bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental Investigation Into Revaporization of Retrograde Condensate
Authors: Luo Kai , Li Shi , Zheng Xitan , Chen Gang , Liu Ning , Sun Wenyue
Published: December 2007

A high condesate saturation ring usually forms in a gas condensate reservoir where pressure decreases below the dew point, especially around the wellbore. Gas injection/cycling is a main recovery process of choice for preventing loss of valuable condensate liquids. In this process the reservoir is often maintained above the dew point. Although full pressure maintenance development seems ideal in terms of preventing liquid loss, for economic reasons, this process may not be profitable. In recent years, many gas condensate reservoirs discovered have very high dew point pressures, say above 50MPa, in this case the full pressure maintenance will result in much expensive cost of the injection equipment and a large risk of safety problem. Thus one thought usually arises that whether the reservoir may be cycled at lower pressure after undergoing previous depletion below the dew point.

To address this issue, a series of experiments in this paper are performed and compared to quantitatively investigate the revaporization efficiency of retrograde condensate by lean gas injection. The studies include three main parts: (1) gas injection below the dew point in the PVT cell; (2) gas injection above and (3) below the dew point in long core equipment. Instead of the simple synthetic fluid and the packed core systems used in the previous literature, the actual gas condensate fluid and about 1m long-core are employed here. The gas condensate used is rich and has high wax content. As a comparative basis, the phase behavior is first detailed at length, including constant mass expansion and constant volume depletion. The measurements in the PVT cell show that lean gas injection leads to increase in the dewpoint of the rich gas condensate. An interesting finding from the first part is that lean gas can effectively revaporize not only the intermediate but also heavy hydrocarbon (i.e., C20+), which is contrary to the common belief that the heavy hydrocarbon cannot be revaporized by lean gas. Comparison of the second and the third parts illustrates that more condensate recovery of the former is obtained than the latter. This value is consistent with the conventional idea that full pressure maintenance is superior to the partial pressure maintenance according to the condensate recovery. However, when the expensive investments of the high pressure equipment are taken into account, the full pressure maintenance may not be the best choice. Therefore, it is recommended that an economic analysis be done to evaluate its feasibility. This is beyond the scope of the present study. To our knowledge, this paper is the first report of experimental studies on the revaporization of condensate using actual reservoir fluid/core system in long core equipment.
Effect of Pore Fluid Type on Perforation Damage and Flow Characteristics
Authors: Karacan C. Ozgen , Grader Abraham S. , Halleck Phillip M.
Published: December 2007

This paper compares the results of two perforation tests performed to investigate porosity and permeability damage due to perforating in gas-saturated versus liquid-saturated conditions. We used a method combining transient analysis and X-ray computed tomography (CT) map variations in permeability and porosity around the perforation tunnel. Experiments were conducted on 10-cm (4-in.)-diameter Berea Sandstone cores saturated with either low-viscosity silicone oil or nitrogen gas. Perforation flow tests were performed according to API RP43 procedures using conventional 6-gram HMX explosive charges, 6.9-Mpa (1000-psi) effective stress, and 5.2-Mpa (750-psi) underbalance. After flushing the perforations to remove explosion gases and loose debris, higher viscosity silicone oil was injected into the tunnels and movement of the front in the core was tracked using X-ray CT to measure the front velocity. Radial permeability was determined by relating differential pressure, front position and velocity. Porosity near the perforations was measured by comparing images taken when the sample was saturated with the two different fluids.

Analysis of the images and the data show that, for the specific charge and test conditions used, the type of fluid saturating the rock results in significantly different perforation geometries and damage under the same operating conditions. In the gas-saturated core, we obtained a shorter total penetration depth and a tunnel largely plugged with charge and rock debris. A zone of compacted rock, about 6 mm thick and with 6–8% less porosity than the average rock, surrounded the perforation tunnel. Near the entrance hole, the compaction was more severe when compared to other locations along the tunnel. The liquid-saturated core had a clean tunnel with a larger diameter and deeper penetration than the gas-saturated core. The liquid-saturated rock had no compacted zone. Permeability damage extended approximately 1.5 cm from the center of the perforation in the liquid-saturated core. The thickness of the damaged zone was a little higher in gas-saturated case when compared to liquid-saturated one.
Proppant Holdup, Bridging, and Screenout Behavior in Naturally Fractured Reservoirs
Authors: Barree R. D. , Conway M. W.
Published: December 2007

Pressure spikes and early, rapidly developing screenouts are often observed while hydraulically fracturing naturally fissured reservoirs. These occurrences are commonly attributed to fracture width restrictions or slurry dehydration. This paper describes the results of a series of laboratory experiments designed to study proppant transport and distribution in a hydraulic fracture with leakoff through discrete fissures. Mechanisms are described which explain the observed phenomena of proppant induced pressure rises and rapid screenouts. Methods of treatment design to combat these effects are also outlined. Observations made during the experiments provide insight into proppant crushing during fracture closure, poor polymer gel recovery, and final fracture conductivity.

