bluuebunny/crossref_metadata_2025 huggingface dataset:
Modular Calculations, An Aid in Oil Well Completion Design
Authors: Mantooth M.A.
Published: December 2007

A computerized method for calculating well productivity was used to study ten gravel- packed inner liner completions in the Louisiana packed inner liner completions in the Louisiana Gulf Coast area. Used as a performance- diagnostic tool, the method produced estimates for certain unknown completion parameters from known productivity information, revealing which factors might have contributed to the productivity impairment. A sensitivity study productivity impairment. A sensitivity study of completion design parameters showed that clean, high-permeability gravel placed in deep penetration of 1/2 in. diameter or larger penetration of 1/2 in. diameter or larger size perforations are necessary for maximum production from this type completion. production from this type completion

Introduction

Gravel-packed inner liners are extensively used in the Louisiana Gulf Coast area as a means for the controlling sand production from unconsolidated or poorly consolidated formations. Our experience, however, shows that this method of sand control is not infallible, owing mainly to two problems:poorly designed gravel packs are often ineffective in stopping sand packs are often ineffective in stopping sand production; andpack installations are production; andpack installations are usually accompanied by productivity impairment.

The first problem is mechanical, which can be overcome only by improving the operating procedures, such as gravel placement and size procedures, such as gravel placement and size selection. The second problem is more difficult to solve because any installation of a downhole device produces an additional resistance to flow, impairing productivity. The best that can be done with this problem then is to minimize the impairment through judicious selection of completion parameters under a given set of design restrictions. This requires a thorough understanding of how the various completion and reservoir parameters, individually or in combination, affect the productivity of a given well.

This paper discusses an attempt to understand the relationship between productivity and certain design factors for gravel-packed inner liner completions and to learn the best approaches to improving the completion design. A computerized analytic method developed at Chevron Oil Field Research Company was used for this study.
Optimizing Waterflood Recovery in a Mature Waterflood, The Fullerton Clearfork Unit
Authors: Stiles L.H.
Published: December 2007

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

After a detailed study of 12 years' performance of the Fullerton Clearfork performance of the Fullerton Clearfork Unit, a special study group recommended major operating changes which will increase ultimate oil recovery 22 million barrels. New techniques included a simplified waterflood model and a statistical approach to measure reservoir continuity. Evaluation of alternate plans with these tools indicated the plans with these tools indicated the need for infill drilling and a closer spaced pattern.

Introduction

Location and Geology

The Fullerton Field is located in west Texas in Andrews County, 50 miles north-west of Midland as shown on Figure 1. Geologically, the field is located in the northeastern part of the Central Basin Platform Area, and lies in a north-west-southeast trend of Permian carbonate production stretching for more than 100 miles. Figure 2 is a structure map which shows the northwest-southeast trending, anticline with approximately 400 feet of relief on top of the Clearfork formation. There are two prominent structural domes on this feature with the North Dome being much the larger of the two. The Fullerton structure continues northward from the Unit boundary and is productive in the adjacent, but separately prorated Union Field. Discovery was in 1942 and was followed by rapid development during the next five years with 565 wells completed by 1947. Development continued throughout the 1950's and 1960's with sporadic development up to the present time.
Preparation and Testing of Partially Hydrolyzed Polyacrylamide Solutions
Authors: Foshee W.C. , Jennings R.R. , West T.J.
Published: December 2007

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

The evaluation of a mobility control polymer requires; that proper laboratory techniques be followed if meaningful results are to be obtained. New procedures are presented and existing procedures are reviewed to aid in the procedures are reviewed to aid in the measurement of properties related to performance of polyacrylamide solutions. In addition to polyacrylamide solutions. In addition to mixing and filtration techniques, the measurement of polymer concentration, thermal stability, core testing, and other factors relating to mobility control in the reservoir are discussed.

Introduction

Polymers are being widely used to provide Polymers are being widely used to provide mobility control in secondary and tertiary oil recovery processes. Large quantities of polymer are required for these processes and it is imperative that adequate, but not excessive, quantities be used to insure the economic success of these processes. To accomplish this, it is necessary that sufficiently accurate laboratory core data be developed to permit optimum mobility bank design.

This paper will describe the elements of such a laboratory testing program. It will be organized into three sections:Solution PreparationCharacterization of Polyacrylamide Solutions.Polyacrylamide Behavior in Field Core Specimens

In Section I, procedures will be given to dissolve polymers properly in stable analogs of the natural field brines. Section II continues with methods to assess the properties (screen factor viscosity and thermal stability) of polyacrylamide dissolved in brine. It also contains polyacrylamide dissolved in brine. It also contains a new analytical method to determine the polymer concentrations in oil field brine. The last section describes tie techniques used to measure polymer solution behavior in actual field core specimens.

