bluuebunny/crossref_metadata_2025 huggingface dataset:
Mesophase Technology for Wellbore Cleanouts-Case History
Authors: Al-Ruwaily A. A. , Phillips J. E. , BenSaad Z. R. , Christian C. F.
Published: March 2009

This paper is a case history of two successful applications of mesophase technology for wellbore cleanouts and flow back enhancement. The first application was as a remedial treatment after the well's ESP pumped off and the second application was part of the completion process. Both wells were completed as open-hole horizontal wells, one with expandable sand screens (ESS) and the other with stand alone mesh type premium screens (SAS). Wells in this field are typically drilled with 65 pcf invert oil emulsion drill-in fluid (DIF) and can be as much as 800 psi over balance to formation pressure. The DIF is intuitively managed with respect to mud solids control, so there is no actual QA/QC on the solids management.

The ESS completion was treated remedially with coiled tubing (CT) and rotating jet blasters months after the completion. The horizontal well was accessed through a Y-tool bypass that was part of the ESP completion. The SAS completion was treated with CT and rotating jet blasters after running the screen and setting the packer; prior to running the ESP completion, due to casing size limitations for running a Y-tool bypass.
Inflow Control Device an Innovative Completion Solution from "Extended Wellbore to Extended Well Life Cycle"
Authors: Al Arfi Saif Ali , El Abd Salem Salem , Keshka Ashraf Al-Saiid , Al-Bakr Salem , Amiri Abdel Hameed , El-Barbary Abdalla Youssef , Elasmar Magdi , Mohamed Omar Y.
Published: March 2009

This paper will describe a new production technology system that enabled focusing on achieving performance objectives in addition to finding and fixing production problems.

Inflow Control Device (ICD) is a new completion system that will optimize production, delay water progress, eliminate / minimize annular flow, and ensure a uniform inflow along the horizontal wellbore at the cost of a minute pressure drop. The non-uniform production profile across the horizontal hole especially in the highly heterogeneous and fractured reservoirs can result in premature water production, bypassed oil and lower ultimate recovery. The problem was identified through production logging of several horizontal wells, which indicated a non-uniform production profile across the horizontal holes.

The successful implementation of this technology was achieved by the use of an integrated approach to select the appropriate technology and method for addressing the problem. A business case was developed at which all key factors comprised a successful completion strategy in both drilling of a new well and work-over of an existing well. Among these key factors the development of multidisciplinary team; matching a good intervention candidate well with the appropriate technology; properly designing the well segmentation and execution of the design with rigorous quality control.

A case history will be presented where this new production technology, has resulted in significant Net Present Value (NPV), and improved production via an extended well-life cycle. The ICD Equalizer system was installed in one new and an existing well with the aim to evaluate the viability of the technique.

Both installations were successful and the preliminary surface testing results of the wells performance on different rates indicated a niform production profile across the horizontal hole and a drop in the existing well water cut (from 7% to traces). Although the new well has penetrated fractures as expected, the well did not show water production since installation (Febrauary 2007) till the time of writing this paper.

With field-scale implementation, the economic analysis revealed an improved NPV and an incremental recovery factor increase about 1%.
Effect of Brine Salinity on Interfacial Tension in Arab-D Carbonate Reservoir, Saudi Arabia
Authors: Okasha Taha M. , Al-Shiwaish Abdul-Jalil A.
Published: March 2009

Carbonate reservoirs contain more than 50% of the worlds's hydrocarbons reserves. In Saudi Arabia, most of the current hydrocarbon production is from Arab-D carbonate reservoir (Upper Jurassic limestone). Oil production started 50 years ago. So, the various fields had been subjected to prolonged pressure support by waterfloods (since 1970) using high salinity brine (Arabian Gulf water). Oil recovery using waterflooding is about a third of the oil original in place (OOIP); while two-thirds still remain as a target for additional recovery.

Low salinity waterflooding was introduced as an enhanced oil recovery technique from at least 65 years. Interfacial tension (IFT) between oil and brine during waterflooding has a significant effect on oil recovery and production strategy. So, this study was carried out to investigate the effect of brine dilution, temperature, and pressure on IFT of dead and recombined oil in Arab-D carbonate reservoir as the first phase in evaluating the potential of low salinity flooding technique to improve oil recovery.

