bluuebunny/crossref_metadata_2025 huggingface dataset:
A Compact High-Performance Absorber for Small-Size Remote Field Gas Processing
Authors: Chakma A. , Islam R.
Published: December 2007

A compact high performance mass transfer device capable of producing very high interfacial area and turbulence is described. Interfacial areas as high as 106 m2/m3 of absorber can be obtained which is considerably higher than coventional mass transfer devices. This allows the absorber to be compact and therefore makes it suitable for use in small scale gas fields and in remote field operations where conventional gas processing technology is not economical. This paper provides the theoretical basis of mass transfer enhancement, experimental mass transfer and fluidodynamic data for this absorber. Design equations are provided and other potential applications are discussed.
Four Pressure Buildup Analysis Techniques Applied to Horizontal and Vertical Wells with Field Examples
Authors: Salamy S. P. , Locke C. D. , Overbey W. K. , Yost A. B.
Published: December 2007

Pressure build-up analysis of Devonian shale gas reservoirs is very critical and essential for determining the reservoir formation properties such as the flow capacity (Kh), skin factor (S), and the average reservoir pressure (P̄). Due to the complexity of the shale reservoir (its typically very low permeability and the presence of a dual porosity system), valid and accurate results of pressure build-up analysis are important to the optimization of individual well completions or depletion plans for gas reservoirs in the shale. Horizontal wells may allow operators to take better advantage of the shale fracture systems and anisotropic flow regime, but they present a new challenge for well testing and analysis.

This paper documents a technical procedure with field examples, using pressure build-up data from horizontal and vertical wells, to assist the reservoir engineer in evaluating the reservoir prior to any decision-making process. This procedure implements two conventional build-up analysis techniques: (1) type curve matching, and (b) Horner's technique. Pressure and pressure-derivative values are used to estimate values of skin, flow capacity, and average reservoir pressure. A newly-developed technique known as the rectangular hyperbolic method (RHM) is implemented in the pressure build-up analysis for comparison to results determined by the previous techniques. The RHM technique is accurate/valid for estimating the various reservoir properties and, in particular, the average reservoir pressure. In addition, reservoir engineering simulation is used to verify the results of the various techniques by using either the pressure build-up data or the production history for the history matching process.
Tender Assisted Drilling – NPD Experience
Authors: Mathiesen R.
Published: December 2007

TAD systems are in use and planned for future usage in the Norwegian Continental Sector of the North Sea. The NPD experience has been positive when compared to more traditional field development designs. The paper will explain the advantages gained by such TAD systems with respect to risk to personnel, environment and invested equipment.

The main contributing factors fall under the category of frequency of ‘Residual Accidental Events’, which appear to be lower with TAD systems.

The bridging system providing a safe protected escape route from such accidents as blowouts, riser ruptures, fires and explosions on either the wellhead platform or the TAD vessel, is the single most beneficial sub system.

Both the wellhead platform and the TAD vessel, is the single most beneficial sub system.

Both the wellhead platform and the TAD vessel are built or upgraded to meet NPD regulations for production installations.
The Tommeliten Subsea Project
Authors: Solheim A , Prichard M , Newcombe R
Published: December 2007

The paper will present the Tommeliten Subsea Development Project with emphasis on the X-mas tree and control systems. The experience from the test phase is also highlighted.

The Subsea development of the Tommeliten field was interesting and special with regard to utilizing an existing platform system with a different operator/-owner for processing and distribution. It is also one of the first fields being developed with a 10,000 psi X-mas tree system.

The trend of activities in the North Sea is towards smaller and less expensive development solutions.

The field is marginal and was developed with an economically sound solution.
Hydrate Mitigation in a Deepwater Production System
Authors: Setliff S R , Parfitt G M , Chilton T S
Published: December 2007

Deepwater developments such as the one depicted in Fig 1 rely on production flowlines to carry raw, unprocessed reservoir fluid, called full wellstream (FWS) production, from wells to production facilities. As the search for reserves has taken the petroleum industry into deeper water and colder environments, the feasibility of producing FWS may become questionable due to the possibility of hydrates in the flowlines. The lower capital investment of FWS production flowlines is also attractive in shallower water. Even here, the risk of hydrates raises questions of feasibility in shallow, cold water environments.

When hydrates form in production streams, they can pose problems with economic consequences. Field experience indicates that hydrates occasionally obstruct production flowpaths (Ref 1 and 2). In the event of a partial obstruction, hydrate formation is a nuisance, slowing the production stream until the obstruction can be removed. And, in the event of a complete obstruction, full stoppage of production can last for weeks while mobilizing equipment to remove the obstruction. The cost of the mobilization on top of the lost revenue from the interruption in production can have serious economic repercussions.