The procedures presented are the results of hundreds of core tests using water soluble polymers. Although this paper is not a polymers. Although this paper is not a complete reference manual, an attempt has been made to cover many of the critical points. A topical sentence has been underlined to identify recommended standard procedures in Section I and in Section II where alternative procedures are also discussed. It is hoped that the procedures are also discussed. It is hoped that the methods presented might be considered as the first step in setting standards for resistance factor determinations.
Historical Problems with Old Field Rejunvenation
Authors: Blaskovich F. T.
Published: December 2007

In many parts of the world, the redevelopment of older fields presents unique problems that will require innovative solutions. With the rising costs of finding and developing new oil fields, oil companies are turning more attention to revitalizing existing fields. Because of historical practices, these fields often have significant potential for enhanced recovery. These older fields have many different problems to deal with than the more modern fields that traditionally drive petroleum technology.

Advances in computer hardware and software technology have made it possible to analyze reservoirs at a level of detail unimagined only a few years ago. With all of this power on our desktops, it is easy to lose sight of a major problem in dealing with older fields - the historical data.

In many cases, there may be a large amount of historical data, but much of it is either inaccurate or critical types of data have not been gathered. Several field examples are discussed in this paper. Each field has redevelopment potential using modern techniques, but each project has great uncertainty due to data constraints. The conclusions and recommendations of the paper include suggestions for ways to solve these problems. Since we cannot go back in time to gather critical missing data (e.g., early production and injection data, initial fluid properties, produced compositions, etc.), special techniques will be needed to determine the value of these projects.
Application of a Point the Bit Rotary Steerable System in Directional Drilling Prototype Well-bore Profiles
Authors: Schaaf Stuart , Pafitis Demos , Guichemerre Eric
Published: December 2007

Recent trends in the oil industry are requiring higher degrees of accuracy in the placement of boreholes, while improving overall rates of penetration. In addition to reducing overall drilling costs, several technical reasons can be cited. These include: Increasingly complex directional well trajectories designed to drain more of the reservoir; accurate build rates and precise landing of horizontal wells; accurate horizontal control for steering relative to an interface or to reduce undulation in extended reach wells.

Rotary steerable systems have been introduced in the past few years to respond to these more complex requirements. These systems have shown the potential for reducing the costs of drilling while providing improved directional control. Elimination of sliding increases rates of penetration, provides better hole cleaning, smoother boreholes, less chance of differential sticking; and the ability to drill further. Schlumberger has developed a new rotary steerable system, which functions on a point-the-bit principle. The system has no non-rotating or stationary parts in contact with the formation. The system is implemented in a 6 ¾-inch platform and operates in bore-hole diameters between 8 3/8-inch and 9 7/8-inch.

This paper will present an overview of the new point-the-bit system. Benefits of the system will be discussed. Case studies from two wells will be presented. The presentation will discuss the well objectives, the plan implementation, and include operational highlights and issues. Project results and improvements in implementation will be presented with discussion on how the system was utilized to insure value-added savings.
Comprehensive Reservoir Modeling of a Mature, Geologically Complex Reservoir
Authors: Pawar RJ , Edwards EB , Coombs SF , Whitney EM
Published: December 2007

The Carpinteria Offshore field in the Santa Barbara channel is a geologically complex, mature reservoir. Over the past years production has declined due to increased water cut and sand production from unconsolidated zones. The current operator of the field, Pacific Operators Offshore Inc. (POOI), a small and independent producer joined with Los Alamos National Laboratory in a joint research program. The purpose of the program was to use advanced computational tools to improve understanding of the field geology and fluid dynamics. No comprehensive model of the field was available prior to this project. As part of the project, a geologic model that integrated the legacy data was developed. The model was used to develop a reservoir flow simulation model for a part of the field. The model was used to qualitatively understand field fluid dynamics. Subsequently, geostatistical techniques were used to characterize the spatial heterogeneity in reservoir rock properties. Multiple realizations were generated for individual rock properties and the uncertainties associated with the property distributions were quantified. The geologic model has been extensively used by POOI during planning stages of a field redevelopment program. The newly drilled wells have dramatically increased the production from the field. The increased production has been tremendously helpful for the company during the recent oil production shortage.
Detailed Clastic Maps from Intense Log Data Extractions and Advanced Sedimentation Analysis
Authors: Allen Rob L.
Published: December 2007

Major changes were made to conventional mapping procedures. Hundreds of map input values are usually extracted from an interval of interest on each log instead of using an averaged sand thicknesses or a few other properties. Reversible wave, current, gravity, partial derivative, and particle dispersion mathematics are used to model sedimentation processes. Log pattern inversions combined with the above sedimentation emulation technologies have been used to create much more detailed maps of depositional systems.
Implementation of Fracture Calibration Equations for Pressure Dependent Leakoff
Authors: Meyer Bruce R. , Jacot R. Henry
Published: December 2007

Nolte originally developed a pressure decline analysis method to provide an estimate of the fluid efficiency, closure pressure, fracture geometry and leakoff coefficient. The Nolte method of pressure decline analysis has become a standard for fracture calibration in the industry. Implementation of a proper calibration test is critical for the successful design and evaluation of hydraulic fracturing treatments.