In this study, Arab-D reservoir brine with total dissolved solids (TDS) of 214,943 ppm was mixed with distilled water in two proportions resulting in a first solution with TDS = 107,906 ppm and a second with TDS = 52,346 ppm. For reservoir brine and each diluted brine, crude oil/water IFT was measured at reservoir conditions. Test results showed a decrease in IFT values for both dead and recombined oil as the volume percent of brine in the mixture decreased. IFT decreased with increasing temperature at constant pressure and increased with pressure at constant temperature. Such results show that low salinity flooding may be a good technique to improve oil recovery in Arab-D carbonate reservoir. This will require an intensive experimental coreflooding tests due to complexity of the Arab-D reservoir.
The Application of Streamline Reservoir Simulation Calculations to the Management of Oilfield Scale
Authors: Fawzy Tharwat , Mackay Eric
Published: March 2009

Inorganic scales precipitate in oilfield systems - downhole in the reservoir, in the production flow tubing, and in surface facilities - because of thermodynamic changes that affect the flowing brines. These changes may be induced by temperature or pressure changes, or by mixing of incompatible brines. While much work has been performed to study the effect of thermodynamic changes such as pressure decrease or temperature increase on scale precipitation, it is only recently that a body of work has been developed on the impact that the dynamics of brine mixing in the reservoir has on scale precipitation in situ. Much of this work has been conducted using finite difference simulators, which are handicapped with regard to these calculations in that numerical dispersion effects can be orders of magnitude greater than physical dispersion.

The introduction of chemical reaction calculations into streamline simulation models presents a very significant opportunity for improving the accuracy of such calculations. While numerical dispersion effects for immiscible calculations (eg water displacing oil) can be countered by pseudoisation of the relative permeability functions, in finite difference models it is difficult to control numerical dispersion for miscible displacements - eg seawater (with a Sulphate concentration) displacing formation water (with a barium or strontium concentration), which may lead to scaling in the reservoir (BaSO4 or SrSO4 precipitation). Streamline simulation reduces the numerical errors for both miscible and immiscible displacement - so making the scaling calculations much more accurate.

The objective of this paper is to study the application of a streamline simulator that has the appropriate chemistry modelling capabilities to realistic reservoir scenarios. The calculations performed demonstrate where, and under what conditions, scale precipitation takes place in situ in the reservoir, and what the resulting impact on the chemical composition of the produced brine will be. This information is key in the planning of management of oilfield scale, especially in developments where options for scale mitigation may be limited.
Holistic Approach for Regional Depletion Plan Supporting Gas Supply in the Nile Delta of Egypt
Authors: Hussien Mohamed Samy M.
Published: March 2009

This paper shows practical example in the direction of building "holistic regional depletion plan" by applying "fully holistic" and "fully probabilistic" modeling at the cost of the classic "precision" modeling that tends to include more physics. The approach came as a result of the oil industry low return on investment (ROI) that averaged at 7%. Deterministic methods usually ignore the full uncertainties distribution, associated risks, the diversification effects, and the interdependencies among the chosen assets. In addition it loses the proper interaction between the technical and the commercial value drivers. As a result, many rated oil companies fall since 1990 until near future.

To achieve more realistic results, decision and risk analysis (D&RA) approach together with a "holistic strategy" (based on the Nobel-Prize wining portfolio theory that has shaped the financial markets over the past four decades and recently introduced to E&P) are applied instead of the conventional deterministic method and the "hole-istic strategy" that may lead to suboptimal solutions. Assets in the Nile Delta of Egypt were chosen to apply more modern modeling techniques by using less model "precision" for more comprehensive modeling of uncertainties and more integrated technical and business modeling. Full probabilistic methods that closely integrate technical and commercial data and tie that to the decision-making process are used to preserve more relevant information. This allowed the pertinent uncertainties to be exploited better and risks to be quantified when compared to the traditional deterministic methods. Optimization was carried out within the whole "value chain" at different "hierarchical levels" instead of optimizing parts separately that may destroy the whole value chain.

With the current volatile oil market and the 2008 international financial crisis, integrating the endogenous factors (local uncertainties such as geology) and the exogenous factors (global uncertainties such as geo-economics) reduces the risk of the volatile oil prices and the political events. Proper risk evaluation and quantification for many assets enables to build reasonable efficient frontier (EF) that a firm can use to decide its optimum situation depending on the firm willing and to avoid misallocation of capitals.
Integrating Real-time Downhole Data to Enhance Gas-lift Completion Strategies and Perforation Practices
Authors: Ibrahim Hanaey D. , Al-Balushi Sameer , Al-Shizawi Wafa , Beattie Stephen
Published: March 2009

This paper discusses the use of downhole gauges not only for monitoring pressure and temperature, but also production-optimization, enhancing completion design, perforating activates and cost-management efforts.

Real-time downhole gauges have been used in oil fields for many applications in the past. Despite this, permanent downhole gauges have only been installed for gas-lift wells in one of PDO's fields since 2007. The requirement for the monitoring system was to closely monitor the bottomhole conditions for the purpose of water injection in a 5-spot pattern application.

Openhole logs and individual reservoir pressure data of a well in 2007 indicated a variation in reservoir pressure values across the encountered zones. The decision to install permanent gauges offered the possibility to perforate the wells selectively in stages and measure the extent of underbalance prior to and during perforation operations. A technical and commercial comparison among perforation operations methods revealed that such an approach could result in better production performance and cost management. Data from the gauges provided ideas for improving perforation practices, such as spotting light oil against the perforated interval to minimize reservoir impairment.

