern changed from slug flow to stratified flow by decreasing the slug frequency to 0 slug/min. when 50 ppm DRA was added. At higher liquid and gas velocities, the slug frequency also decreased significantly. The effective height of the liquid film decreased with addition of DRA.
Disposal Problems at Drilling Locations
Authors: McDaniel Kent W.
Published: December 2007

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

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines.

In view of the rapidly developing field of environmental law and practices, this presentation is an effort to point out some of the numerous guidelines as they pertain to the rules and regulations of a land drilling operation. The problems of proper rights-of-way and site selection, disposal, restoration and protecting the environment without a complete trade-off in economics are becoming increasingly more challenging each day.

Some of the more obvious and important aspects of a drilling operation from the time the project is conceived to its completion pertaining to the aforementioned are covered. Certainly all facets necessary for consideration and action in this area cannot be explored in depth in a paper of this type due to time allotment. Actual problem situations of a drilling operation and how they can be approached and handled display some of the time and effort required for this task.

Discussion

The complexity and number of regulations now governing current drilling operations require that every effort be made to illustrate as simply as possible some of the guidelines necessary to a project. Reference to specific regulations have been necessarily avoided to minimize inaccuracies from an individual interpretation of any one given set of laws.

On any planned drilling project, a few basic rules of thumb would be applicable and well to keep in mind throughout the planning and doing-stage. These might be summarized as follows:In all cases of unintended conflict, conformance with all applicable laws, rules and regulations is of course mandatory.Some current environmental laws and pertinent regulations contain language to the effect that proposed operations should utilize the best available technology to reduce adverse environmental effects.