Although Nolte's original work has many simplifying assumptions regarding fracture closure (e.g., constant leakoff coefficient, no spurt, no fracture growth after shut-in, constant compliance, etc.) it still provides the foundation for the basic first order parameters affecting pressure decline behavior.

The assumption of pressure independent fluid loss may have an adverse affect on the pressure decline analysis if leakoff is controlled by the filtrate viscosity and/or reservoir compressibility and mobility effects or fissure opening effects. An improved procedure is presented for identifying and implementing pressure dependent leakoff. This methodology is formulated from the generalized Nolte G function approach utilizing a dimensionless pressure function based on the original work of Castillo for a pressure dependent leakoff coefficient and Barree for naturally fractured reservoirs. The procedure first makes use of the standard Nolte analysis to identify the presence of pressure dependent leakoff, and then establishes the appropriate leak-off pressure dependent parameters by matching the pressure decline behavior. Deviation of the measured data from the dimensionless pressure function versus Nolte G time indicates closure. The methodology also utilizes the first derivative and pressure superposition derivative to help identify and quantify closure.

Guidelines are presented to identify cases where pressure dependent leakoff should be considered. Implications of neglecting pressure dependent leakoff or using a pressure dependent leakoff coefficient improperly are addressed. The governing equations and field examples are presented for clarity.
Characterization of Spontaneous Water Imbibition into Gas-Saturated Rocks
Authors: Li Kewen , Horne Roland N.
Published: December 2007

Spontaneous water imbibition into gas-saturated rocks is an important physical process during water injection into highly fractured petroleum and geothermal reservoirs. Few methods, however, are available for characterizing the process of spontaneous water imbibition into gas-saturated rocks. To this end, a method has been developed. Water relative permeability and capillary pressure can be calculated separately from water imbibition data using this method. A linear relationship between imbibition rate and the reciprocal of the gas recovery by spontaneous water imbibition was found and confirmed both theoretically and experimentally, even at different initial water saturations. The effect of initial water saturation on imbibition rate, residual gas saturation, and the gas recovery has been investigated. There was almost no effect of initial water saturation on residual gas saturation by spontaneous water imbibition. The higher the initial water saturation, the lower the water imbibition rate and the ultimate gas recovery. It was found that the capillary pressure did not vary with initial water saturation in a certain range. The capillary pressure calculated using the new method was approximately equal to the values measured using an X-ray CT technique in a glass-bead pack. The computed water relative permeability was consistent with published experimental results. The method developed in this paper is also of importance for scaling-up experimental data.
Approximate Finite Difference Modeling of the Performance of Horizontal Wells in Heterogeneous Reservoirs
Authors: Yeten Burak , Wolfsteiner Christian , Durlofsky Louis J. , Aziz Khalid
Published: December 2007

A simplified representation of reservoir heterogeneity is applied to the finite difference modeling of horizontal wells operating under two phase flow conditions. The heterogeneity model, referred to as the s-k* approach, was developed and applied in earlier studies for single phase flow scenarios. The model represents heterogeneous permeability fields in terms of a constant background permeability k* and a variable skin s, which captures the effects of near-well heterogeneity. This simplified permeability representation is applied to the modeling of multiple realizations of heterogeneous permeability fields characterized by three different sets of permeability statistics. Comparisons to simulation results using the detailed permeability field and to results using a homogeneous permeability field are presented. The s-k* permeability representation is shown to provide an accurate means of representing reservoir heterogeneity in models of horizontal well performance. Integrated quantities, such as well productivity index, are captured with better accuracy than are more local quantities such as water cut. The s-k* models are more accurate than the homogeneous models in all cases considered. The use of the new modeling approach for the coarse scale modeling of horizontal well performance is also demonstrated.
An Experimental Investigation of Permeability and Porosity Alteration in Diatomite During Hot Fluid Injection
Authors: Kovscek A. R. , Diabira I. , Castanier L. M.
Published: December 2007