Installing permanent gauges in 2008 clarified three important areas: the wireline operations prior too perforation; the correct method for perforating; and the adherence to the issued program.

While kicking off the well using gas lift, readings from the gauges revealed a gas-lift valve problem that instantly led to the decision to suspend perforation and change the malfunctioning valves. After rectifying the issue, perforating operations resumed and individual production tests were carried out to clarify the well's further potential. As a result, an operating-expense saving of more than $500,000 was achieved in the 2008 new well campaign. The added benefit of improved completion operations and production optimization has proved very useful.
Validation of Fracture Lineaments With Dynamic Well Data, Improves History Matching of a Dual Porosity-Permeability Model
Authors: Mubarak Saeed M. , Ali Zaki A. , Pham Tony R. , Le Maux T. , Colomar F. M.
Published: March 2009

Simulating fractured carbonate oil reservoirs using the conventional single-porosity/single-permeability (SPSP) model does not normally capture the whole fluid flow mechanism in the system. A dual-porosity/dual-permeability model (DPDP) conditioned by field dynamic data can lead to better fluid saturation matches.

This paper presents a new approach to history matching of naturally fractured reservoirs using a DPDP model that incorporates integrating production field performance data into the geological fracture model. A case example from a carbonate reservoir model will be used to illustrate this approach.

The construction of the fracture model was done by emplying structural lineaments from 3D seismic data, and then enhanced by integrating engineering data into the model. The engineering data included mud losses during drilling, flowmeter surveys, transient well test analysis and water production data.

The upscaled 3D fracture model was then used for history matching. With only minor modifications to the fracture model, a simulation model yielded a reliable match for water production. Furthermore, eighty percent of mud loss occurrences were in agreement with the 3D seismic lineaments mapping.
A New Stick-Slip Prevention System
Authors: Kyllingstad Åge , Nessjøen Pål Jacob
Published: March 2009

Stick-slip is a dysfunction of rotary drilling, characterized by large cyclic variations of the drive torque and the rotational bit speed. It is recognized as a major source of problems, such as excessive bit wear, premature tool failures and poor drilling rate.

This paper presents a new system for curing and preventing stick-slip motion. Like other competitive systems it fights the stick-slip oscillations by smart control of the drive. But in contrast to other active systems it does not use any kind of torque feed-back, not even the motor current. Fundamentally, the system is a PI-type speed controller that is tuned to effectively dampen torsional vibrations at the observed stick-slip frequency. In addition to automatic tuning of the speed controller the system includes a suite of support functions, such as automatic determination of the stick-slip frequency, estimation of the instantaneous bit rotation speed and calculation of the stick-slip severity, defined as the normalized downhole speed amplitude. All software is implemented in a standard programmable logic controller (PLC).

The paper also includes results from a field test and from Hardware-In-the-Loop (HIL) simulation tests. In the latter tests utilizing the HIL, the software runs on a PLC communicating with an advanced real-time computer model for the drive and the drill string. HIL testing has proved to be cost efficient because the PLC software can easily be tested over a wide range of different downhole conditions that rarely occur in the field.
The Application of Surfactin Biosurfactant as Surfactant Coupler in ASP Flooding in Daqing Oil Field
Authors: Wang D. , Zhang Y. , Yongjian L. , Hao C. , Guo M.
Published: March 2009

After conventional water flooding processes the residual oil in the reservoir remains is likely to be around 70% of OOIP. The EOR method socalled alkaline-surfactant-polymer (ASP) flooding has proved to be effective in laboratory experiments and field projects .At present restricts to application of this technique is surfactant development. biosurfactants has characteristic of low poisonous, no pollution, inexpensive. Therefore biosurfactants could be used as an economical alternative to chemical surfactants in ASP flooding is feasible. This paper studied the feasibility of using biosurfactant-Surfactin-fermentation liquor (SF) as a complementary agent of alkaline-surfactant-polymer (ASP)-flooding was conducted in the laboratory. The results show that The activity of Surfactin is tolerance to high salinity(0~12 wt%), high temperature(50-100 °C), wide pH range(6.0~11.0) and high Ca2+/Mg2+ concentration. And this surfactin could reduce IFT of water/oil from 23.53 mN/m to 4.57 mN/m , Its critical micelle concentration was tested to be 33.3 mg/L, and it had excellent emulsifying(2.89U) and foaming property. The interfacial tensions (IFTs) between solutions containing SF or mixture of SF and alkylbenzene sulfonate (ORS) at different ratios and crude oil were studied at a constant NaOH concentration. The results show interfacial characteristics (IFT) of SF and significant synergic effect between SF and ORS. The core-flooding tests show that the enhanced oil recovery with the formulation of ASP of 0.1 wt.% SF and 0.1 wt.% ORS is 7% more than that with the formulation of ASP of only 0.1 wt.% ORS, and is equal to that with the formulation of ASP of 0.3 wt.% ORS. This indicates that using SF can reduce the cost of ASP flooding.
Towards the e-field: Continuous Monitoring of Pore Fluid Phase using Horizontal Wells
Authors: Evans B. J. , Hartley B. , Keshavarz N.
Published: March 2009