The experiments show that lateral flow velocity into natural fissures causes proppant to migrate to the fracture wall and build up a dense proppant pack at the leakoff site. With sufficient leakoff the proppant holdup is severe enough to completely fill the main fracture channel, leading to screenout, even at low injected proppant concentrations. During buildup of the proppant bank the injected fluid is forced to flow in channels of diminishing height at very high shear rate. This unstable channelized flow leads to significantly different proppant and fluid distribution in the fracture than that predicted by uniform flow and transport models.
Direct Determination of Relative Permeability from Nonsteady-State Constant Pressure and Rate Displacements
Authors: Toth Janos , Bodi Tibor , Szucs Peter , Civan Faruk
Published: December 2007

Direct interpretation methods for determination of the relative permeability data by linear, non-steady-state, two-phase fluid displacements conducted via constant rate and constant pressure laboratory core tests, are presented. The equations necessary for processing of the displacement test data obtained after the breakthrough of the displacing fluid phase are derived by neglecting the capillary end-effects at sufficiently high flow rates and verified by various experimental data. The total mobility and the mobility ratio of the immiscible fluids are related to the characteristic parameters of the displacement process and the cumulative injected fluid pore volume. The general correlation functions of the characteristic parameters of the immiscible displacement process in porous media are facilitated to conveniently describe the relative permeability functions. These functions allow for accurate determination of the characteristic parameters of immiscible displacement by least-squares linear regression of experimental data. Therefore, the present analytic method determines the relative permeability functions uniquely, rapidly, and more accurately than the previous direct interpretation methods, auxiliary functions, and graphical and analytical methods, and offers a possibility of determining the relative permeability functions from constant pressure and constant rate displacements data.
Planning and Implementation of the Repsol-YPF-MAXUS Krisna Underbalanced Drilling Project
Authors: Park D. , Brand P. R. , Allyson B. , Sodersano G.
Published: December 2007

Due to the previous history of high mud losses and stuck pipe, Repsol – YPF - MAXUS Southeast Sumatra B. V. decided to implement underbalanced drilling technology in the development drilling campaign in the Krisna Field offshore Indonesia. Although Underbalanced drilling is not a new technology, it has been used infrequently in drilling from an offshore structure.

Underbalanced drilling from a jack-up rig causes some unique planning and implementation issues. Planning and implementation are made more complex by the space limitations and logistics. These were compounded by the lack of infrastructure in Indonesia for underbalanced applications.

The Krisna D12 production interval was successfully drilled underbalanced from 10 June 2000 through 20 June 2000 from the Reading and Bates Falcon jack-up Roger W. Mowell. A total of 1159 feet of formation was drilled Underbalanced without any significant drilling related problems.

Although the project encountered problems during the initial start up, modifications to the system and changing the fluid system to a diesel mist eliminated the majority of the issues. By the end of the well, the Underbalanced system was working well.

This paper presents the pre-engineering, project management and field implementation results for the drilling of the Krisna D12.
Reservoir Characterization Whilst Underbalanced Drilling
Authors: Kneissl Wendy
Published: December 2007

Underbalanced drilling (UBD) is rapidly gaining popularity in the industry because of the advantages gained both in terms of the drilling process itself (for example higher rate-of-penetration and reduction of lost circulation), and for enhanced long-term productivity (associated with reduced formation damage). Production associated with the drawdown maintained throughout UBD furthermore offers the opportunity for formation evaluation in real time.

This paper presents a method for simultaneously deriving formation pressure and permeability profiles in real time during UBD, using an approach that does not require any extra operational hardware than is already typically used. This method is known as testing while underbalanced drilling (TWUBD).

The analysis uses pressure transients in the wellbore at bottomhole to perform a novel form of local multirate well test during drilling, leading to the derivation of the spatial profiles of reservoir characteristics.

The method has to date been tested with good success using UBD data from approximately 20 wells.
Extending BHA Life with Multi-Axis Vibration Measurements
Authors: Ashley D. K. , McNary X. M. , Tomlinson J. C.
Published: December 2007

Extending motor, bit, MWD, and BHA component life is of primary importance to the drilling process. Frequently downhole vibrations can cause anywhere from minor to catastrophic failure in any of the components of a typical BHA.

Some types of vibrations are more detrimental to various components of the BHA. Most vibrations can be controlled with the alteration of surface parameters such as weight-on-bit and rotary speed in conjunction with downhole measurement tools such as downhole weight-on-bit and downhole torque as well as BHA alteration. The problem has always been knowing which parameters to alter without adversely affecting total drilling performance.