Figure 2 is a hydrate formation curve for a crude oil reservoir fluid with a gas-oil-ration (GOR) of 1000 SCF/STB (177 SCM/STCM). Note that increasing pressure or decreasing temperature favours hydrate formation. The worst exposure to hydrate formation usually is associated with a prolonged interruption in production, when the pressure rises to shut-in wellhead pressure (SIWHP) and the contents of the flowline cool to seabed temperature. While hydrate formation will be more likely in deep water, even at typical seabed temperatures in the North Sea (40-45°F or 4-7°C), hydrate formation is possible.
Air Diving Inspection of Offshore Facilities: The Advancement of Transferring Under Pressure Within The Air Range
Authors: Neal B. R , Townsend A. R
Published: December 2007

This paper addresses the following related subjects: iThe different types of diver deployment and retrieval systems in present use within the UK Sector.iiTotal Oil Marine's successful experience of using a HYBRID BELL system in conjunction with the technique of TRANSFER UNDER PRESSURE for platform based air diving operations during 1988.
Image Analysis of Reservoir Pore Systems: State of the Art in Solving Problems Related to Reservoir Quality
Authors: Davies D. K.
Published: December 2007

Image analysis is rapidly emerging as a promising new technology for the quantification of pore geometry. This paper presents reservoir-oriented applications of pore geometry analysis with particular emphasis on reservoir quality (porosity and permeability).

Image analysis consists of a computer-based, systematic procedure which quantifies those aspects of porosity that are visible using a 2 dimensional image (thin section or SEM image). This allows for identification and quantification of the size, shape, distribution and volume proportions of different pore types (pore geometry). In terms of producibility, pore geometry can be more important than total porosity particularly in rocks with less than 25% porosity.

Two examples are presented that demonstrate the application of image analysis of reservoir pore systems to problems related to formation damage and reservoir quality. In the first example, pore geometry derived from sidewall cores is related to test results in an offshore well. There is a direct relationship between pore geometry and flow rates. Zones that under-produce their pore system are identified as potentially damaged zones.

In the second example, pore geometry is related to test results, routine core analysis and log response (specifically deep induction and sonic travel time). A rock-based log model is developed to identify Rock Type units on a foot-by-foot basis in cored and non-cored intervals.
Stability of Clay Minerals in Acid
Authors: Simon D. E. , Anderson M. S.
Published: December 2007

Hydrochloric (HCl) acid is commonly used to acidize sandstone formations. Although much emphasis has been placed upon the dissolution and reprecipitation theories for acidization with hydrofluoric (HF) acid, little information is available concerning the effect of HCl acid on clay minerals commonly found in sandstone formations. While clays are not truly soluble in HCl acid, exposure to HCl acid does affect the structure of clay minerals.

This paper presents results of acid stability studies conducted with chlorite, illite, and kaolinite Clays. Initial testing utilized solubility analyses to determine which minerals are affected by acid. A second series of tests utilized x-ray diffraction analysis to determine the effect of HCl acid on the crystalline structure of the clays. Chlorite was found to be the most susceptible to acid attack. The reaction of acid on chlorite was found to be dependent upon HCl strength and temperature. A third series of tests evaluated the effects of weak HCl, formic, and acetic acid.

Diffraction studies, coupled with fluid analyses, revealed that the mechanism of acid attack is the leaching of ions from the matrix of chlorite clay. By-products of the acid dissolution of chlorite clay are of concern because they can cause formation damage. When the crystalline structure is destroyed, a significant amount of amorphous residue remains. The leached ions (primarily iron and aluminum) can precipitate as the acid is neutralized.

In addition to the diffraction studies, permeability change flow tests were conducted utilizing formation cores with high chlorite content. The results of these tests demonstrate that formations containing chlorite clay can be acidized successfully, provided that clay content, acid strength, and bottomhole temperature are considered in the treatment design. The flow tests also demonstrate that where extremely high chlorite contents cause acid sensitivity, organic acids may serve as acceptable breakdown and stimulation fluid systems.
Gravel Packing Horizontal and Highly Deviated Openhole Completions Using a Single-Screen Prepacked Liner in Offshore California Fields
Authors: Ashton J. P. , Liput J. , Lemons R. , Summerlin J.
Published: December 2007

A major operator has successfully gravel packed two long interval wells in the Giant Beaver and in the Santa Clara offshore California fields, [576 feet (176m)] and [1475 feet (450m)], respectively. The wells are producing from 11 inch diameter open hole gravel packed intervals having maximum well deviations of 87° and 84° from the vertical, respectively. Both wells were completed using downhole hardware specifically designed for horizontal (or extremely deviated) wellbore gravel packing. Gravel was placed around the single screen prepack liners using reduced viscosity (±400 cp @ 100 sec1) gravel carrier fluids, low gravel concentrations (3 to 5 ppg) and increased displacement rates (±5.0 BPM).
Rate-Convolved Horner Plot for Analysis of Simultaneously Acquired Flow Rate and Pressure Data
Authors: Tariq S. M.
Published: December 2007