A study of silica dissolution has been performed to probe the evolution of permeability and porosity in siliceous diatomite during hot fluid injection, such as water or steam flooding. Two competing mechanisms were identified. Silica is soluble in water at elevated temperature causing rock dissolution and thereby increasing permeability; however, the rock is significantly compressible leading to compaction of the solid matrix during injection and the loss of permeability and porosity. A laboratory flow apparatus was designed and built to examine these processes in diatomite core samples. At the core level, we measured the pressure drop as a function of time to determine the permeability variation and utilized an X-ray Computerized Tomography (CT) scanner to measure porosity. At the pore level, a scanning electron microscope (SEM) was used to observe changes in pore morphology. We found that porosity decreased initially due to compaction caused by the imposed pressure drop across the core. Later, porosity increased as silica dissolved. Dissolution of the rock matrix was relatively uniform in that wormholes were not observed even after tens of pore volumes of fluid injection.
Burst Induced Stresses in Cemented Wellbores
Authors: Fleckenstein W. W. , Eustes A. W. , Miller M. G.
Published: December 2007

The industry acknowledges that there is an increase in the burst resistance of cemented pipe vs. uncemented pipe; but the effects of cement and formation mechanical properties, and insitu stresses are not well understood. This paper presents the results of a finite element study of the resistance of casing to internal burst pressure under a variety of conditions. This will provide for better design understanding of the stress conditions developed in casing under burst loading.

Two-dimensional stress distribution model results are presented in graphical and tabular format for a variety of geometrical and mechanical material properties of formations, cement slurries, and casing combinations.

A better understanding of the true stress profile in cemented pipe will allow for less expensive decisions concerning casing design parameters and safety factor criteria. Applications of using the burst resistance of the cemented pipe as a system as opposed to using the burst resistance of free pipe can include deeper drilling with thinner walled pipe, smaller rigs, and better casing integrity decisions for refracturing candidates.
Vertical Permeability from In-Situ Horizontal Permeability Measurement in Shaly Sand Reservoirs
Authors: Zahaf K. , Tiab D.
Published: December 2007

The oil industry has become more and more aware that reservoirs exhibit complex variations of reservoir continuity, in particular of pore space-related properties such as porosity, permeability, and capillary pressure. These variations reflect the original depositional process and subsequent diagenetic and tectonic changes. Simple models are often inadequate for predicting reservoir performance and designing a field production management scheme that optimizes recovery. It is becoming increasingly apparent to reservoir engineers that the optimization of recovery is crucially dependent on the quality of the reservoir under water injection where the recovery factor is very sensitive to reservoir heterogeneity. Therefore, an accurate knowledge of vertical and lateral permeability distribution is essential.

This paper represents results of a research project aimed at determining vertical permeability from in-situ horizontal permeability in shaly reservoirs. This is accomplished by considering the microscopic and macroscopic features; such as the type of shale (Kaolinite, Chlorite, and Illite) and grain size. In-situ vertical permeability correlations are derived by using various water saturation correlations for Shaly-Sand formation.

Several vertical permeability relationships were obtained as function of horizontal permeability, hydraulic mean radius grain size, and the amount and/or type of shale. Generalized models were developed and were applied to real oil field data for calculating vertical and horizontal permeabilities.
The Top 10 Reasons to Rethink Hydraulics and Rheology
Authors: Zamora M. , Roy S.
Published: December 2007

After a century of need, the drilling industry finally has the tools to properly analyze and optimize drilling fluid hydraulics. This is indeed fortunate, because most unscheduled trouble events in drilling are still hydraulics related. Emerging results from these tools and recurring field problems and challenges provide many good reasons to rethink drilling hydraulics and rheology, especially in critical-well applications. This paper is about the reasons that made the Top 10 list.

Real-time downhole pressure measurements, powerful / inexpensive computers, and quality HTHP / LT viscometers are among the most notable new diagnostic tools. Individually and collectively, they continue to remind the industry, for example, that downhole mud properties are different than those measured under surface conditions. Failure to compensate for significant differences in density, rheology, pressure loss, and other parameters can cause great difficulties, especially in wells drilled in HTHP and deepwater environments.

Items in this Top 10 list cover a wide range of hydraulics and rheological issues. Some focus on specific well conditions, some address new findings, and others dispel long-standing oilfield paradigms. All are practical and useful for solving common and unique well problems. Field examples are given where appropriate.
Experiments in Fluid Loss and Formation Damage with Xanthan-Based Fluids While Drilling
Authors: Navarrete R. C. , Dearing H. L. , Constien V. G. , Marsaglia K. M. , Seheult J. M. , Rodgers P. E.
Published: December 2007

Formation damage is a concern when attempting to control fluid loss during drilling operations. The usual approach is to use bridging agents and high polymer loadings to reduce fluid loss. However, these additives contribute to formation damage. In this paper we explore the fluid loss characteristics of xanthan-based fluids, including starch and calcium carbonate, during the drilling process. Fluid loss while drilling is a complex process where fluid is lost underneath the bit and through the surface of the wellbore. A unique laboratory scale drilling simulator was used to determine the leakoff and formation damage of xanthan-based drilling fluid formulations. The fluid was circulated as in a conventional drilling operation, through the microbit and up the annulus under overbalanced conditions. Thin section analysis and environmental SEM were performed on rock samples to identify the different components of the fluid system. Sandstones up to 1,000 md were used. Cleanup sequences, which include enzymes and oxidizers, were also evaluated after the cores were drilled. The cleanup efficiencies were compared to conventional QC-testing techniques used by operators for filtercake removal.