The electric or e-field has been discussed at length in literature, in terms of the methodology of continuously remotely monitoring oil field production over a long term using vertical and horizontal wells, and transmitting data back to a monitoring centre. Conventional vertical well monitoring methods is adequate to monitor at points around an oil field but continuously monitoring where fluids are moving requires monitoring over an area using horizontal wells.

Recent research has shown that seismic methods can show subtle changes in pore fluid phase which enhances the potential for long term monitoring where pore pressure is reducing, where injected water or CO2 flood options have been chosen, and areas where gas is being replaced by water. If we can marry the use of slim-hole horizontal sensor cables with this recent demonstration of the detection of phase changes, then we have the tools for the first applied e-field scenario.

During 2007, laboratory tests injecting different amounts of CO2 into pore water showed that by monitoring the seismic transmission through a simulated rock, there was a change in seismic frequency response and transmission amplitude. Physical modeling has shown that a horizontal slim-hole well drilled to test the ability to put sensors in a horizontal well, can then be used for remote reservoir surveillance. A seismic source which walks around at the surface, produces data which is then processed to produce an indication that this method can be used as a first step for determining pore fluid properties over an area.

This paper presents the results of the experiments on pore fluid phase and discusses how the use of horizontal wells allows the ability to develop the e-field concept towards reality.
Development of Water Saturation Sensitivity Charts for Different Shaly Sand Models for Uncertainty Quantification of Volumetric In-Place Estimate
Authors: El-Sayed Samiha S.
Published: March 2009

Quantifying the uncertainty in the volumetric estimation of original oil in place (OOIP) is an important process in evaluating the field potential and hence in designing the proper and the most economical subsurface and surface facilities to produce the field reserves. This uncertainty in the OOIP estimate results from uncertainty in reservoir areal extent, net reservoir thickness, porosity, and hydrocarbon saturation. In this work, a methodology is presented to assess the uncertainty in the hydrocarbon saturation estimated from open hole logs using the commonly used empirical and theoretical shaly sand models.

This technique is based on development of water saturation sensitivity charts for the most commonly used water saturation models (Simandoux, Indonesian, Waxman & Smits, Dual Water, and Effective Medium) due to the uncertainty in the different input parameters to each model separately. Both analytical and numerical error analysis techniques were used to develop these charts and hence used as a forward tool to quantify the uncertainty in the hydrocarbon saturation due to the uncertainty in the core and shale properties.

Fifteen wells with 1300 shaly sand points from Alam Bewab formation, in Western desert of Egypt, were used as the data base in generating these sensitivity charts. The uncertainty in input data was assumed from ± 5 to ± 15%. The results showed a significant range of uncertainty in hydrocarbon saturation estimate from ± 2% reaching to ± 75% in some models.

General water saturation sensitivity charts were developed, for each model, based on the above mentioned database and validated mathematically. These charts can be easily used to predict the uncertainty in hydrocarbon saturation estimate due to uncertainty in the input data. In addition, it can be considered as a useful screening tool to select the best saturation model to be used depending on the input data uncertainty.
A Study of Temperature Dependent Friction in Wellbore Fluids
Authors: Kaarstad E. , Aadnoy B. S. , Fjelde T.
Published: March 2009

Increased well reach is one of the most important developments in modern drilling. Wellbore friction plays a central role here, both related to the drilling and to the completion phases of a well. The oil industry, however, uses the simple one-parameter Coulomb friction model to analyze well friction, without temperature effects.

The University of Stavanger has conducted friction research over some years, trying to further understand mechanical, viscous, temperature and material frictional effects. This paper presents some results of this work. Many water and oil based drilling muds from several mud vendors have been measured. The test equipment used includes a heat element to study the temperature effect on friction. The data reported cover a temperature range of 10°– 100°C.