During the last five years, the use of simultaneously acquired pressure and flow rate data in well test analysis has become quite common. The additional measurement of downhole flow rate makes the assumption of constant wellbore storage unnecessary and enables one to perform a more rigorous analysis. Many techniques have evolved for analyzing such data. These include convolution, deconvolution, convolution derivative, and convolution type-curves. In this paper, we present a new technique called the Rate-Convolved Horner plot for analyzing rate and pressure data which offers certain advantages in comparison to other methods. These advantages include: simplicity and analogy to conventional Horner plot, integration of flow period data with shut-in data, better handle on skin, and its adaptability for quick well-site interpretation. Field examples are presented to show the application of this technique to a variety of well testing configurations. The technique presented in this paper is especially suited for the analysis of short duration transient tests, i.e., after underbalance perforating, TCP/DST, closed chamber testing and IMPULSE* Testing because of rapid variations of flow rate in such tests.
Compressive Loading Casing Design
Authors: Kocian E. M. , Mefford R. N. , Hilbert L. B. , Kalil I. A.
Published: December 2007

This paper provides compressive loading design guidelines for the provision of safe, economic casing for any type of onshore well. Compressive loading design is analyzed by looking at the nature of compressive loads, casing compressive failure mechanisms, and load distribution. Field data verifying such analysis is presented. Lastly, recommended procedures and design factors are offered to reach a final design.
Inspection and Certification of Hoisting Equipment for Critical Wells
Authors: Kirkham K. K. , Lowery D. E. , Hays D. P. , Skogsberg J. W.
Published: December 2007

An elevator failed unexpectedly while drilling a critical deep sour gas well. The elevator failed by brittle fracture. After reviewing industry practice, we decided that the minimum standards provided by API on hoisting equipment were inadequate for a few critical wells. This realization prompted us to develop a complete rig hoisting equipment inspection/ certification program for critical wells. On implementing the program, we found that basic materials certification was not routinely available and detailed component inspections were not routinely done on any hoisting equipment. This paper presents our inspection and certification requirements and thè results of several jobs.
A New Approach to Rig Sensors
Authors: Lesage M. , Casso C. G. , Zanker K. J.
Published: December 2007

The traditional image of mud-logging as a low-tech activity is gradually changing. Drilling data, which were not even archived a few years ago, are now sent by satellite to engineers in offices hundreds or thousands of miles away. These engineers need accurate and reliable information to run the sophisticated computer simulations required in modem drilling.

In the harsh economic environment of today, quality data eliminate waste and help prevent severe incidents: the use of MWD torque and WOB to detect cone locking and incipient pipe sticking is now well established.

Finally, reliable data fed into a proper computer system increase rig safety: thousands of factories, refineries, nuclear plants run (generally) safely because a multitude of sensors alert the engineer to possible malfunctions.

The new rig sensors need to be accurate, reliable, intrinsically safe and reasonably priced. Because no two rigs are alike, they need to be versatile and easy to calibrate (or even better self calibrating). Because the life of the crew might depend on them, the sensors need to be able to diagnose themselves.

To fulfill these requirements, the sensors need to be associated with a computer or micro-processor. The advantage of a central computer over a local micro-processor, is that the computer has access to all the data of the rig to decide if an alarm is valid. For example a computer can easily differentiate between a total mud loss and a stop of the pumps.

This paper presents three new sensors which fit at least partially the description above: a flow-out sensor, with an average accuracy of 25 GPM on a fixed rig, a depth system with a proven accuracy of one foot in a thousand feet, and a ‘calibratable’ hookload sensor.

The flow-out is continuously compared to flow-in for kick and loss decisions. We explain in detail how the system is self-calibrating and self-diagnosing, the management of the alarms and the techniques used to detect a developing kick as early as possible.

The depth system automatically feeds the lengths of the pipes added or subtracted to a tally book. It can be compared to the driller's tally to detect wrong entries or the need for a new calibration.

Calibration of the traditional pressure sensor tomeasure hookload is made every year (in good cases) at great expense. This is not satisfactory when the overpull while tripping is close to the limit of the pipes in deep and deviated wells. We describe an alternative sensor which can be straightforwardly calibrated on the rig.
Effects of Gas Cap and Edge Water on Oil Recovery by Steamflooding in a Steeply Dipping Reservoir
Authors: Hong K. C.
Published: December 2007

A numerical simulation study was conducted to elucidate recovery mechanisms and find optimum operating strategies for a steeply dipping, heavy oil reservoir. A model representing a 20° dip reservoir with an updip gas cap and a downdip edge-water was used for the study.

The study showed that gravity drainage of the heated oil is the main production mechanism in steamflooding steeply dipping reservoirs. Steamflood oil recovery for this type of reservoir is strongly affected by gas cap and aquifer pressures. This is because the gas-oil or water-oil contact can move closer to or away from the initial oil zone, depending on those pressures relative to that of the steam zone. High gas cap pressure is desirable because it slows the injected steam rising above the initial gas-oil contact where injected heat is wasted. A high aquifer pressure retards the growth of steam-zone downdip, thereby reducing the steamflood efficiency.