Recent advances in MWD technology have provided a means of measuring downhole vibration in multiple axes. This information, provided in real-time, allows the driller to control the proper parameters to minimize specific vibration effects thereby maximizing BHA life and total drilling performance.
Subsea Equipment for Deep Water Drilling Using Dual Gradient Mud System
Authors: Forrest Neil , Bailey Tom , Hannegan Don
Published: December 2007

Deepwater drilling presents both opportunity and challenge. One challenge that consistently presents itself is the difference in pressure, at the mudline, between the hydrostatic head of the mud in the riser and the formation pressure close to the mudline, which is, typically, defined by the seawater head. This pressure differential causes an operational difficulty that may, in some cases, prevent drilling the well to its target depth using conventional riser return drilling methods. The concept of Dual Gradient drilling, using a riser filled with seawater, has been proposed as a viable method of limiting this pressure imbalance and of facilitating the drilling of challenging deepwater wells. Over the years, especially in the ‘60’ s and ‘70’ s by major Oil companies, many different approaches to dual gradient drilling have been studied, but none have been commercially developed. During the past three years, three independent large-scale efforts have been initiated in attempts to provide a commercial dual gradient system to the industry. (Ref. 1). Several of these efforts include configurations that utilize a seawater filled risers.

One of the major requirements of dual gradient drilling, using a seawater filled riser, is the need to create an interface between the drilling mud in the wellbore/wellhead and the seawater, or other fluid, in the riser. This can be simply a fluid/fluid interface, located generally above the wellhead in the riser, or a mechanical device to provide positive isolation of the two fluids.

This paper will review the general concept of dual gradient drilling, while focusing on the development of a mechanical isolation method combined with a subsea pumping system for return of the drilling mud. In addition to reviewing the mechanical aspects of the hardware, operational methods and added value that the mechanical isolation system brings to deepwater drilling methods, will be discussed.
The Commissioning and Sea Trials of the Deepwater DP Drill Ship Glomar C.R.Luigs
Authors: Chiu Hin
Published: December 2007

The Glomar C.R.Luigs, Global Marine's new deepwater dynamically positioned (DP) drill ship, has been commissioned, sea trialed, and deployed with a pace unprecedented in comparison with previous efforts. The project achieved record setting results in both operational and technical areas. Operationally speaking, client acceptance of the vessel was accomplished 32 days after Global Marine took delivery of the vessel at the Harland & Wolff shipyard in Belfast, Northern Ireland. Excluding the 20 days of transit time to cross the Atlantic, the vessel began to earn day rate and was ready to commence drilling only 12 days upon her arrival in the Gulf of Mexico. Technically, the sea trials demonstrated astonishing performance in dynamic positioning, setting new records on maximum heading turn rate (52 degrees per minute) and precision station keeping capability (one meter radius watch circle). This paper presents the key elements for the planning phase and execution phase of the project, leading to the successful operation of commissioning and sea trials. These include the operation philosophy and guidelines, scope and duration of works, team organization, preparation of the commissioning procedures, agenda of the sea trials, client's acceptance tests, and interfaces with the client, the classification society, the equipment vendors, and the ship builder.

The contents of this paper will be of interest to project management, commissioning manager and engineers, and fabricators involved in the planning and execution of commissioning and sea trials of offshore drilling and production vessels.
Drilling with Rotary Steerable System Reduces Wellbore Tortuosity
Authors: Weijermans P. , Ruszka J. , Jamshidian H. , Matheson M.
Published: December 2007

Wellbore tortuosity can be defined as any unwanted deviation from the planned well trajectory. As wells become more complex, oil companies increasingly perceive wellbore tortuosity as a concern in the process of drilling, completing and producing wells. Tortuosity is a potential source of additional torque/drag and can lead to problems while running casing, liners and completions. In specific applications, excessive tortuosity in horizontal wells can even impair productivity.

Due to the conceptual difference in steering principle between conventional directional drilling systems, utilizing steerable bent housing motor technology, and rotary steerable systems, it has been claimed that rotary steerable systems produce a less tortuous wellbore. This effect has so far not been quantified, mainly due to the absence of a sufficient body of comparative data. In this paper, results of a tortuosity analysis of a number of North Sea wells drilled with rotary steerable systems, and offset wells drilled with steerable motors systems is presented. Various mathematical definitions of wellbore tortuosity and their implications are also discussed.

The analysis shows that drilling with rotary steerable systems significantly reduces tortuosity. In tangent sections drilled with the rotary steerable system, superior inclination hold performance was observed and in areas of the wellbore where deviation changes were planned, more continuous curve sections were drilled.