As expected, oil based fluids have lower friction coefficient than water based fluids. The coefficient of friction increases with temperature for all fluids, except for one mud which showed nearly constant friction above 50 °C. There is considerable variation between the different fluids. Friction coefficients have been measured with steel on steel, steel on concrete and steel on rocks. Steel on rock exhibit higher friction due to higher surface roughness of the rock material. An equation for temperature dependent coefficient of friction is derived, and it is used in the field example. It is shown that the temperature effect on friction is considerable.
Drilling at the Limit—Can Your Top Drive Handle It?
Authors: Deutsch Eric
Published: March 2009

As deepwater drilling has advanced, the weight expected to be borne by a top drive has increased to levels at or near the load rating of the machine. The single load rating number normally associated with a top drive model (e.g. 1000 ton) is a nominal figure that may not apply to every operating situation. A typical top drive has two main load paths: hoisting and drilling. Hoisting load passes through the elevators and link hanger, while drilling load passes through the saver sub, IBOPs, and main shaft bottom end connection. Limitations inherent to rotary shouldered connections can lead to diminished drilling load capacity vis-à-vis hoisting. Further complicating matters is the fact that the drilling load path is governed by disparate API specifications: 7 and 8C. These two specifications provide different calculation guidelines with regard to safety factors and are subject to a certain amount of interpretation.

The end result is confusion about how much load a top drive can realistically handle. A 1000 ton top drive may not be officially rated to hoist 1000 tons through its IBOPs. Additionally, API sets forth a different load rating for the swivel bearing, so load rating for rotation differs from overall top drive load rating. This paper discusses the technical aspects of top drive load rating and clarifies the usable load capacity of a top drive in real-world conditions.
A Seasonal Solution for Offshore Drilling in an Ice Environment
Authors: Keener Chip , Allan Rod
Published: March 2009

The promising potential of prolific hydrocarbon reserves in the difficult Arctic ice environment has spurred accelerating lease activity particularly in the US and Canadian Beaufort Sea, and the Chukchi Sea. The obstacles are formidable: The leases may only be ice clear a few months a year.The fall and early winter months expose severe weather analogous to a North Sea wind and wave environment.Winterization measures must consider potential of severe icing.The vessel hull and exposed machinery must tolerate temperatures of −40° C.The ice management strategy must anticipate operations in one-year ice (sheet ice to a 1.5 meter thickness with rubble fields, occasional multi-year inclusions, and modest ridges).Logistic lines are long and tedious, motivating an unparalleled level of self-sufficiency.Water depths range from 50 meters or less to extreme depth, confounding a station-keeping solution.Heavy ice and formidable ridges compel an exodus mid-winter through mid-summer, and obligate consideration for off-season marketability and high speed open water transit.Consideration must be given for wintering over … in contingency or with ambition to extend the season.Extreme environmental sensitivity will be expected.

Against these challenges, a fit-for-purpose vessel has been conceived. optimized for extended-season operations in the Arctic, and uncompromised ultra-deepwater off-season performance in a more hospitable environment.
Confidence Limits Associated With Values of the Earth's Magnetic Field used for Directional Drilling
Authors: Macmillan Susan , McKay Allan , Grindrod Steve
Published: March 2009

This paper describes updated uncertainties for use with predicted geomagnetic parameters within magnetic Measurement-While-Drilling (MWD) survey tool error models. These models are used to define positional error ellipsoids along the wellbore which assist in hitting geological targets and missing existing wellbores.

The declination, dip angle and total field strength of the Earth's magnetic field are used with magnetic survey tools for surveying the wellbore. These values are often obtained from mathematical models such as the British Geological Survey Global Geomagnetic Model (BGGM). As the Earth's magnetic field is continually varying with time the BGGM is updated annually to maintain accuracy. However a global predictive model cannot capture all sources of the Earth's magnetic field which results in uncertainties of the predicted parameters. The Industry Steering Committee on Wellbore Surveying Accuracy (ISCWSA) published a MWD error model in 2000 (Williamson, 2000). The geomagnetic field uncertainties that are part of this model were derived from work done by the BGS in the early 1990s. Since then more accurate data from magnetic survey satellites have been introduced into the BGGM and the uncertainty of the predicted geomagnetic field parameters has been reduced.

The original approach to deriving the uncertainties involved separating the various error sources in the magnetic field and assessing them individually. This paper uses a simpler approach where clean orientated magnetic down-hole data are simulated using geomagnetic observatory data. Spot absolute measurements of the magnetic field made at observatories around the world are adjusted for the crustal magnetic field to make them more representative of hydrocarbon geology. The adjusted observatory data are then compared with the predicted values from the BGGM to assess the uncertainty. The uncertainties do not fit a ‘normal’ distribution so they are expressed as limits for various confidence levels. They vary with time and with location and, in their derivation, do not assume any underlying empirical error distribution. Options to further reduce the uncertainties using data from local magnetic surveys (In-Field Referencing) and observatories (Interpolation In-Field Referencing) are also described.

The use of the revised geomagnetic uncertainty values in the MWD error model will reduce wellbore position uncertainty to reflect the increased accuracy from recent improvements in geomagnetic modelling.
Precise Management of Downhole Pressure Enhances Safety and Enables Access of Challenging Offshore Reserves
Authors: Grayson Brian
Published: March 2009

The global demand for oil and gas is continually growing, while the world's resources are becoming increasing more difficult to obtain as the less problematic and operationally straightforward prospects dwindle. A majority of the industry's efforts are being spent in the identification and development of new methods and technologies to enable access and production from these resources where accessibility is technically challenging and hazardous due to difficult drilling environments or geological hazards, or both. At the same time, health, safety and environmental risks are more of a concern than ever before. Exposure to these difficulties is even more evident and challenging in offshore operations where not only the technical problems exist, but now logistics becomes a bigger issue.