The study further showed that this type of reservoir can best be exploited by: (1) initiating the steamflood as a line drive with steam injection into the oil zone away from the gas cap and edge-water, (2) placing the injector closer to downdip producers than to updip producers in order to distribute the injected heat evenly between the updip and downdip directions, and (3) continuing to operate both updip and downdip producers to capture the displaced, heated oil until an economic limit is reached. Maintaining a high gas cap pressure by injecting a noncondensable gas, if the gas cap volume is finite, is an additional operating strategy for improving steamflood oil recovery from this type of reservoir. If the aquifer pressure is low, infill drilling downdip from the original producer can be used to improve capture of the displaced oil.
Comparative Study of Prepacked Screens
Authors: Harrison D. J. , Johnson M. H. , Richard B.
Published: December 2007

Prepacked screens (gravel pack screens fabricated with gravel pack sand incorporated into the device) are being used more frequently in gravel packed completions. Many types of prepacked screens are available, but little comparative data has been published. This paper is a comparative study of prepacked screen types. Included in the study are standard gravel pack screen, prepacked screens with two different configurations of pipe and wire jackets, and the more recently developed prepacked screens for restricted casing diameters. The prepack screens were tested with consolidated and unconsolidated gravel pack sands. The plugging potential, the blast resistance, and sand control capabilities of prepacked screens are presented. A 20 in. (500 mm) test cell of 7" (178 mm) casing was fitted such that an air or water sand blasting unit could be used to direct blasting sand at the test screens. The tests indicate prepacks with a thin layer of consolidated gravel pack sand can provide insurance against a gravel pack failure should voids occur in the gravel pack. Also, testing indicates little pressure loss will occur through a prepacked screen during production. The prepacks exhibit good resistance to plugging for particle diameters less than 38 microns. Therefore, current filtration practices employed for gravel pack completions are adequate for prepacked screen applications.
An Overview of Reeled-Tubing-Conveyed society Production Logging Capabilities in California
Authors: Harness P. E. , Hansen M. D. , Terzian G. A. , Fowler S. H. , Golino F. J.
Published: December 2007

Horizontal well completions have increased production efficiencies for operators and are challenging service companies to develop new wellbore analysis and maintenance techniques. Reeled tubing has played a key role in the development of horizontal well servicing techniques. Especially important is the ability to run a continuous tubing string through horizontal intervals while the string is under compression.

By installing an electric wireline inside reeled tubing and using the reeled tubing as a transport and placement mechanism, many standard wireline services can be performed in highly deviated and horizontal wellbores, even in live well conditions. Reeled-tubing-conveyed wireline services performed to date in California include production logs, cement bond logs, casing inspection logs, and perforating. Reeled-tubing-conveyed wireline systems have been successfully deployed in California wells with deviations of 90°, over horizontal ramps of 7,200 ft (2,195 m) in length, at depths of 13,900 ft (4,237 m), and with wellhead pressures of 2,000 psi (13,790 kPa).

A reeled-tubing-conveyed wireline system is described in detail and two field examples are discussed.
Analyzing Unstable Flow in Multilayer Gas Lift Wells with an Application of the Inflatable Diverter Flowmeter
Authors: Clark D. G. , Beardsell M. , Cherel X.
Published: December 2007

Downhole flow and pressure measurements monitored in low flow rate gas-lifted wells in multilayer reservoirs offshore West Africa revealed that production from many of these wells was cyclic in nature. This phenomenon, called "slugging", causes bottomhole measurements to oscillate in unstable fashion. The traditional approach used in measuring vertical flow profiles and computing production allocations for the individual zones drained was invalidated as a result.

Inflatable Diverter Flowmeters* were used successfully in these low rate/high deviation/high water cut wells to provide measurements which, when interpreted as discussed in this paper, yielded not only the desired flow profiles but also permeability, skin factor and potential of the individual layers that were monitored. The flowmeter's response pattern under these conditions was verified by comparison against a numerical reservoir simulator model currently used for multilayered reservoir interpretation. The extension of this technique to the analysis of unstable wells is discussed. The results from a successful match between simulated and measured data (achieved via nonlinear optimizations) provided the layer permeabilities, skins and potentials which, in turn, were combined to derive synthetic flow profiles and by layer inflow performance curves.

Two field examples of wells exhibiting cyclic flow behavior are presented. Results compared favorably with those from buildup tests. Based on experience gained from the evaluation of these wells, recommendations are made for modifying data acquisition schemes so as to enhance final interpretation answers.
Extended-Reach Drilling from Platform Irene
Authors: Mueller M. D. , Quintana J. M. , Bunyak M. J.
Published: December 2007

Four wells have been completed on platform Irene at inclinations as high as 87 degrees. The most recent well, #A-16, was drilled to a total measured depth of 14387′, with a horizontal departure of 12740′ at a tree vertical depth of 4420′. Over 73% of the well path was at an inclination at which incremental drag forces exceeded the incremental inclined buoyed weight.

Major accomplishments for this will include:

-A 9-5/8" casing string was easily run to 8678′MD utilizing buoyancy assistance to minimize drag forces. Drag data proved that without buoyancy assistance the casing would not have made it past 7500′MD.