In order to illustrate potential benefits this may have with respect to drilling conditions, results from the evaluation were used to carry out torque/drag simulations. Levels of tortuosity produced by steerable motor systems and rotary steerable systems were calculated from the well data studied. These values were superimposed on a generic well profile. It was found that the torque reducing effect of the lower tortuosity delivered by the rotary steerable system is quantifiable and in some cases significant.
Field Application of a Fully Rotating Point-the-bit Rotary Steerable System
Authors: Schaaf Stuart , Pafitis Demos
Published: December 2007

Rotary steerable systems are passing through their infancy stage and becoming an increasingly integral part of the drilling plans of many operators. Improvements in drilling efficiency and the subsequent economic benefits have driven the development of the technology and new methods of rotary steering have now been proven in full-scale tests. One of the key new developments is the creation of "point-the-bit" systems. In this paper, we describe the first of these systems to have all elements of the bottom-hole assembly rotating. This presents a significant advantage in terms of prevention of cuttings accumulation around the BHA, reduced likelihood of becoming stuck and the ability to back-ream. We present a number of case studies that indicate the reliability and broad functionality of the system.
Field Validation of Transient Swab/Surge Response with PWD Data
Authors: Samuel G. Robello , Sunthankar Ashwin , McColpin Glen , Bern Peter , Flynn Tim
Published: December 2007

This paper describes the results of field validation of the transient swab, surge model with PWD (Pressure while drilling) data. The maximum pressures encountered during tripping- or reciprocation are indispensable for making appropriate well completion decisions. The prediction of swab and surge pressures are of critical importance in wells where the pressure must be maintained within narrow limits of pore and fracture pressures. It also plays a major role in running casing, particularly with narrow annular clearances. For these critical cases, a fully dynamic model is required to better estimate the maximum pressures encountered.

This paper presents actual surge and swab field data during tripping and circulating operations collected using PWD tools. These data were obtained from Alaska and North Sea wells with a range of hole diameters and with different base fluid muds. The data were compared and interpreted with a dynamic surge model, which includes the effects of fluid inertia and compressibility, wellbore elasticity, axial elasticity of the pipe, and temperature dependent fluid properties.

The sampling rate was specifically increased to two seconds and in some cases one second. This is done to prevent downhole data attenuations and to capture the full waveforms more accurately. Different operations were included in the PWD runs to cover swabbing, surging, reciprocation and simultaneous pumping operations during tripping. Model predictions of downhole pressure behaviour were in excellent agreement with the measured PWD data.
Measurement of Mud Motor Rotation Rates using Drilling Dynamics
Authors: Macpherson J. D. , Jogi P. N. , Vos B. E.
Published: December 2007

The measurement of mud motor rotation rates, and the transmission of these measurements to surface while drilling, is important for drilling optimization. In general, mud motor rotation rates are estimated from the manufacturers performance data. However, flow rates, torque, weight-on-bit and differential pressure will all vary while drilling as will the efficiency of the motor, affecting the actual rotation rate of the motor. While torque, weight and pressure can all be measured by MWD tools, the direct measurement of motor speed has proven difficult. In general it has been necessary to instrument and hardwire a motor to the MWD system in order to extract a measurement of motor speed. Such modifications result in dedicated and specialized MWD hardware.

This paper describes a means of measuring the rotation rate of a mud motor using a device that is independent of the mud motor. In essence, the dynamic signal created by the rotor is detected by vibration sensors in an MWD measurement sub in the BHA, and converted directly to motor speed. The MWD measurement sub may be remote from (i.e., not directly connected to) the motor, and therefore this system will work with any motor developed using the Moineau principle. Development and testing of the system in the laboratory and in the field are described in the paper.
The Value of Rotary Closed - Loop Drilling Technology on Chevron Alba's North Sea Horizontal Field Development
Authors: Johnstone John A. , Stevenson Philippa
Published: December 2007

This paper describes how innovative Rotary Closed – Loop Steerable (RCLS) drilling technology was introduced to the Chevron Alba field in an effort to optimize horizontal well placement and extend the production life of the field. The application of the RCLS technology has been more successful than initially anticipated, with significant well cost reductions being realised. Moreover, it has allowed access to targets that could not be reached using conventional technology, thereby increasing ultimate recovery from the Alba field.

Initial field development utilized conventional steerable drilling technology, i.e. motor assemblies and rotary drilling assemblies with adjustable stabilizers. Due to geological uncertainties, directional well plans routinely featured pilot holes with an option for one or more geological sidetracks. However, the well designs were constrained by the limitations of the conventional technology. Specifically, the limited ability to steer in the unconsolidated reservoir sands set limits on the dogleg capability and therefore lowered target TVD objectives. Drilling efficiency was compromised too; non-aggressive tri - cone bits were used in preference to PDC bits to facilitate directional control and consequently this limited BHA run length.

In the late 90's a reassessment of the seismic data for the Alba field established new target areas for which it would be necessary to drill more esoteric well designs. This paper outlines the rotary drilling strategy adopted by the Alba project team to accomplish that objective. A review is made of the drilling risks on Alba in the 12 ¼" and 8 ½" hole sections from the conventional drilling perspective, and how these risks became more manageable through improvements in drilling performance with RCLS. In conclusion, an assessment of the technical and financial impact that RCLS technology made on drilling operations on the Alba platform is presented.
Integration of Drilling and Geological Data to Understand Wellbore Instability
Authors: Beacom L. E. , Nicholson H. , Corfield R. I.
Published: December 2007

Throughout the initial phase of development on the Mungo field in the Central North Sea, wellbore instability and mud losses have caused serious drilling problems and additional expense. Geomechanical modeling around the salt diapir led to refinement of some drilling procedures but the direct cause of the drilling problems still remained poorly understood.