Over the past several years, significant advancements have been made towards methodologies and technologies that allow for better control and management of downhole and surface pressure during the drilling and completions of onshore and offshore wells. The technology advancements and lessons learned through the evolution of Managed Pressure Drilling (MPD) techniques are now being utilized to increase safety and drilling operation's efficiencies, and allowing for access of previously inaccessible reserves. MPD is being used as a mitigating technology to eliminate non-productive time (NPT) problems, such as time spent during kick-loss scenarios and reduction of well costs by minimizing the number of casing strings. For many projects, MPD has become the enabling technology that permits feasibility of drilling and completion of the prospect.

This paper will describe the processes and variations, and the technologies used with MPD. It will further detail how MPD techniques are being applied as an enabling technology to a variety of onshore and offshore operations to increase the safety of rig crew and surrounding environment and overcome the problems associated with today's challenging wells.
Intelligent and Interventionless Zonal Isolation for Well Integrity in Italy
Authors: Moroni Nevio , Zanchi Augusto , Barbieri Enrico , Ravi Kris , Mesmacque Anne , D'Ancona Evasio
Published: March 2009

Cement-sheath integrity is fundamentally important for well integrity and helps to ensure that the asset is operated safely and economically. If the cement sheath is damaged during well operations, it could lead to interzonal communication, annular pressure, and casing damage. Remedial jobs are then necessary to fix the problem and continue well operation. In some cases, it might not be economical to fix the problem, leading to well abandonment.

The challenge to cement-sheath integrity is caused by the stresses resulting from change in pressure and temperature during well operation. Examples of wells that could be subjected to changes in pressure and temperature are deepwater, high-pressure high-temperature (HPHT), gas storage, steam injection, and geothermal. Gas storage wells in Italy are addressed in this work. An integrated, intelligent, and interventionless solution has been applied to solve the zonal-isolation challenges in such wells. The well events during the life cycle were integrated into the analysis and a cement sheath was designed and tested so that it was not damaged. Safety considerations were built into the design procedures based on the teachings of designs of other materials. This design procedure helped the cement sheath withstand cyclic loads, which could be significant in gas storage wells.

During well operations, if the stresses on the cement sheath exceed the design limits, the cement sheath could be damaged. The initial damage could be in the form of small cracks and micro-annuli. If these damages can be fixed immediately and without intervention, then the formation fluid can be prevented from entering the annulus. Intelligent features were built into the cement sheath so that small cracks and micro-annuli could be automatically sealed if formation fluid enters the annulus.

The integrated, intelligent, and interventionless zonal-isolation features of the solution offer a unique opportunity to prevent the annular pressure buildup if the cement sheath inadvertently fails. This solution has been implemented in a number of wells and is described in this work. The job implementation and subsequent results during the life of the wells have been successful. The unique features of the solution discussed and presented in this work is a game-changer and should help the industry solve a pressing problem and operate wells safely and economically.
Case Histories of a New Wireline Logging Tool for Determination of Free Point in Support of Drilling and Pipe Recovery Operations
Authors: Kessler Calvin , Dorffer Daniel , Crawford Don , DeHart Rory , Weiser Jerry
Published: March 2009

A new logging tool that is will identify the free point in drill collars, drill pipe, tubing, or casing has been developed and field tested. The tool is commercially available in the wireline service sector for drilling support and well abandonment operations. Unlike previous free point methods, which used strain measurements of the pipe obtained as a series of stations with and without the application of pipe stretch or torque at each station, this new method is simply overlay of two logging passes. The first logging pass is recorded with the pipe in a neutral weight condition, and the second logging pass is recorded with tension or torque applied to the pipe. The tool utilizes the property of steel called magnetostrictive effect. When a mechanical stress is applied to the steel, the magnetization of the material is modified. Thus when torque or tension is applied to the pipe that is free to move, their magnetization will change. If the pipe is not free to move their magnetization will remain the same. The tool has been successfully tested in steel alloys that have minimal magnetic properties.

This new logging tool has many advantages over legacy free pipe determination methods. First, from a rig safety standpoint, the application of pipe stretch, or torque is applied only once for a few minutes for the logging pass. With legacy free point methods numerous stationary measurements were required, with the pipe being stretched/torqued at each station. Since determination of free point is a comparison of two logging passes, real time operations and 24/7 satellite communications allow remote based operator and service company pipe recovery experts to be involved with the well site decisions. While this new technology uses a comparison of two logging passes, well site operations is not dependent on a pipe recovery expert with extensive hands on experience to be on location, or delays waiting for pipe recovery experts to arrive on location. This benefit is extremely important with the aging of the industries workforce.