-Special drill string design minimized trip time while drilling by maximizing the depth at which pipe could be run without rotation. This same design technique enabled pushing open hole logs for over 5300′ to 14040′MD, while conventional drill pipe conveyed logging would barely have made it out of the 9-5/8" casing shoe.

-Almost 6000′ of 7" liner was rotated down the hole utilizing an innovative hydraulic releasing tool.

In addition to the above, this paper addresses well path and mud program design considerations, as well as problems encountered while drilling and completing the well.

P. 604
Gypsum Determination in Shallow West Texas Carbonates
Authors: Hedberg H. S. , May D. H.
Published: December 2007

The younger Permian carbonates have been prolific producers over the years. The San Andresand Grayburg dolomites, which are productive in nearly all areas of west Texas, are ol particular note. Although traditional log analysis has been generally successful in ihese reservoirs, the presence ol gypsum in many has created difficulties. Gypsum tends to result in overly optimistic porosity calculations and also tends to restrict permeability by plugging the pore throats.

This paper exjfiains some ol the difficulties encountered when using traditional log analysis techniques in gypsiferous reservoirs and shows how the ELAN* log interjmetation program has been used to give superior results.
Field Experiences with Computer-Controlled Drilling
Authors: Brett J. F. , Warren T. M. , Wait D. E.
Published: December 2007

This paper describes the mechanical, electrical, computer, and software systems of a prototype computer controlled drilling rig. The rig has operated under computer control for over three years on a project investigating optimized turbine control. In addition to describing the advantages and the basic computer control features of the rig, this paper presents the practical problems for computer controlled drilling and suggests possible solutions to these difficulties.

In the past, several attempts at full computer control of the drilling process have been made, but all have ultimately proven to be short lived. Recent advances in the power and reliability of sensors and computer control hardware, as well as reductions in their cost, have brought computerized rig control closer to reality. However, some important hurdles remain.

It is the authors' experience that most of the hurdles lie on the electrical and mechanical side of the system. Computer hardware and software capabilities have improved to the point that almost any function can be economically programmed. However, problems with sensor reliability and calibration, and actuation still exist. Each of these problem areas is discussed in this paper.

In summary, the purpose of this paper is: (1) to describe the use of a computer controlled rig, (2) to describe the problems the authors have experienced during three years of computer controlled drilling, (3) to present possible solutions to these problems, and (4) to discuss the future for field use of computer controlled drilling.
Vertical Permeability Determination From Pressure Buildup Tests in Partially Perforated Wellsa
Authors: Barnum R. S. , Frederick K. A.
Published: December 2007

This paper describes a new analysis technique for determining vertical permeability from pressure buildup data in partially-perforated wells. The method applies when the vertical permeability is low enough that the Horner straight-line region characteristic of the perforated interval exists. A correlation chart is presented that relates the vertical permeability to the dimensionless pressure group (P* " Pi)/m, the percent completion, and a dimensionless time based on the flow duration, rock and fluid properties, and the thickness of the perforated interval. The variable m is the slope of the straight line corresponding to the perforated interval, p* is the extrapolation of this line to infinite shut-in time, and p,- is the initial reservoir pressure. Two simulated pressure buildup responses are presented and discussed to illustrate the technique.
Field Evaluation of New Treating Technique To Recover Permeability Damaged by Polymeric Materials
Authors: Dalrymple E. D. , McFatridge D. G. , Zeltman T. A.
Published: December 2007

A recently developed treatment technique has significantly increased injectivity rates of injection wells which had been damaged by near-wellbore polymer blockage.

Polymer blockage can be caused by incompletely dissolved solid polymer, improperly inverted emulsion polymer, and/or deposition and adsorption of the polymer on the rock. Strong oxidizers such as hydrogen peroxide or sodium hypochlorite are typically used to clean up polymer deposits left after polymer injection; however, both of these chemicals present significant handling hazards. The treatment technique presented in this paper utilizes a solid oxidizer which releases a peroxide to dissolve the polymer deposits.

Field tests in Hockley County, TX, yielded injectivity rates more than double those recorded before treatment. The wells consisted of open-hole San Andres sections, at 4,850 to 5,050 ft (1,478.3 to 1,539.2 meters), with a bottom-hole temperature of 100°F (37.8°C). The polymer project was conducted from 1984 to 1986.

This paper discusses the solid oxidizer treatment technique and presents case histories and laboratory results.
Makeup Determination and External Testing of Internally Plastic-Coated Tubing Connections
Authors: Traweek J. B. , Nini C. J. , Gardenier D. , Hasha B.
Published: December 2007

Tests were run on 2 3/8", 4.7 #/ft, J-55, 8-round, EUE, IPC tubing connections using data on position and connection strain to determine the proper torque to use in making up the connections with a Teflon thread compound. The tests were also used to determine if external testing Causes any connection or coating damage by further compressing the pin which is already in compression from being made-up.
Compositional Simulation of the Coyanosa Wolfcamp Field Gas Cycling Operation
Authors: Kim J. S.
Published: December 2007

The Coyanosa Wolfcamp Field, located in Pecos County, Texas was discovered in September 1962. The reservoir rock is comprised of poorly sorted, coarse-grained heterogeneous conglomerates with thinly interbedding shaly limestones.