A detailed fault mapping study has been carried out from the Paleocene reservoir interval through the overburden. Wellbore instability and mud loss zones displayed along the wellbores were integrated with the 3D fault model and demonstrated that the wellbore instability and mud loss incidents coincide with the location of seismically resolved faults. However, not all faults in the overburden or reservoir were associated with drilling problems. It was found that the intersection angle between the wellbore and the fault surface is critical to determine whether drilling through the fault will induce instability. The Mungo data indicates that small intersection angles (commonly between 0–45°) resulted in drilling problems while larger intersection angles (commonly between 45–90°) were not associated with drilling problems.

These results have been incorporated into the current well planning and drilling strategy for Mungo development wells. So far, a sidetrack well and chalk oil appraisal well has been successfully drilled in the overburden. Potential problem zones predicted in advance were mitigated for in the well planning stage and contingencies included in the drilling budget. The overburden drilling risks are understood by visualizing the integrated geology and drilling data in 3D, so it now takes less time, and therefore less cost to drill successfully to the reservoir target. The techniques are also being applied successfully for well planning and drilling on other fields.
First Simultaneous Application of Rotary Steerable/Ream-While-Drill on Ursa Horizontal Well
Authors: Eaton L. F. , McDonald Scott , Rodriguez Edgar M.
Published: December 2007

The development wells at the Ursa tension leg platform (TLP) site use 8.625" production casing in conjunction with 5.5" tubing to achieve the highest daily production rates to date in the Gulf of Mexico. The desire for large diameter production casing and the small margin between mud weight and fracture gradient at the deepwater Ursa site combine to require drilling a larger sized hole than the drift diameter of the previous casing string for all of the casing intervals. Bi-center bits have successfully drilled all of the intervals in one run except the section to total depth (TD). The last 1,000’ true vertical depth (TVD) on the first two wells were drilled and then under reamed prior to running casing.

The directional plan for the third well at the Ursa TLP included an 86° turn in azimuth and building hole angle to horizontal by 18,300’ TVD. The previous lack of success drilling the TD interval in one trip with bi-center bits led to using a 9.5" bit below a 6.75" AutoTrak rotary steerable closed loop system (RCLS) in combination with an 11.4" ream-while-drill (RWD) sub. This bottom hole assembly (BHA) would simultaneously drill and ream the hole to the proper diameter, thus eliminating the separate under-reamer run.

During the initial pilot hole penetration of the target reservoir and two subsequent sidetracks to build to horizontal, the RCLS / RWD system drilled approximately 20,000’ of Miocene age sand and shale sediments at inclinations that ranged from 30° to 88°. The instantaneous and average rate of penetration (ROP) increased 30% and 85% respectively over that achieved in the TD interval on the previous wells drilled with steerable mud motors and bi-center bits. The directional target of the well was intersected at the desired inclination and azimuth. Caliper logs obtained while evaluating the pilot hole showed the shales had been opened to the gauge diameter of

11.4" while the sands were opened to a slightly smaller diameter. Subsequent laboratory tests showed that the slightly smaller hole diameter in the sands was most likely due to filter cake build-up and/or barite sag.

This paper will discuss the planning, results, problems, and lessons learned during the first simultaneous use of rotary steerable and RWD technology while drilling a build to horizontal section to 18,300’ TVD on the Ursa A-6 well.
West Africa Deepwater Wells Benefit from Low-Temperature Cements
Authors: Piot Bernard , Ferri Alain , Mananga Simon-Pierre , Kalabare Collins , Viela David
Published: December 2007

More and more drilling occurs in frontier areas and particularly in deep water. In this environment, where the water depth often ranges between 1000 and 3000 m, the temperature at the seabed is extremely low, reaching –1°C (30°F) or less in certain parts of the world. In addition, a nonlinear temperature gradient in this water column and the sea currents further participate in and accelerate the cooling of the fluids in the wells. These low temperatures considerably slow cement hydration, which adversely affects the compressive strength development of the cement slurries.

The young, soft formations encountered in the first few thousand meters below the seafloor preclude the use of normal-density cement slurries. However, conventional low-density cements take a long time to set and develop significant strength at these very low temperatures. The daily rate of the rigs able to drill these deepwater wells is fairly high. In addition, the latest generation of offshore deepwater rigs is designed to work faster and deliver wells drilled more efficiently. It is therefore important to have lightweight cement systems that set quickly and develop high strength in the short period of time compatible with the operation of these new rigs.