The results showed that most of the fluid is lost underneath the bit in a continuous spurt condition while drilling. The filtercake formed during drilling does not pose a resistance to flow during production, but poses a strong resistance during leakoff. Xanthan gum contributes to fluid loss reduction, while combinations of CaCO3, starch and xanthan gave the lowest leakoff and formation damage. Wellbore soaking procedures do improve production after drilling.
Marvelous Effect of Magnetization on Drilling Fluid
Authors: Gao Changhong
Published: December 2007

Magnetic technology has been widely used in oil fields and other aspects due to its many outstanding advantages. Yet its main utilization lies in oil production and transportation, and little research is done on the magnetized drilling fluid. In this paper, through experiment, it is shown that magnetization can apparently reduce the viscosity and improve the inhibition ability of the mud system.
Underbalanced Drilling Dynamics: Two-Phase Flow Modeling and Experiments
Authors: Lage A. C. V. M. , Fjelde K. K. , Time R. W.
Published: December 2007

A dynamic model, based on the drift-flux formulation, is presented for treating transient phenomena in UBD operations. A set of mechanistic steady state procedures for dealing with the definition of flow patterns, pressure drops, gas volumetric fractions, and in-situ velocities completes the model. The iteration between those mechanistic laws and the conservation equations is discussed. The numerical solution, which presents an easy implementation, uses a composite explicit scheme that properly combines the second order MacCormack and the first order Lax-Friedrichs methods, reducing false oscillations and numerical diffusion. In addition, details about the boundary treatment are also presented.

Model predictions are validated through comparison to full-scale experimental data in two distinct transient situations. First, a typical unloading scenario in an underbalanced operation is studied. Further, the model simulates the injection of a high velocity single pulse and a sequence of two pulses of a gas-liquid mixture. Measured variables as pressure and returning liquid and gas rates at surface are compared to the predicted ones. The comparisons address model limitations and improve the understanding of the physics involved.
Cements for Long Term Isolation – Design Optimization by Computer Modelling and Prediction
Authors: di Lullo Gino , Rae Phil
Published: December 2007

Today, development of high early compressive strength (CS) is a key performance specification for oilwell cementing. Early strength is important to ensure structural support to the casing and hydraulic/mechanical isolation of downhole intervals. Delays in strength development cause significant amounts of lost time due to the need to Wait-On-Cement. Thus, drilling operations cannot proceed and the rig must sit idle until the cement is deemed hard enough to continue.

The actual development of strength in cement systems is dependent on a number of factors. The type of cementitious material is important due in part to chemistry and in part to granulometry. Slurry density is considered critical – lower density has, traditionally, been associated with lower strength. Temperature is a key parameter and, to a lesser extent, the pressure. Less appreciated, is the influence of the many types of additives that are included in slurry formulations. Correct selection of cement and additives allows slurry tailoring to achieve "a strong cement" that will support mechanical stresses that happen during the well productive life. Since cement is the primary means of isolation, its integrity as a sealing material should be paramount.

Under confining pressure, cement compressive strength is several times higher that the values obtained from an unconfined API test. In fact, the ultimate compressive strength of a wide variety of slurries is similar to that of the surrounding reservoir rock, regardless of initial slurry density. In the long term, more important than compressive strength is the ductility/compliance that set cement has to support down-hole stresses imposed by pressure and temperature oscillations during drilling, work-over and production operations. In the vast majority of well operations, cement failure occurs under tensile loading, not under compression. Poor appreciation of this has led to the routine use of higher density slurries for many applications. Such slurries may be not only unnecessary but also positively harmful, since they can produce more brittle cements that fail under downhole stresses. This paper describes a method of designing cement slurries using a simulator that models cement setting and strength development. Instead of obsolete rules of thumb, mechanical properties of set cement, formation and casing responses to cyclic stresses during the well life are used to optimise designs for early times and long term. Finally, a few case histories are presented, demonstrating the benefits of this new design methodology to produce cost effective cement slurries for one isolation.
Zonal Isolation in Stimulation Treatments and Gas/Water Shutoff Using Thermally Compensated Inflatable Packers and Plugs
Authors: Wilson Paul , Hoffman Corey E.
Published: December 2007