The dew point pressure of the Gas Unit reservoir ( representing about 80% of the Coyanosa Wolfcamp Field pore volume ) was 6,179 psia at a reservoir temperature of 175°F. The initial reservoir pressure was 6,700 psia. Mobil initiated a gas cycling operation in August 1964.

The condensate yield has declined steadily during the lean gas cycling operation. A compositional simulation study was undertaken to simulate complex mass transfer and composition changes. The study's objectives were to estimate the remaining condensate reserves and to determine an efficient depletion scheme including an optimum reservoir blowdown timing.

After matching the past 23 years of the product-ion history, the model was then used to predict future performance under the various operating scenarios.The sensitivity of liquid recovery to pressure, rate and degree of cycling was investigated. Depletion plans such as added compression, partial cycling and immediate blowdown were evaluated to devise an optimal operation plan.
New Stimulation Techniques Improve Canyon Sand Gas Production: A Case Study
Authors: Pferdehirt D. J. , Brown J. E. , Rucker L. R.
Published: December 2007

It is an established fact that the Canyon Sand Formation in the Val Verde Basin must be fracture stimulated to exploit the reservoir's potential. However, in the past, the degree of stimulation required has been a judgement call at best. Due to recent results from an industry consortium dealing with conductivity, it became obvious that many past stimulation designs were inadequate. Changes in fracturing fluids, as well as proppant selection, concentration, and placement, have led to an improved design.

Past treatments were insufficient in fracture half-length and conductivity. These treatments have now been modified to double the fracture half-length, and to increase the conductivity six-fold. These design changes are necessary to overcome fluid damage and long-term conductivity deterioration. Computer simulated fracturing programs have been used to develop improved designs. When implemented in the field, these designs have proven to increase profitability through post-frac production results.

Although previously reported laboratory work has addressed the topic of in-situ fracture conductivity, these findings were not substantiated with actual production results. Therefore, a case study of twenty four wells located in Sutton County, Texas was performed to determine the actual effect of fracturing fluid type on well performance. A comparison of post-frac well production indicates that different fracturing fluids can dramatically effect a well's producibility. This case study supports the consortium's findings, that different fracturing fluid types create varying levels of permeability impairment.
Use of Stuck Pipe Statistics To Reduce the Occurrence of Stuck Pipe
Authors: Weakley R. R.
Published: December 2007

The occurrence of stuck pipe can significantly increase the cost of drilling, decrease, if not eliminate, the success in reaching objectives, and negate attempts to retrieve valuable formation evaluation data. We have developed many tools and techniques in the oil field to solve problems such as stuck pipe after they occur, but the real key to savings and success is in the avoidance of the problem to begin with.

Approximately 600 wells were analyzed throughout the Gulf Coast and this survey included trouble free wells and those which had experienced differential and mechanical sticking as well. From this data, we are able to predict the environments which are likely to have a high risk of stuck pipe occurrence. Once knowing the risk factors, we are able to either design the well to avoid the high risk situations or to plan for it accordingly.

The results of this statistical analysis will be presented in a simple format which enables one to estimate the risk of occurrence for a given well. Use of the information for both well planning and the successful execution phase will be explained and demonstrated. Examples of the occurrence of problems when entering the high risk areas will also be illustrated. During the course of drilling some 100 wells, with attention to the guide lines to be presented, only eight incidences of stuck pipe were encountered.
Light Oil Recovery from Cyclic CO2 Injection: Influence of Gravity Segregation and Remaining Oil
Authors: Thomas J. , Berzins T. V. , Monger T. G. , Bassiouni Z.
Published: December 2007

This paper presents results of an experimental and numerical investigation of the CO2 huff ‘n’ puff process for the enhanced recovery of light oil. The objective of the investigation was to increase our basic understanding of the process by examining the effects of a gas cap, gravity override, and remaining oil saturation on oil recovery.

In laboratory corefloods, the CO2 huff ‘n’ puff process was physically modelled using Berea sandstone with live and dead oil systems. Live oil was used in a vertical core at pressures above and below the bubble-point to study the influence of a gas cap. Stock tank oil was used in horizontal cores at immiscible conditions to study the effects of gravity segregation and remaining oil saturation. The cyclic process was also modelled using a three-dimensional fully-compositional reservoir simulator. Coreflood and numerical simulation results indicate that the presence of a gas cap, gravity segregation and higher remaining oil saturation improve process performance.
Characterization of Fracture Networks from Well Tests Using a New Analytical Solution
Authors: Corre B.
Published: December 2007

This paper describes the first direct evaluation of various parameters of a fractured reservoir such as fracture compressibility, matrix block size and anisotropy of the fracture network. A new analytical solution is derived which reflects both double porosity and partial perforation effects. This technique is applied to an actual field to evaluate its applicability and reliability.