Often, the permeable layers below the seabed contain either free gas, when the water depth (and pressure) is reasonable, or gas hydrates at greater water depth. The lightweight cement system used in deepwater wells must therefore also control gas during its setting process at these low prevailing temperatures.

Several case histories are presented from West Africa, where lightweight cements capable of setting quickly and managing gas flow in low temperatures have been required to economically drill, case and abandon formations with low fracture gradient in deepwater wells. These systems are compared to more conventional solutions that have been either applied or attempted for cementing the shallow casing strings in wells drilled in water depths ranging from 800 m to 1900 m (~ 2620 to 6230 ft). Applications for water depths to 2800 m (~ 9190 ft) are also considered.
A Case Study of High Pressure Brine Flows within the Zechstein Supergroup of the Southern North Sea
Authors: Finnie A. B.
Published: December 2007

This paper presents the case histories of four adjacent development wells drilled through the Zechstein formations in the Southern North Sea (SNS) during ‘99-‘00. A jack-up MODU was used in cantilever mode. Formation pressures encountered ranged from 18.1ppg to 19.25ppg EMW. Brine kicks, believed to be among the most intense in the SNS, were experienced. Of the 4 wells, 2 encountered high-pressure from Plattendolomit formation, while the other two experienced significant pressures from within the Zechstein salt itself.

The Zechstein Supergroup is a series of evaporite and carbonate formations formed ca. 250 million years ago1. It has presented Southern North Sea drillers with significant problems since drilling began ca. 1965. This paper focuses on the problems associated with the drilling of the Z3 series. These are overpressure; losses; and loss/gain situations. A description of each problem and the industry’s current thinking towards them is presented. The recent wells have provided a learning opportunity. The prospect of encountering high-pressure was considered likely. Contingency plans were drawn up and implemented in response to events. The experience gained, as the project progressed, was used to tailor the approach towards the subsequent wells. This iterative process is followed, as each well is drilled, and serves to provide a variety of learning points. These are categorised as 1) Wells Problems and Solutions 2) Practical Problems and Solutions. These cover issues ranging from how to circulate kill mud effectively to determining the volume of influx. The learning is documented and presented as a reference for future developments.
New Operator Achieves Best in Class Performance in CNS
Authors: Redgrave S. , Kipperman E. , Morton T. R.
Published: December 2007

During April – June 2000, Veba Oil & Gas UK Limited (VOGUK) drilled three Appraisal wells in the Guillemot West/Western Extension as Sole Risk (no partners) Development Pilot holes. The wells were designed as "keeper wells" that could be used as Development wells if successful.

The wells were drilled under high angle, with 13 3/8" casing set at 70 degrees inclination in water based mud, penetrating the reservoir in 12 ¼". During the drilling of the 12 ¼" hole section, synthetic based mud cuttings were collected and, using skip-andship operations transported for disposal on land. Inside drill pipe gyro runs were required to open up tight targets, and novel TLC (Tough Logging Conditions) tool combinations were run under high over balance conditions, achieving all objectives.

The paper describes the "can-do" approach for this successful fast track project (5½ months from start of planning to end of drilling). The paper covers the consultations with the Government bodies, the environmental issues solved, the contracting process, procurement of materials, the new technical applications and the Team-approach used to achieve the Best-in-Class drilling performance.
A Mathematical Algorithm for Modeling Geomechanical Rock Properties of the Khuff and Pre-Khuff Reservoirs in Ghawar Field
Authors: Al-Qahtani Mohammed Y. , Zillur Rahim
Published: December 2007

The Khuff and Pre-Khuff are deep gas condensate reservoirs under active tectonic stress environment. The reservoirs are under development using horizontal wells and vertical wells with hydraulic fracturing. Modeling geomechanical rock properties accurately is essential for ensuring a successful frac job design and execution. During the last two years, a large amount of additional lab and field information has become available. Integration of all the data was conducted for better estimation of in-situ geomechanical rock properties.

This paper presents the results of a mathematical algorithm for calculating the geomechanical rock properties for the Khuff and Pre-Khuff reservoirs in the Ghawar field. The model is derived from the classical poroelastic model in addition to a tectonic strain component as proposed by Prats and Warpinski. The model was calibrated to lab data as well as to the results of several Microfrac and Minifrac field tests. The model was further improved by calibrating it with actual history-matched frac data.

The algorithm describes a methodology for systematically calculating geomechanical rock properties and in-situ minimum horizontal stress magnitude from sonic shear and compression log data. The paper also describes a detailed history-matching algorithm for Minifrac and frac data using a 3-D frac simulator. The results show that the minimum in-situ stress in the Khuff and Pre-Khuff reservoirs is governed by the tectonic effect, which is Young’s modulus dependent. Detailed analysis and well examples are presented.
Considerations on the Selection of an Optimum Vertical Multiphase Pressure Drop Prediction Model for Oil Wells
Authors: Takacs Gabor
Published: December 2007

First, the paper gives a classification of the calculation models commonly used for the calculation of multiphase vertical pressure drops in oil wells. The main parameters of the experimental data used to develop the different empirical correlations are presented indicating the ranges where the correlations are expected to perform best. Next, an analysis and classification of the many possible causes of calculation error is given. Deviation of calculated and measured pressure drops is shown to stem from different sources that can have different importance from case to case.

