bluuebunny/crossref_metadata_2025_split huggingface dataset:
No-Damage Drilling: How to Achieve this Challenging Goal?
Authors: Santos Helio , Olaya Jesus 
Published: December 2007

Abstract
No-Damage DrillingSM is the ultimate goal of all well construction activities, by providing a way to explore and produce the hydrocarbon reserves with minimum reduction of the natural permeability of the reservoir rocks. Conventional drilling is conducted with an over-balanced pressure on the reservoir formation, which causes the drilling fluid to invade and damage the rock.
The industry has been trying to come up with alternatives and underbalanced drilling UBD has grown in popularity during the last years. However, in many situations UBD is not feasible to be used, due to economical and/or technical reasons. In cases UBD is not used, a drilling fluid with an overbalanced pressure should be used. A new drilling fluid called Non-Invasive FluidSM – NIFSM has been developed and is in the market to fill this gap.
The goal of this paper is to present a new concept, called No-Damage Drilling, addressing the most important points during a well construction activity. The paper describes the different techniques available to achieve the goal of drilling a well with no-damage, including UBD and drilling fluids. A new drilling fluid is described, which has the capability of not invading the rock when a certain overbalance is applied, and the unique technology of the fluid allows an extremely easy removal of the seal, guaranteeing an effective restoration of the original permeability of the rock.
The paper presents laboratory tests conducted to evaluate the performance of UBD and drilling fluids related to formation damage, as well as several case histories showing that with careful planning and proper technology a successful No-Damage Drilling operation is possible to be achieved. The paper finally addresses the main points to be followed to decide the best technological option to drill with no-damage, based on a series of questions specially developed.
Sag of Weight Materials in Oil Based Drilling Fluids
Authors: Saasen Arild 
Published: December 2007

Abstract
To be able to keep a well under control during drilling it is important to have the weight material suspended during the whole operation. Especially in oil based, or synthetic based drilling fluids, controlling sag is difficult. A large number of wells have experienced lost circulation or well control problems with the associated high costs relating to sag. There are limited field proven methods available to predict the potential for sag for a particular drilling fluid. Therefore, barite sag continues to be one of the most difficult tasks to handle for a drilling fluid engineer. It is well known that standard viscosity readings cannot be used to predict the sag potential of a drilling fluid.
The current paper discusses in detail the mechanisms of sag in oil based drilling fluid and how to treat sag. It is shown that at ultra-low shear rates the oil based drilling fluid is shear thickening as opposed to the shear thinning effect observed at higher shear rates. It is described how this shear thickening behaviour leads to sag if the drilling fluid composition is incomplete. It is described how organophilic clay should be used to minimize sag and why different types of clay have different effect onto hindering sag although none of these differences have to be visible on standard viscometer readings. Furthermore, it is suggested that "modifiers" generally have little effect on preventing sag. Different methods to monitor or predict the sag potential of drilling fluids are also outlined. Dilution of the drilling fluid normally results in increased sag. Good practice is that the dilution with new drilling fluid should be minimized to control the sag properties of the oil based drilling fluid.
One Hole Section-Two Fluids: Optimizing Drilling and Drill In Through Reverse Sequence Solution Engineering
Authors: Reeve Jack , Jones Tom , McNair Gary , Pin Hu Jia 
Published: December 2007

Abstract
An Offshore China/South China Sea operator wanted to optimize the use of a rotary steerable drilling assembly, simplify and reduce operational steps, and provide a larger reservoir wellbore. The operator elected to drill a single 8.5" wellbore and, in order to address a variety of issues and potential problems, change from a Cloud Point Glycol Drilling Fluid to a Drill-In Fluid (DIF) at the reservoir entry point. A reverse sequence solution engineering process was employed wherein planning began from the point of view of a completed well.
Cuttings Transport in Directional and Horizontal Wells While Aerated Mud Drilling
Authors: Naganawa Shigemi , Oikawa Atsushi , Masuda Yoshihiro , Tetsuo Yonezawa , Hoshino Masashi , Acuna P. 
Published: December 2007