The field is dolomitic and intensely fractured as shown by well logs and cores. The fissure networks are partially injected with anhydrite. All the well tests studied here present double porosity behaviour which is sometimes reduced to a slight inflexion of the derivative curve.

Matrix block size and fracture compressibility are inferred from a double porosity matching. Several wells exhibit also an effect of partial perforation: in this case, the new technique developed in this paper makes it possible to calculate the vertical permeability of the fracture system.

The results show that:

The reservoir is composed of two distinct fracture networks. The typical block size of the most conductive network is in the order of ten to one hundred meters and that of the less permeable one is in the order of one meter. The vertical anisotropy kv/kh of the fracture networks varies from 0.01 to 0.22.depending on the matrix block size. An isopach of the fracture compressibility was produced for the whole field which reflects the presence of anhydrite.

All the observations mentioned above are supported by geological considerations.
Practical Transient Multilayer Test Design, Implementation, and Analysis of Gas Wells in the North Sea Southern Basin
Authors: Rapach J. M. , Jefferies R. , Guedroudj A. H. , Westaway P. J.
Published: December 2007

Traditional pressure drawdown and build-up analysis of well tests in layered reservoirs has in many cases proven inadequate to describe layer parameters. Without a proper layer description which includes, pressure (Pe or Pr), permeability-thickness (KHl), Darcy skin (Sl), and non-Darcy skin (Dl), future well performance cannot be accurately described.

An innovative procedure was developed for gas wells in the North Sea Southern Basin to provide individual layer parameters in commingled, layered reservoir systems. The procedure incorporates pressure Transient Multi-layered Testing (TMLT) within the procedural framework of a Flow-After-Flow (FAF) test, utilising both wellbore pressure and layer rate transients. The TMLT technique has been successfully performed using a personal computer on 4 wells producing from the Rotliegendes sands in the Virgin condition 4V-Field wells, Vanguard 49/16 -Q03/08 and Vulcan 49/21-R06/06, and from the mature producing Victor field, wells 49/22-JD03/03Z and 49/22-JD05/05. Furthermore, the procedures and analysis for TMLT have been successfully executed in these wells despite layer boundaries, differential layer pressures, and problems/uncertainties inherent in spinner-determined flowrates.
Reservoir Variability and Modeling with Fractals
Authors: Crane S. D. , Tubman K. M.
Published: December 2007

An important factor in the simulation of reservoir performance is the input reservoir parameters. Layers are often modeled with constant parameters (porosity, permeability, etc.) or with only minor variations. The failure to incorporate appropriate heterogeneity into reservoir performance predictions can be a significant problem.

This paper examines the variability in reservoir parameters as measured with wireline logs. Both vertical and horizontal well data are utilized for this purpose. The nature of the log variability in both a sandstone and a carbonate reservoir are evaluated using rescaled range (R/S) analysis in conjunction with power spectrum analysis, similar to the methodology of Hewett et al. The R/S analysis yields a fractal dimension that can be used to model the reservoir parameters. Both vertical and horizontal well log data can be characterized as fractional Gaussian noise of similar fractal dimension.

Fractal reservoir realizations are generated using Fourier transform techniques. This technique is straightforward and successfully maintains the desired spatial dependencies of the data. The fractal dimension is derived from the results of the statistical analysis. Some potential problems with this determination will be highlighted and discussed.

Examples of simulation results demonstrate improved reservoir performance predictions using the fractal realizations. Reservoir sweep efficiencies are altered and a different recovery performance is obtained relative to linearly interpolated realizations.
The Design, Development, and Field Testing of a Water-Cut Meter Based on a Microwave Technique
Authors: Yang Y. S. , Scott B. N. , Cregger B. B.
Published: December 2007

This paper will describe a new and unique instrument to accurately determine the water-cut of an oil-water emulsion. The basic principle of the measurement is based on a novel technique, commonly called oscillator load-pull, which detects the microwave characteristics of the emulsion. This measurement technique will be described simply and concisely. The design and development of the measurement pipe section and the necessary microwave oscillator source and control electronics will be discussed. Laboratory calibration data for the microwave water-cut meter will be presented. Installation of the instrument at a production facility will be described and field test results will be presented. Performance of the microwave water-cut meter will be compared to other water-in-crude determination methods including distillation and centrifugal separation.
An Inhibited Mud for Drilling Water-Sensitive Pay Zones
Authors: Hendrickson G.E.
Published: December 2007

Description of a water-base mud suitable for drilling, completing, of working over water-sensitive pay sands is given. This mud is inhibited by using salt, lime, and caustic soda so that its filtrate will not swell colloidal material with which it comes in contact within the pay sand. Conventional electric log can be run in this mud.

