bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Formation Damage/Remediation Potential of Tight Reservoirs
Authors: Elkewidy Tarek Ibrahim 
Published: June 2013

Abstract
Oil or gas effective and relative permeabilities can be reduced to a great extent due to the invading liquid phase of the drill-in or completion fluid, contrary to the misconception that formation damage is less of a concern in lower permeability reservoirs (e.g., less than 5 md). Many laboratory, well logging, and formation tester data proved that mud filtrate (both from water- and oil-based muds) can deeply invade the formation enhanced by capillary forces. This will result in reduction of the oil or gas effective permeability, especially if the formation exhibits fluid emulsion blocks and phase trapping. Unfavorable interaction of the filtrate with the reservoir fluids and rock minerals can generate emulsions and precipitates. The same scenario may occur in hydraulically fractured formations.
An integrated multidisciplinary approach is pursued in this study to evaluate formation damage/remediation potential of low permeability reservoirs. The techniques involve different formation evaluation methods including core analysis, well logging, and well testing along with various cleanup scenarios. Furthermore, results from petrographic analysis and laboratory experiments (Micro and Macroscopic scales) are related and correlated with the larger Mesoscopic and Megascopic scales of well logs and well testing, respectively.
Results of these efforts lead to the following technical contributions; a) Delineation of the low permeability heterogeneous reservoirs, e.g. the Leduce carbonates, into their hydraulic units. b) Determination of the undamaged formation absolute and relative permeabilities along with the diameter of filtrate invasion. c) A rule of thumb is to minimize or prevent damage from taking place by selecting a drilling fluid that quickly forms an easily removable mudcake. d) Cleaning up damage due to water filtrate may be accomplished by just flowing the well and can be accelerated using solvents or surfactants. However, once the formation reaches its irreducible water saturation, remediating water saturation below the irreducible value may not significantly improve its permeability.
Three-Dimensional Sonic and Anisotropy Data to Provide Effective Fracture Treatments
Authors: Smith Charles H. , Hamilton Layne , Bashkirtseva Alena 
Published: June 2013

Abstract
Hydraulic fracturing has become a common completion treatment or stimulation treatment for horizontal wells; however, effectiveness of these treatments, in terms of improved production, is difficult to predict. One reason for uncertain production results is poor fracture initiation in the reservoir, which can be caused by drilling-induced damage or a formation's natural resistance to breakage.
Several approaches have been attempted to solve this problem and provide a better return on completion investment. One approach that has achieved strong initial results is the use of dipole sonic logs to determine closure stress. From closure stress, formation breakdown pressures can be determined, which are used to design more effective treatments and place them more efficiently in the well and reservoir, where breakdown pressures are lower. This paper presents research to validate this approach.
Two wells were selected in the same area and geologic setting. The first was completed using standard processes for this asset. A dipole sonic log was run in the horizontal wellbore before beginning the completion. Results from the sonic log were compared to the fracture treatments after the fact.
In a second vertical pilot well, information was acquired, including elemental capture, dipole sonic, and nuclear magnetic resonance, with the objective of determining rock texture, vertical and horizontal rock mechanical properties, effective porosity, and permeability. A dipole sonic was then run through the horizontal section of this second well to determine anisotropy. This knowledge was used to select perforation and stage points in the horizontal well and design fracture treatments.
Two additional reservoirs are included in this paper where dipole sonic logs were run only in the horizontal cased hole but reference nearby pilot holes. Results from all cases were positive; therefore, it is believed that this technique can be useful in any reservoir.
Foam And Scale Inhibitor Squeeze With Natural Gas: A Lifeline For Water Flooded And Damaged Gas Well
Authors: Rauf O. , Gerdes S. , Lummer N. R. 
Published: June 2013