The author collected and summarizes in the paper the findings of the many previously published investigations on the accuracy of the different pressure drop calculation models. A table including all available data on calculation accuracies is also presented. Statistical parameters of these investigations are shown to be widely scattered and to be of limited use to engineers seeking the most accurate model. Differences and contradictions in the results are evaluated and explained.

Finally, the author describes the petroleum engineer's proper attitude towards vertical pressure drop correlations. Practical implications of the proposed philosophy are also detailed. In conclusion, the paper provides the required insight and proper attitude to petroleum engineers facing the problem of predicting multiphase pressure drops in oil wells.
Optimizing Acid Treatments With the Use of Jet Blasting Tool
Authors: Dahroug Ahmed , Brown Barry , Shaheen Mansour
Published: December 2007

Coiled Tubing is a common method of diverting treatment fluids into wellbore formations in open hole and cased hole completions. The efficiency of the treatment can be significantly improved by increasing the impact force of the fluid on the formation.

The recently developed JetBlaster™ Tool has been used on some cases as the optimum BHA that can be used with Coiled Tubing for the efficient delivery of treatment fluids. The software JetADVISOR supports system hydraulic analysis and the design of the tool configuration in terms of nozzle and orifice diameter. This allows optimization of jet impact force or hydraulic horsepower, and ensures a sufficiently high rotational speed to effectively divert the treatment around the circumference of the wellbore. The addition of velocity increases the affectivity of the treatment.

In order to assist evaluation of the efficiency of the technique we have primarily attempted to treat a well that had formation drilling damage with the tool while pumping a non corrosive fluid that has no direct chemical reaction with the formation filter cake. The well was then put on the test to see the increase in production and wellhead pressure and the results recorded and compared. Then the same treatment was repeated but while jetting acid, then the well was once again put on test.
Coiled-Tubing-Conveyed Hydromechanical Pipe Cutting: A Safe, Effective Alternative to Chemical and Explosive Severing Methods
Authors: Fanguy Dean J.
Published: December 2007

In the past, tubing, casing and drill pipe recovery has been employed where chemical and explosive severing tools could not effectively sever the pipe.

A coiled-tubing-conveyed hydromechanical pipe cutting system has proven to be a viable alternative to pipe recovery when conventional severing systems are not effective. The system does not contain or require any hazardous materials, which makes it safer to use than conventional systems.

The pipe cutting system incorporates modular stabilizing devices that decrease the risk of the coiled tubing forces and the wellbore deviation from interfering with the cutting operation. The pipe-cutting mechanism uses several unique blade configurations that were designed specifically to address various metallurgical properties and dimensions. The cutting blades contain state-of-the-art cutting inserts, which were previously proved in various metal milling and cutting applications within subterranean wells.

A detailed description of the coiled-tubing-conveyed hydromechanical pipe cutting system, its operational function and a variety of case histories are discussed in this paper.
An Experimental Study of Drag Reduction of Polymer Solutions in Coiled Tubing
Authors: Shah Subhash N. , Zhou Y.
Published: December 2007

The excessive friction pressure loss due to the small tubing diameter and the curvature (which believed to cause secondary flow) of coiled tubing (CT) often limits the maximum obtainable flow rate in CT operations. This paper presents an experimental study of drag reduction performance of several polymer solutions in coiled tubing using a sophisticated full-scale coiled tubing test facility for an industry-university joint research project. The facility includes of seven reels of coiled tubing with diameters of 1", 1-1/2", and 2-3/8", fluid mixing and pumping equipment, and data acquisition system. Fluids investigated include water and solutions of polymers currently used in the well drilling and completion industry – Xanthan gum, partially hydrolyzed polyacrylamide (PHPA), guar gum, and hydroxyethylcellulose (HEC). Experimental results showed that the amount of friction drag reduction differs significantly among the different types of polymers at various concentrations. Data interpretation and analysis revealed that the CT diameter and the CT-to-reel drum diameter ratio are important geometrical parameters affecting drag reduction. The flow data indicate that the onset of turbulent flow in CT is suppressed in the polymer solutions. This paper introduces the concept of the modified drag reduction envelope for flow of polymer solutions in coiled tubing.
Selection of Optimum Coiled-Tubing Drilling Parameters Through the Cuttings-Bed Characterization
Authors: Cho Hyun , Shah Subhash N. , Osisanya Samuel O.
Published: December 2007

The effects of cuttings bed at intermediate deviation of wellbore (30 – 60°) from vertical are quite complicated in cuttings transport because the movement of cuttings bed with its direction has not been well understood. The effect of cuttings bed movement in this region has also been neglected in most other mathematical models. The reason for this might be the instability of cuttings bed. This study shows that neglecting the cuttings bed characteristics may result in improper selection of coiled tubing drilling parameters, which may frequently lead to costly problems such as stuck pipe. However, the existing models, which can handle from vertical to horizontal wells with only a function of the wellbore deviation, cannot properly characterize the effects of cuttings bed movement in cuttings transport mechanism for the intermediate deviation of wellbores.