Abstract
Cuttings transport in aerated mud drilling for inclined annuli with inclination angles between 30° to horizontal was investigated. Experiments were carried out for over 300 flow conditions using a 9-m long un-pressurized annular test section with 5-in. CSG and 2-in. DP, concentric or eccentric annulus geometry. Two types of base liquids, water and PHPA solution, were used for aerated muds. In the experiments, cuttings were fed into the test section at a constant rate corresponding to a supposed ROP, and the volumetric concentration of cuttings in the annulus under steady state was measured. From the analysis on the variation of cuttings concentration with mud flow rates ranging from sub-critical to critical regions, the critical flow rate (CFR) criterion avoiding a formation of cuttings bed was found to correspond to the cuttings concentration of about 4 vol%. The annular velocity (AV) equivalent to the CFR was as high as 2 m/s in highly inclined eccentric annulus using non-Newtonian conventional PHPA fluid. Air injection significantly reduced the CFR and improved the cuttings transport efficiency in highly inclined annulus except for the horizontal annulus in which much higher AV of about 1.5 m/s was still required to transport cuttings effectively. The result indicates that the flow pattern between gas and liquid considerably affects the cuttings transport performance.
Experimental Determination of Adhesive-Cohesive Bond Strength (ACBS) and Adhesion-Cohesion Modulus (ACM) of Mudcakes
Authors: Amanullah Md. 
Published: December 2007

Abstract
A unique test procedure and a novel test facility have been developed for experimental determination of the adhesive-cohesive bond strength (ACBS) and the adhesion-cohesion modulus (ACM) of mudcakes formed by different mud systems. The test set up consists of a Wykeham Farrance stepless compression machine to embed a cylindrical foot up to a particular depth of the mudcake matrix and then to apply a pulling force to unstuck the cylindrical foot from the mudcake matrix, a digital dial gauge to register the depth of embedment and upward displacement during loading and unstucking process, an electronic balance to register the driving/pulling force during embedment and pulling stages of the test as a function of displacement, a lab jack to elevate the mudcake to a desired height and a PC-based automatic data acquisition system to record the data and monitor the test.
Experimental results indicate significant variations in ACBS and ACM of mudcakes for an identical depth of embedment depending on the composition of the mudcakes. The magnitude of the pulling force and the shape of the force-versus decrease in embedded area curve are influenced by adhesive and cohesive bonding potential of the mudcake material and the nature of the adhesive and cohesive bonds. The presence of electrolyte significantly influences the metal to mudcake and mineral to mineral bonding. The hydrated ionic diameter of the cations also has some effect on the adhesion and cohesion properties of mudcakes. The presence of barite within the mudcake matrix causes a significant increase in ACBS and ACM of the mudcakes probably due to the filler and mass adhesion effects of barite particles along with the molecular forces of interactions. The effect of three fluid loss additives such as modified starch, CMC and PAC on the ACBS properties of NaCl-Bentonite mudcakes has also been investigated. The presence of CMC and modified starch in NaCl-bentonite muds has little effect in the ACBS and ACM of NaCl-bentonite mudcakes. However, the presence of PAC in NaCl-bentonite mudcake causes some increase in ACBS but a significant reduction in ACM. The results of the test could provide useful information regarding bonding potential of different mudcakes to drill pipes, reamers, stabilisers and drill bits and also drill cuttings in case of cuttings bed formation in directional and horizontal wellbores. The test method can be used for mechanical screening of drilling mud additives and the results can be used in designing drilling muds to produce desirable mudcake quality.
New Shared Organization-Learned Project Management System provides a Knowledge Hub for Integrated Reservoir Optimization
Authors: Drnec M. L. , Balci B. , Etkind J. 
Published: December 2007