The small diameter logging tool is run centralized, and does not require weight bars added to the tool for slip engagement, this shortens the length of the tool string and simplifies e-line rig up procedures.
Drilling a 2-inch in Diameter Hole in Granites Submerged in Water by CO2 Lasers
Authors: Kobayashi Toshio , Nakamura Masahiro , Kubo Satoshi , Ichikawa Makoto
Published: March 2009

As part of a fundamental study of rock drilling by laser irradiation, this paper describes laser drilling of a 2-inch-in-diameter hole in granites submerged in water. In the air, fused rock produced by laser irradiation reflects or absorbs successively irradiated laser beams, thereby refraining laser heat from being transmitted into the rock. This absorption leads both to a temperature rise of the fused rock and a further increase in absorption of laser radiation by the fused rock, causing the rock destruction process to cease completely. From consideration of the lack of success in past laser rock drilling methods, we arrived at the idea that laser-induced mechanical forces could be utilized to generate a hole in rocks by laser irradiation in water. A granite specimen was submerged at 50mm from a water-surface and then 10.6 pm carbon dioxide laser (CO2) beams which have a high absorption coefficient in water were intermittently irradiated. The laser beams induced underwater shock waves, bubble formations, and micro-water jet formations upon bubble collapse.

High-speed video observations revealed the generation of an initial cone-shaped cavity in the water, propagation of the laser beams through the cavity and eventual ablation of the granite surface. The laser beams locally melt the granite surface to form small glassy beads, which are readily removable by mechanical methods. Repetition of this procedure demonstrated that a high-power laser beam propagating in water can be used to generate a hole in rocks. The laser beam irradiation indeed drilled the granite specimen submerged in the water. A 2-inch-in-diameter hole in the underwater granites was successfully generated by two methods that were melting and spalling by the laser. Melting the granite to generate a 2-inch-in-diameter hole requires energy almost 3 times as much as spalling the granite to generate the same size hole.
Coring Unconsolidated Formation—Lower Fars: A Case Study
Authors: Al-Sammak Ibrahim , Ahmed K. , De Santanu , Al-Bous Faisal , Ahmad Fatma , Abbas Faisal
Published: March 2009

Lower Fars is a shallow unconsolidated sandstone reservoir with high inter-granular porosity filled with heavy oil in southern part of Ratqa Field in Kuwait. The shallow depth (500′ to 800′), friable sand laminated with shale and high viscosity heavy oil in pores have made coring this sand quite challenging. Last recovered core with rubber-sleeved core barrel in the eighties was only up to 60%.

This paper describes how thoughtful mix-up of technology, innovative techniques and proper coordination by aligning all concerned has helped in meeting the challenge of coring unconsolidated sand and it's processing.

Using low invasive core fluid, shorter core length, Aluminum inner core barrel, separate core bit to cut major sand / shale, full core catcher system, vertical slabbing at well mouth and on-site freezing have improved core recovery in excess of 85%.

While low-solid content coring fluid with a pH of 9 resulted in low mud invasion, reduced WOB, ROP and SPM ensured fewer washouts during coring. Low abrasive core head with clam shell full closure core catcher produced good recovery. Core barrel length was reduced from standard 30′ to 10′, which was slabbed to 3′ size keeping barrel vertically at well mouth. At well site it was frozen vertically with foam on top to minimise lateral movement and transported in freezer. At Core Lab it was kept frozen with dry ice, slabbed and plugged with liquid N2.

It is expected that the obtained core plugs from similarly cored 6 wells shall lead to meaningful Routine and Special Core Analysis, which was suspected in old cores. This would help in developing the depositional geological model in conjunction with the image logs.
An Innovative Stimulation Approach for Horizontal Power Injectors in Sandstone Reservoir, Saudi Arabia: Field Experience
Authors: Al-Zain Ahmed , Al-Driweesh S. , Al-Jandal A. , Said R. X. , Metwally S. , Abitrabi A.
Published: March 2009

Acid stimulation systems to remove formation damage are very well established for vertical injectors, drilled during the early development of a sandstone reservoir in central Saudi Arabia. With the advent of horizontal technology, new injectors are drilled with thousands of feet of horizontal section to expose large reservoir area for injection. The conventional acid stimulation programs, applied on vertical wells, would be impractical and very expensive for horizontal wells due to the expected large quantities of acid and other associated chemicals.

An innovative acid stimulation approach has been introduced for stimulating sandstone horizontal injectors in central Saudi Arabia. The new approach, which has been applied on horizontal injectors, consists of a foam cleanout to condition the horizontal section followed by main acid stimulation using optimized acid volume and overdisplacement of spent acid into the formation.