A mathematical model is proposed based on momentum and force balances in this region. All parameters, which involve cuttings bed movement and its direction, build up and erosion of cuttings bed, and wellbore deviation, are analyzed quantitatively. The analysis of the data obtained from the simulation allows interpretation of the relationship between major parameters affecting characterization of the cuttings bed in this region. The concept of minimum anti-sliding velocity of cuttings bed (MASV) is developed based on the interrelationship between parameters, which involves fluid rheology, wellbore deviation angle, interfacial friction between suspension layer and cuttings bed, and in-situ fluid velocity in suspension layer. This study also provides the selection guide of drilling parameters affecting wellbore cleaning by a compromise process for optimum combination of the parameters.
Reserve Overbooking – The Problem No One Wants to Talk About
Authors: McLane M. A. , Rose P. R.
Published: December 2007

Managers of publicly held companies often face pressures that can tempt even the most principled to push the envelope of credibility in efforts to buoy investor confidence and thus increase stock value. In an age of instant gratification and inflated expectations of return on equity, companies often struggle with long range strategic planning while at the same time striving to meet expectations of the next quarterly earnings report. The quest for increased market capitalization often leads these harried managers to look under every stone for anything that will entice more investors to buy into their company.

The assets of oil and gas companies consist mostly of hydrocarbons in the ground – reserves. In typical annual reports one often finds proved oil and gas reserves stated in very precise terms. These reserve numbers are, in reality, very imprecise because of the variability and uncertainty in the earth and in the industrial and economic world. This is why the industry is moving increasingly away from deterministic reserve estimates to probabilistic, or stochastic, reserve estimates. Ironically, it is the very uncertainty associated with reserves that has enabled and preserved a practice that has, over the last twenty years, destroyed value and led many investors down the primrose path – reserve overbooking.

Reserve overbooking occurs for many reasons, among them poor estimating practices, misguided incentives, ignorance, competition for investors, and lack of professionalism. Any temporary benefits companies may derive from overstating reserves disappear whenever reserves must be de-booked. The resulting loss of confidence by investors and analysts is often made more painful by the fact that it could have been avoided. Reserve overbooking is a problem that may be solved through consistent, professional reserve estimating and reporting, and leadership, professionalism and accountability by informed and knowledgeable managers.
Problems Reconciling Probabilistic and Deterministic Reserve Classifications and Evaluations
Authors: Purvis Dwayne C. , Strickland Richard F.
Published: December 2007

The current SPE/WPC definitions for reserves quantified by probabilistic methods are ambiguous and largely inconsistent with deterministic criteria. Probabilities are least well defined and most subjective at the extremes of the ranges of outcomes. Since reserve definitions are meant to provide consistency across evaluators and evaluations, the current definitions are not workable. When defining reserves, volumes should first be classified into a category. A probabilistic analysis can then be made of the uncertainty in each category, and a central estimate of Proved reported. When probabilistic analyses are used to determine value, the same restraints are not necessary, but the same wariness of the extremes of the distributions should be applied.
A New Tool to Make Quick Estimates of Probabilistic Reserves from Production Trends
Authors: Idrobo E. A. , Jiménez E. A. , Bernal M. C.
Published: December 2007

The estimation of probabilistic distribution of reserves is increasingly being used in the oil industry. However, this is not an easy assignment because of the amount of information required and costs associated. Even more complicated is the task of evaluating distribution of reserves departing from production trends. The historic analysis of production has usually used a deterministic approach in the form of Decline Curve Analysis (DCA).

In this paper we present a quick and efficient application for estimating probabilistic distribution of reserves combining the usually available production information with the power of stochastic methods through the use of decline curve analysis: PREP (Probabilistic Reserves Estimation Package). The computational tool developed uses a Monte Carlo-type technique under an efficient optimization algorithm to calculate the DCA parameters. More than 200 realizations can be generated and evaluated in a few seconds for diverse production scenarios and information such as standard errors, confidence intervals, expectation curves can be visualized to uncertainty diagnosis.

We have applied the proposed tool on several fields located in the Valle Superior del Magdalena Basin in Colombia, South America. The Valle Superior del Magdalena Basin is estimated to contain over 1,400 million barrels of oil-in-place of which only 14.7% have been produced. The results obtained have had strong economic impact on reservoir management decisions.