This paper provides laboratory and field-test results of a thermally compensated fluid-inflated packer system. This system greatly reduces the chance of sealing-element failure when inflatable packers or plugs are used where the borehole fluid changes temperature more than 50° F (10°C). To date, a primary cause of failure in achieving zonal isolation while using inflatable packers and plugs is the change in temperature of the borehole and inflation fluids once the packer is set. Thermally compensated inflatable packers are an innovation in nflatable packer technology. These packers act in a manner unlike conventional inflatables, which are susceptible to temperature changes as little as 50° F (10°C) between borehole and internal fluids. These temperature changes can cause the fluids inside conventional inflatable packers either to expand and rupture the element or to contract and cause the element to lose its seal on the casing wall. Qualification tests and resulting data will be presented as well as data acquired after a thermally compensated inflatable plug system was deployed in a water injection well. Possible applications include those in which a fluid inflatable packer, straddle acker, or plug would be used and subjected to temperature changes in excess of 50° F (10°C).

The introduction of thermally compensated inflatable packers offers a more technically effective, economical means of zonal isolation in almost any cased-hole application. This technology is equally applicable for openhole applications.
Well Control of an Influx from a Fracture Breathing Formation
Authors: Ashley Paul R.
Published: December 2007

Hydrocarbon influxes into the wellbore while drilling are typically caused by over-pressured formations, where mud weight is insufficient to control the pore pressure of the formation drilled. Formation permeability and over-pressure determine the intensity of the kick. Well kill procedures in such situations are standard industry wide. Shut in drillpipe pressure is used to determine the pore pressure of the formation, and the driller's or weight and wait method is used to remove the hydrocarbon influx from the well. Hydrocarbon influxes associated with fracture breathing are much less common, and methods to deal with such influxes are not taught within the drilling industry. This paper describes two case studies: the first, Bard–1, an exploration well in the Timor Sea, offshore Australia, describes a well control situation that was initially interpreted as over-pressure. The well could only be killed by pumping cement. Investigation showed that the influx mechanism was a fracture breathing and hydrocarbon swap out mechanism. The high mud weights used in the attempt to kill the well actually exacerbated the situation. The second case study, Jura-1 which was located nearby Bard-1, describes design and procedures used to manage a similar influx mechanism. These were implemented successfully enabling the well to achieve its objectives.
The Benefits of Monitoring Torque & Drag in Real Time
Authors: Vos Bart E. , Reiber Frank
Published: December 2007

Monitoring Torque and Drag effects in real time has been done for some time now in the oil industry. However, the service is still used only in a small percentage of the total drilling hours and the analyzing techniques used are quite diverse.

The real-time Torque and Drag technique described in this paper is in many ways advantageous compared to the precalculated hook load (HKLD) and surface torque comparison techniques typically used in the industry. Several delimiters are filtered out of the equation and current drilling conditions are used automatically and directly in the calculations and evaluations. Monitoring Torque and Drag in the described way gives direct information on current down hole drilling conditions and predicts upcoming situations. This allows the driller to go closer to the limit of the drillstring load capacity in a controlled manner, thereby optimizing tool use whilst maintaining safety on the rig.

Combined monitoring of Torque and Drag and the Equivalent Circulating Density (ECD) shows clear correlations, and gives additional information on hole cleaning conditions. The technique also helps to optimize reaming programs - reaming correctly and only when necessary -, to save rig time and improve weight transfer.

Monitoring Torque and Drag in real time is part of a service package that analyzes the available data at the rig-site and converts them into valuable information. This information is subsequently used to improve well profitability by optimizing drilling efficiency and increasing well productivity.
Causes and Remedies of Drillstring Failures while Drilling Medium Radius Horizontal Wells (Field Study)
Authors: Amro M. M.
Published: December 2007

Improvements in horizontal drilling technology made it possible to drill almost in all types and shapes of reservoirs. No change, however, was made in the design of drill pipes to overcome the high stresses especially for drill pipe rotating in medium or short radius horizontal wells. During drilling of some horizontal wells in the Middle East area, an abnormal amount of tubular failure was noticed in the drill string being used.

This paper presents a field case study of drill string failure during drilling of medium radius horizontal wells.

Investigations as well as a metallurgical evaluation were conducted in an attempt to establish the possible causes of the drill string failures. Other possible reasons for drill string failures and suggestions to minimize the bending stress of drill pipes are also discussed.
New Bio-Polymers for Drilling, Drill-in, Completions, Spacer Fluids and Coiled Tubing Applications
Authors: Navarrete R. C. , Seheult J. M. , Coffey M. D.
Published: December 2007

Xanthan gum has been used extensively as a viscosifier in the oil industry for different applications due to its unique rheological properties. In this paper we introduce two biopolymers for use in drilling, drill-in, completions, spacer fluids and coiled tubing applications. The first bio-polymer yields higher viscosities and better temperature stability at lower polymer concentrations that welan and xanthan gum due to its higher molecular weight; this polymer is particularly effective in low salt fluids. The second bio-polymer has improved solubility in high density CaCl2 brines.