Abstract
Knowledge capture, distillation, preservation, and sharing among project teams are challenging issues across widely distributed organizations. The teams need to share information, learn about and apply best practices and lessons learnt, in a structured, easily accessible manner: anytime and anywhere. The implementation of a project management system integrating worldwide, web-accessible organizational-learned knowledge hub is presented in this paper.
A Project Knowledge Portal (PKP) was implemented; containing links to corporate web based Knowledge Hub, including a structured repository for all project critical information. The Integrated Project Management System (IPMS) was developed as a process matrix, based on a company wide implemented standard. The PKP uses the IPMS to create an ISO 9001 compliant structure behind all applied project processes.
Organizational knowledge is generated, captured, distributed and preserved throughout every stage of the project. The team uses the PKP to create a one-stop-shop for project knowledge. The project specific management system is stored in the Project hub together with all associated documentation such as standards, procedures, manuals, roles & responsibilities, audit & review systems, records, etc. All project members have access to the management system anytime. The records of the system are generated by team members and posted into the Project Hub. The required changes to the system are made via the Project Hub to the project member that maintains project specific management system.
Knowledge Management (KM) components of the web based PKP include real-time synchronous and a-synchronous E-collaboration tools to capture decision processes and have an audit-able trail for document control. The Portal includes a static filing repository in the form of the Schlumberger Knowledge Hub. QHSE Data, Lessons Learned and Best Practices are captured and made available for the rest of the organization. An example of implementation is presented in an actual project, with details of the roles and responsibilities and the impact on organizational learning.
Viscosity Predictions for Crude Oils and Crude Oil Emulsions Using Low Field NMR
Authors: Bryan J. , Kantzas A. , Bellehumeur C. 
Published: December 2007

Abstract
Knowledge of oil viscosity is vital to the petroleum industry, and is especially important when considering production of heavy oil and bitumen. As viscosity increases, conventional measurements become progressively less accurate and more difficult to obtain. Oil viscosities measured in the lab may also be not indicative of true in-situ viscosities. An alternate method is required for predicting oil viscosity, especially if this method can be applied in-situ. Stable crude oil emulsions are prevalent in many stages of the production and transport of heavy oil and bitumen. Knowledge of emulsion viscosity is necessary for determining energy requirements for transport and upgrading of the produced crude.
Low field nuclear magnetic resonance is examined in this work for its potential to predict viscosity of crude oil and crude oil emulsions. NMR is an attractive alternative to conventional viscosity measurements, because it can provide fast, unbiased and non-destructive data. A correlation is presented that predicts fluid viscosities from under 1 cP to over 3 000 000 cP over 25 – 80°C, making it valid over a wider range of viscosities and temperatures than any other published NMR viscosity correlation. With tuning, this model can predict very accurate changes in viscosity with temperature for a single oil. An NMR emulsion viscosity model is also presented that uses the oil viscosity and water fraction, both determined from NMR, to predict emulsion viscosity. This correlation is able to provide order of magnitude emulsion viscosity predictions for a wide range of emulsion water cuts and viscosities. Work has also been done to extend the viscosity predictions to in-situ viscosity measurements, which can then be extracted from logs. Preliminary findings on in-situ oil viscosity are encouraging, and indicate that NMR has great potential as a tool for in-situ viscosity determination.
Characterization of Acid Gas Diffusion in a Carbonate Fractured Reservoir through Experimental Studies, Numerical Simulation and Field Pilots
Authors: Lagalaye Y. , Nectoux A. , James N. 
Published: December 2007