Introduction

A water-sensitive pay sand is one that has its permeability more or less destroyed when invaded by the filtrate from a conventional water-base mud. This destruction of permeability is not reparable under reservoir conditions by any known method. In Oklahoma most Pennsylvania sands, of less than 125 millidarcies, came under this classification. The amount of damage to the permeability caused by mud filtrate invasion seems to vary directly as the time the mud is on the pay zone and inversely as the permeability of the sand. Sands having permeabilities of 125 millidarcies or more are damaged to some extent but will usually clean up in a short time. Sands of approximately 60 millidarcies can usually be drilled and a drill stem test taken before much harm is done, but by the time pipe is set and the well completed, 25 to 50 per cent of the permeability will be lost. Sands of 30 millidarcies or less are, as a rule, blocked off by the time the well is completed and will not produce their full capacity on drill stem test.

The Cisco Sand field, near Frederick, Okla. was developed during 1951. The Cisco Sand is of Pennsylvanian age and is found at a depth of 2,800 feet. Its thickness varies from 10 to 25 feet and, from cores, the average permeability is 30 millidarcies. There are 35 wells in the field and none of them ever made more than a show on drill stem test, or more than a few barrels per day upon completion and before hydraulic-fracturing. After hydraulic-fracturing, these wells were completed for 200 to 300 b/d, natural flow. This is evidence that the conventional mud used in drilling almost completely blocked off the sand by the time the sand was drilled.

A semi-wildcat well drilled in the West Bradley field, near Lindsay, Okla., encountered the Hart Sand of Pennsylvania-age at about 8,000 feet. On drill stem test, this sand produced oil at the rate of 100 b/d. Based on this information and the thickness of the pay of 11 feet, several thousand barrels were set up as a reserve for this zone. The well was completed in a lower zone and the Hart Sand was not protected with cement. A year later, it was decided to test this sand and after squeezing, gamma ray, one oil squeeze and two hydraulic-fractures, no production could be obtained. This is a case where the mud had been on the sand for a long period of time. Examples like this are numerous.
Prediction of Separator Performance Under Changing Field Conditions
Authors: Choi M. S.
Published: December 2007

Over the life of a production system, the separator is expected to process a wide range of produced fluids. With break through from water flood and expanded gas lift circulation, the produced fluid water cut and gas-oil ratio is ever changing. In many instances, the separator fluid loading may exceed the original design capacity of the vessel. As a result, many operators find their separator no longer able to meet the required oil and water effluent standards, or experience high liquid carry-over in the gas. This paper describes a program developed to predict the effects that changing fluid conditions have on the performance of an existing three-phase separator. The procedure and computerized tools may be used for strategic planning when initiating pressure maintenance or artificial lift programs, or to optimize operating parameters of the vessel to yield the best effluent qualities.
Minifracture Analyses and Stimulation Treatment Results for CO2-Energized Fracturing Fluids in South Texas Gas Reservoirs
Authors: Juranek T. A. , Llewellyn M. T. , Drescher G. P. , Tan H. C. , McGowen J. M.
Published: December 2007

CO2-energized fluids can offer advantages over conventional fracturing fluids. However, quality control and design optimization become more difficult with gasified fluids. Minifracture analysis, a valuable tool in optimizing conventional fracturing fluid designs, has not been previously extended to energized fluids.

Minifracture treatments with fluids containing 25% to 70% CO2 were performed on three case wells in Montgomery and Webb counties in south Texas. Data and results from these treatments are detailed in this paper. Significant thermal and compressibility effects were observed during the minifracture pressure declines. An analytical technique which corrected for these effects was used to estimate fluid leakoff based on pressure decline behavior. Improved stimulation results were obtained by redesigning the treatments based on the calculated leakoffs.
An Approach to Reservoir Management
Authors: Wiggins M. L. , Startzman R. A.
Published: December 2007

Many petroleum reservoirs are not developed and produced properly. This failure can be the result of poor reservoir operations management. An understanding of reservoir management and its elements is needed to effectively exploit petroleum reservoirs. This paper defines reservoir management and proposes a comprehensive, integrated approach to the management of reservoir operations.

The paper does not address the many technical details of reservoir management, nor does it give detailed recommendations for particular operations. It presents a method and approach to making these decisions for any reservoir. Its purpose is to communicate the importance of reservoir management and to present an approach for the development of a reservoir management plan.
Data Acquisition and Analysis for Efficient Reservoir Management
Authors: Raza S. H.
Published: December 2007

Timely acquisition of judicious amounts of data and their continual evaluation are foundational to sound reservoir management. To ensure technical success and to avoid economic waste, an experienced multi-disciplinary team should have ongoing responsibility for identifying and acquiring these data from all available sources, assessing their quality and representability, and evaluating (analyzing, reducing, and synthesizing) them properly and consistently.
Engineering Salary Trends in the Petroleum Industry
Authors: Lancaster D. E. , Brown D. C.
Published: December 2007

Results of the October 1989 SPE Member Salary Survey indicate an increase of about 3 to 4% in salaries received by SPE members over salaries reported in October 1988. Results of the 1990 SPE Starting Salary Survey reflect an increase in starting salaries accepted by B.S. graduates in petroleum engineering to $3,050/month. This figure is up 5.2% from a year ago.