Viscosity data over a wide shear rate range is presented comparing the new bio-polymers with xanthan and welan gum at temperatures between 75°F to 300°F. Viscoelastic measurement and settling test are presented to demonstrate the effect of elasticity of the bio-polymers on solids transport and suspension capabilities. Fluid-loss, formation damage tests and friction pressure tests in coiled tubing are also shown.
Development Process and Field Applications of a New Ester-Based Mud System for ERD Wells on Australia's Northwest Shelf
Authors: Eckhout Daniel , Dolan Shane , Gogan Ray , Ledgister Hanjo , Mowat Carol , Tipton Paul , Ewen Bruce , Dye William
Published: December 2007

Extended reach wells drilled from the Goodwyn Alpha platform are highly aggressive and have been drilled with a variety of invert-emulsion mud systems. Historically, mud system selection for these wells was based on compliance to environmental regulations and satisfaction of technical criteria. In order to take a more proactive approach to mud system selection and to raise environmental standards to new levels, an initiative was undertaken to replace the environmentally acceptable, and technically competent mud system being used on Goodwyn with a new ester-based system. Ester-based mud systems are considered the "system-of-choice" in terms of environmental acceptability and possess inherent lubricating qualities for torque and drag reduction.

This paper describes the development process and 4 successful field applications of the new ester-based mud system. A new ester, which exhibits the lowest kinematic viscosity of commercially available esters, was identified and selected for use. New and innovative technologies were introduced in the laboratory development and field applications to address barite sag, hole cleaning efficiency and hydrolytic stability.

The system development and field testing processes were enhanced by daily communication with the development teams in Aberdeen, Houston and Perth. Down-hole friction factors were significantly lower than modeled predictions. Barite sag problems encountered on previous wells were eliminated, and hole cleaning efficiency was optimized.
Jetting Clean-Up of Formation Damage Caused by the Drilling Process
Authors: Way P. W. , Howard P. , Johnson A.
Published: December 2007

We report here a laboratory study that considers the potential of jetting technology for removing formation damage produced in the drilling process.

The effective placement of chemical treatments over long open hole sections is an unresolved problem. The treating chemicals are often lost to the formation in relatively small areas resulting in poor clean-up in large sections of the wellbore. The jetting technique, which has been investigated as part of an on-going research program, could be used with coiled tubing or conventional drill pipe and would provide effective coverage along the whole length of the wellbore. The use of barite as a weighting agent in the drilling fluid rather than calcium carbonate is possible because the material is removed physically and not chemically. This is beneficial as it means that the total solids volume in the drilling fluid is lowered.

We have considered the effects of abrasive laden jetting fluids on two sandstones of differing permeabilities using two water based drilling fluids and two types of weighting agent. Further tests using water only as the jetting fluid are reported

We find that in all cases the jetting removed any external filtercake that was present, and is also capable of removing rock material. On the higher permeability sandstone we see no improvement to the level of formation damage from jetting even with the filtercake removal. SEM studies reveal pore space blocked by particles generated during the jetting process and or by the abrasive material. For the lower permeability sandstone we note an improvement with jetting and no evidence of invaded solids material.

We have further considered the pressure required to initiate flowback after jetting compared with production straight back through the filtercake. We find that the pressure to initiate production is reduced by over 40% for all the fluids tested on both rock types.
Application of Very Heavy Mud and Cement in a Wildcat
Authors: Ezzat A. M. , Jennings S. S. , Al-Abdulgader K. A. , Al-Hammad M. A.
Published: December 2007

Unusual pressure was encountered while drilling through the Triassic lower Jilh formation in a wildcat. The well was one of the deep exploration wells for non-associated gas, in the northern fields, targeting the Permian Khuff and Pre-Khuff gas reservoirs. Mud weight was increased from 80-pcf (10.7 lb/gal) to 156-pcf (20.86 lb/gal) with barite. The drill-string became stuck against the formation above the high-pressure zone. A specially designed spotting fluid was used to disperse the wall cake and free the pipe. Well-killing operation continued with the drill-string inside the casing. Achieving higher mud densities required the use of hematite and phasing out the barite until the well was controlled with 162-pcf (21.66 lb/gal), which is the heaviest drilling mud ever used in Saudi Arabia’s oil fields.