Abstract
Injection of acid gases in fractured reservoirs will be one of most challenging issue in the future for many carbonate fields over the world.
A genuine integrated approach to characterize acid gases diffusion on a carbonate fractured gas field has been developed including laboratory experiments, huff & puff pilots, experiments history match and up-scaling for a full-field dual-porosity model.
First, pre-simulation have been realized to appreciate the feasibility of measurements of acid gas diffusion between a diffusion chamber (pseudo-fracture) and a core saturated by field representative acid gas and irreducible water.
Second, an original laboratory experiment enabling acid gases diffusion measurements has been successfully realized.
Third an history match of the experiment at small scale has been realized. Activity corrected molecular diffusion coefficients and tortuosities have then been up-scaled at 3D full-field scale for a dual medium system passing by intermediate up-scaling models.
Meanwhile huff & puff pilots injecting pure methane have been conducted. The final history match of these pilots enabled to evaluate both diffusion phenomenon and exchange surface between fracture and matrix medium.
The availability of this diffusion characterization for an acid gas injection is ensured by the use of the activity-corrected diffusion formulation which makes the diffusion coefficients independent on pressure, temperature and phase composition under specific conditions.
This method enabled to evaluate with a good confidence the economy of an acid gas re-injection project on a fractured reservoir. It makes possible acid gas diffusion mechanisms and block size evaluation.
The laboratory experiment constitutes a new technical approach to evaluate a fractured medium acid gas diffusion.
The technique used to match and upscale the mechanism constitutes also a technical breakthrough.
Finally the method integrating laboratory experiments, compositional dynamic up-scaling and operational pilots for acid gas diffusion characterization in carbonate fractured medium constitutes a major technical improvement.
Inversion of Multi-Phase Petrophysical Properties Using Pumpout Sampling Data Acquired with a Wireline Formation Tester
Authors: Wu Jianghui , Torres-Verdín Carlos , Proett Mark A. , Sepehrnoori Kamy , Belanger David 
Published: December 2007

Abstract
Modem pumpout wireline formation testers (PWFTs) can collect a wide array of data during the pumpout phase of fluid sampling. Both flow rate and pressure are sampled in time during the pumping process and are used to infer apparent permeabilities under the assumption of single-phase fluid flow. Numerical simulation of multi-phase flow has been successfully used to describe filtrate invasion and the resulting pumpout contamination as a function of pumping time and rate. Recent developments in invasion modeling also allow one to simulate the invasion profile for either water-base or oil-base filtrate invasion when the mud properties are coupled to the invasion process. Because of these developments, it is now possible to determine more complex multi-phase petrophysical properties of rock formations. In this paper, we report on a new inversion technique used to estimate petrophysical formation properties from data acquired by a PWFT.
First, a 3D numerical sensitivity study of PWFT data is carried out over a wide range of formation properties including variations of permeability, anisotropy ratio, and porosity. Results from this sensitivity analysis are used as test cases for the inversion algorithm to estimate formation parameters and their uncertainty in the presence of noisy measurements of pressure and flow rate. Inversion is performed making use of a neural network approach. We appraise the robustness and efficiency of the inversion algorithm with actual field data. The estimated formation parameters are further compared to core and wireline data.
Enhanced Gas Recovery by Carbon Dioxide Sequestration in Depleted Gas Reservoirs
Authors: Mamora D. D. , Seo J. G. 
Published: December 2007

Abstract
A depleted natural gas reservoir can store significantly more gas than a depleted oil reservoir (with the same initial hydrocarbon pore volume) for two reasons. First, ultimate gas recovery (about 65% of gas initially-in-place) is typically about twice that of oil (average 35% of oil initially-in-place). Second, gas is some 30 times more compressible than oil or water. CO2 has a critical temperature of 31°C (88°F) and a critical pressure of 7.38 MPa (1070 psia). Consequently, at pressures and temperatures typically encountered in the field, carbon dioxide will behave as a supercritical fluid. However, displacement of natural gas by supercritical CO2 has not been done in the field and is not well understood.
As part of a CO2 sequestration study, we have conducted experimental and analytical studies to evaluate the feasibility of displacing natural gas with supercritical CO2. The experiments involved injecting supercritical CO2 into an aluminum Hassler core-holder containing a 1-ft long by 1-in. diameter carbonate core initially saturated with methane. Rate and composition of the produced gas were measured, enabling determination of mole fraction of produced CO2 as a function of time. In addition, the core holder was CT scanned to determine core porosity, and CO2 and methane saturation. Experiments have been conducted for core pressures in the range, 500-3000 psig at 70°-140°F. Results indicate that some 73%-87% of the gas initially-in-place is recovered at CO2 breakthrough, with a low CO2 dispersion coefficient of 0.01-0.12 cm2/min.
We can tentatively conclude that CO2 injection into depleted or abandoned gas reservoirs would not only sequester CO2 but would also re-pressurize the reservoir, and most likely result in effective displacement of the gas. Thus, production of hitherto unrecoverable gas reserves could help defray the cost of CO2 sequestration: in short, a possible win-win technology.
New Underbalanced Perforating Technique Increases Completion Efficiency and Eliminates Costly Acid Stimulation
Authors: Behrmann L. A. , Hughes K. , Johnson A. B. , Walton I. C. 
Published: December 2007