This innovative stimulation program provides an efficient and cost-effective method to condition the horizontal section by removing as much as possible of drilling mud cake, filtrates, and possible biomass. It also allows acid treatment to be optimized for stimulating the formation rather than only for removal of mud cake. This paper discusses in detail the successful application of the innovative approach and presents the post-job injectivity tests and results.
Investigations of Stress-Dependent Petrophysical Properties of Coalbed Methane (CBM)
Authors: Shedid Shedid A. , Rahman Khalil
Published: March 2009

The increase of successful exploration and economical importance of coalbed methane makes the understanding of petrophysical properties-stress-dependent more essential.

The influences of net stress on porosity, permeability, and reservoir quality index of Australian coalbed methane (CBM) formation are experimentally investigated. Two groups of low permeability from 0.01 to 1.5 md and medium permeability from 5.21 to 13.22 md actual CBM samples were used to perform this study. The variation of porosity, permeability, permeability-porosity ratio (K/φ) and reservoir quality index (RQI) under different stress conditions is studied. Current permeability-porosity models under stress are tested using the newly-attained experimental results from this study.

New correlations were developed capable to be used as simple tools for predicting changes of petrophysical properties with stress. Attained results also indicated that the reduction rate of porosity of low and medium permeability CBM samples can be represented by a straight-line equation form while the permeability reduction of low and medium permeability CBM formations is confidently followed an exponentially reduction mode. The increase of net stress causes a reduction in both ( K/φ) and RQI values. The results also revealed that the effect of stress is more dominant for low permeability samples than that ones for medium permeability CBM.
Well Placement by Boundary Detection / Optimization of Horizontal Well Performance: A Case Study From U.A.E.
Authors: El-Hamawi M. , Al-Amari Khalid , Al Shehhi Noora , Saleh M. , Mirto E. , Madjidi A.
Published: March 2009

Placing a horizontal well successfully within the target reservoir layers of uneven surfaces with uncertainties in dip and thickness is not a simple task, particularly in areas structurally disturbed. The level of difficulty increase when the well intersects a sub-seismic fault of unknown attributes. In such cases it becomes very difficult to decide which way to steer the well, so that it could re-enter the zone of interest, or which part of the reservoir is drilled after intersecting the fault.

A limitation to geological steering is the relatively small volume of investigation of the traditional logging while-drilling (LWD) sensors, which can typically probe no farther than few inches into the formation.

A new LWD directional, deep electromagnetic propagation service was recently developed with a much larger radial response that delivers distance and direction to the nearest change in resistivity within a formation, in addition to the resistivity of each of the formation layers.

A case study is presented onshore Abu Dhabi field of the United Arab Emirates, where information from the deep directional propagation LWD tool, together with near-the-bit direction and inclination measurements enabled to take proactive and timely corrective drilling actions to optimize the placement of the well path. A team from Petroleum Development and Drilling was formed with specific objectives to maximize reservoir exposure and minimize drilling risk and to insure 24 hours communication and real time data transmission between service and operating companies. The result was a well with 100% of its length in the desired reservoir. It was possible to achieve the field production target for this gas reservoir, drilling only 5 of the 7 wells originally planned.
Underbalanced Drilling Technology Adds Reserves and Enhances Ultimate Recovery
Authors: Babajan Salar , Qutob Hani
Published: March 2009

The current world petroleum industry situation is that: ➢Exploration is difficult and costs are increasing.➢The majority of hydrocarbons being exploited today are found in existing pressure depleted or complex and lower quality reservoirs➢Current oil prices are at their highest

Thus, world circumstances have forced today's petroleum industry to rethink both its operating methods and technologies aiming at improving recovery and reducing cost. It is believed that adoption of new technologies is the most important factor in adding reserves, enhancing recovery, reducing cost and increasing revenue. Underbalanced drilling technology is now seen as the way to achieve these objectives.

Introduction

Underbalanced Drilling – UBD- main objectives are: ➢Preventing formation damage and improving Reservoir Benefits.➢Improving Drilling Performance & Preventing Conventional Drilling Problems.

This paper discusses in details the reservoir benefits part of underbalanced drilling technology.

What is Underbalanced Drilling?

Underbalanced Drilling is the intentional reduction of the drilling fluid density causing the hydrostatic pressure in a well bore to be lower than the pore pressure within a formation thereby permitting reservoir fluids to be produced while drilling.

Underbalanced Drilling benefits the reservoir by simply adding reserves through: ➢Discovery of new zones➢Reducing formation damage and increasing intra-zone contribution➢Lowering abandonment increasing well drainage area➢Accessing challenging reservoirs➢Providing real time reservoir evaluation / characterization.

Although UBD has many advantages, it is not a magic potion for all fields, wells or drilling problems. Poor execution and planning would result in an over-enthusiastic misapplication of the technology, and possibly failure. Several real results and case studies will be presented and discussed in this paper.