Extensive laboratory work was carried out at the well site. The mud system formulation design was adjusted and maintenance treatment was carried out in timely manner. Drilling operations were commenced safely to the casing point where the temperature exceeded 300°F. Successful bit selection for this interval lead to a New World record run in rotating hours. A 9-5/8" liner was run and cemented with specially designed 170-pcf (22.73 lb/gal) cement slurry, which was also a challenge. The liner was extended to surface and cemented in two stages with 145-pcf (19.39 lb/gal) cement. This paper presents the laboratory data along with the field mud and cement formulations used.
A Newton-Raphson Iterative Scheme for Integrating Multiphase Production Data into Reservoir Models
Authors: Wu Zhan
Published: December 2007

This paper presents a new linearized iterative algorithm for building reservoir models conditioned to multiphase production data and geostatistical data. The significant feature of the proposed algorithm is that the computation of the sensitivity coefficients of production data with respect to model parameters can be avoided. This leads to dramatic reduction of computational cost. Instead of generating the sensitivity matrix as required for the least-squares algorithms, the proposed approach relies on solving the inversion equations which are derived from the necessary conditions for a functional extremum.

It is proved that the proposed method requires considerably less computational effort than the traditional algorithms such as the Gauss-Newton method, the Levenberg-Marquardt method and the generalized pulse-spectrum technique (GPST). This is because the computation of the sensitivity coefficients makes the traditional algorithms computationally intensive. However, for the proposed linearized iterative scheme, the computational requirement only depends on the time steps used in the reservoir simulator rather than the number of parameters or the number of observed data.

The linearized iteration scheme converges fast since the inversion equations can be solved through the Newton-Raphson method. At each iteration, the new approach requires solving the finite difference equations and the linear adjoint equations only once, respectively. Since the solver for the flow equations can be used to solve both the adjoint equations and the inversion equations, the proposed algorithm can be easily applied to commercial reservoir simulators. In this paper, two numerical examples for incorporating water oil rate data into geostatistical models are given to prove the efficiency of the proposed algorithm.
Optimization of Multivariate Production-Injection System for Water-Alternating-Gas Miscible Flooding in Pubei Oil Field
Authors: Yang Daoyong , Zhang Qi , Cui Huanwen , Feng Hu , Li Luhua
Published: December 2007

The first Water-Alternating-Gas (WAG) miscible flooding project, Pubei oil field in Xinjiang, was put into production and scheduled to initially inject miscible gas as well as water at the early development stage. With consideration the specialty of the WAG process, optimization of multivariate production-injection system (PIS) is the Gordian knot of improving the reservoir benefit as well as extending the reservoir life. In general, the production history of a reservoir can be predicted by integrating a reservoir model, and a production model including a wellbore model and a choke model. Changes in any production and/or injection parameter will cause changes in the predicted production and/or injection history.

Well-to-well tracer results were used to modify the reservoir model and evaluate efficiency of WAG during the field development, and novel integrated concepts and methods were proposed to couple the reservoir model with well model including both injectors and producers. The genetic algorithm is shown to be both stable and efficient when used to optimize the multivariate PIS with different constraints. It is shown from field applications that reasonable measures can be adopted for globally optimizing production and injection at the any stage of the field life, and that parameters including bottomhole flowing pressure, reservoir pressure, injection pressure, oil rate, gas-oil ratio, water-cut, etc. were controlled and adjusted in an optimized range.
Using a 3D Stochastic GeoModel to Determine Optimal Infill Potential of a Mature Gas Field: A Case History
Authors: Herweijer J. C. , Barley M. , Chugh S. , Alexander S. , Smith M. , Kuppe F.
Published: December 2007

Discontinuous fluvial sands with highly variable permeability patterns pose a significant challenge for further development of mature onshore gas fields in South Australia. To obtain an optimal strategy for further infill drilling a multi-disciplinary reservoir characterization study was undertaken. This study combined all available data (petrophysics, geology, geophysics, and engineering) into a 3D stochastic geo-model before various upscaling methods could be considered for creating a reservoir simulation model. Coarse upscaling methods were used to match macro-scale reservoir characteristics (e.g. the effective permeability in the well's drainage area) while smaller scale heterogeneity (RFT pressure measurements) were matched using permeability predictors that preserved the observed variability from core data.

Several geological scenarios were designed for the model. These scenarios included various assumptions on sand content of the main producing horizon, sandbody dimensions, the permeability distribution, and continuity of coals acting as vertical baffles. During history matching, some of these scenarios were tested as alternatives in pursuit of a history match. Scenarios were refined/rejected and/or iterations made to re-assess the data. The history matching procedure revealed the significance of outlier permeability streaks as conduits to effectively drain reserves. The study was conducted under the constraints of a fairly tight operational schedule to meet a development drilling deadline. Drilling locations and the associated economic evaluations were based on simulated forecasts from a number of stochastic realizations/scenarios while connected volume calculations were made for a larger number of realizations.