Abstract
Cased and cemented horizontal wells in the East Painter field in Wyoming have historically been perforated with modest underbalance pressures of 300 to 600 psi and then acid-stimulated to achieve economical production rates. The moderate success rate and expensive acid stimulations provided the motivation to evaluate other options for obtaining cleaner perforations.
Conventional perforation-design techniques suggested that an underbalance of about 4000psi is needed to produce clean perforations for the low-permeability rock in this field. This would require a low wellbore pressure. An alternative is to use the PURE* (Perforating for Ultimate Reservoir Exploitation) system to create a high dynamic underbalance from a modest initial under or over balance. Two laboratory tests were conducted to evaluate these alternatives. The knowledge gained from these and other laboratory tests was used to modify the perforating techniques in the East Painter field to increase well production. Perforating gun design was changed, and the perforating process was modified to provide a substantial dynamic underbalance with only a modest initial underbalance.
This new dynamic underbalance concept provides transient underbalances up to about 80 percent of the reservoir pressure without applying the equivalent static initial underbalance. This technique increased well performance, and eliminated the costly acid stimulation step by generating cleaner perforations and higher effective shot density. In this paper, details of the gun modifications and perforating process will be described along with specific well-performance data. Comparisons to previous perforating practices are also included.
Successful Diversion of Acid Stimulation in Water Producing Oil Wells: Case Histories, Nisku Formation, Central Alberta
Authors: Henderson G. , Metcalf A. S. , Alderdice E. 
Published: December 2007

Abstract
Stimulation of carbonate oil and water producers with acid can result in an uneconomical increase in water production. This is the result of poor placement of the treatment stimulating the water-bearing rock preferentially to the oil. Typical treatments in the Nisku use selective tool isolation of zones to achieve the required placement control. The operational costs associated with this type of treatment make it difficult to perform economical stimulation treatments on marginal wells. Acid treatment of such a well, using only a diverting agent for control of placement, risks increased operational costs associated with possible increased water production and, therefore, the reduction of a marginal well to an uneconomical one.
A unique diverting material formed by the reaction of an aqueous solution of dibasic acids and rosin esters, with divalent cations, present in formation water or spent acid allows the selective stimulation of only the oil-producing zones. The reaction product is an oil-soluble precipitant. The oil-soluble nature of the diverter base materials and the resultant precipitants makes the likelihood of the precipitant forming in the oil zones remote; however, in the event of such a result, the produced oil will remove the precipitant.
Presented are laboratory tests describing the effectiveness of the oil-soluble material to divert acidic fluids away from water flows. Also, demonstrated is the subsequent cleanup of this oil-soluble diverting material using produced oil. In addition, several case histories from the Wayne area of Alberta, Canada are included. The results of these treatments demonstrate that control of acid placement in water-cut producers results in a considerable increase in oil production while minimizing the effect on water cuts. A significant reduction in the operational costs associated with switching from the selective tool isolation technique to the one described above is also demonstrated.