Abstract
It is commonly seen that water accumulation and near wellbore damage leads to the loss of production. This phenomenon had also been observed in many gas fields in Germany. Five years ago foam & scale inhibitor batch (FSIB) technique was applied but it remained successful only in few fields as only fluid pumping with chemicals was the part of this technique.
Foam & scale inhibitor squeeze (FSIS), a novel technique was developed that involves natural gas pumping along with chemicals. It has been done by using high pressure mobile natural gas compressor. This technique is based on several steps during which foam water as based along with additives (like scale inhibitors, chelating agent etc.) comingled with natural gas are being pumped in the well. In final step compressed natural gas is also bullheaded to displace the pumped chemicals in to the formation.
FSIS has been successfully applied to bring water flooded and damage wells (with no production) back to production. Many targets can be achieved in one job by applying this technique like: removal of water in near wellbore region, cleaning from scales, well kick-off to production in quick time after treatment (due to comingled and displaced gas and reduced hydrostatic pressure), less down time, economy and no effect of produced gas quality.
This report would elaborate the difference between the two techniques Foam & scale inhibitor Batch (FSIB) and Foam & scale inhibitor squeeze (FSIS). Job procedure and benefits associated with these techniques will also be presented along field results.
Evaluation of RPMs in Heterogeneous Cores - Fracture Scale do Matter
Authors: Restrepo Alejandro , Lopera Sergio , Ocampo Alonso , Castro Eber 
Published: June 2013

Abstract
From theoretical work related to production mechanisms to the development and application of preventative and remedial technologies, water control has been and continues to be a broadly studied subject in the oil industry. Although the last word appears to be elusive and trial and error approaches have led to mixed results, there are recent encouraging advances especially in complex systems such as those related to fractures where water arrival can seriously compromise field development plans.
The present work focuses on the study of polymer based RPMs in different petrophysical systems. Laboratory tests at reservoir conditions are documented for homogeneous, macro fractured and micro fractured sandstone cores representative from fields located in Colombian foothills, where active tectonics and compositional fluids are present.
According to relative permeability mesurements taken before and after treatment, RPMs performance can widely vary depending on the type of rock and water saturation range. Results suggest that a critical Sw exists in macrofractured systems above which RPM "swithches" its behaviour promoting higher Kw. Although this effect is not noted in homogeneous nor microfractured cores, there seems to be higher benefits in the last one in terms of kw reduction and final recovery.
Observations derived from this study are now of key value for planning and executing field tests throughout subject fields allowing to clasiffy target areas and tune expected benefits based on laboratory results.
Return Permeability: When A Single Number Can Lead You Astray In Fluid Selection
Authors: Offenbacher Matt , Luyster Mark , Gray Leigh , He Wenwu , Leonard Russell , Stephens Mike 
Published: June 2013

Abstract
Historically, return permeability testing has become a standard to establish minimally damaging fluid properties. This single number is typically focused upon for its simplicity, however the testing procedure and intermediate data provide much more than just this value. The process provides insight into formation damage mechanisms and their overall impact on potential well performance. The variable nature of procedures and apparatus as well as interpretation of data is regularly limited to the percent return permeability - a potentially misleading value in fluid selection. A thorough review of existing literature and experience on recent projects details the recognized potential for variability as well as misperceptions in interpreting results. Examples of test data are reviewed to capture damage mechanisms where fluid formulations require further optimization. In many cases conclusions are drawn and fail to identify why differences in the percent return permeability yields a particular result. Prior published work assessing formation damage tends to focus upon formation characteristics. This paper details the results and data typically provided with these analyses. These data include: fluid loss, initial return permeability, and techniques used to determine the damage mechanism. Test results are reviewed to illustrate where the risk of unwarranted conclusions occurs. Recommendations for appropriate analysis of both final return permeability and intermediate data are provided for optimized fluid design. Through the techniques discussed, testing procedures have the potential to provide the maximum insight into fluid-formation interactions on the core material available.
Risks, Mitigation and Management of Wax Production Chemistry in a SAGD Environment: Downhole to Surface and Beyond
Authors: Shepherd Andrew G. , Vandeweyer Tony , Rafik Dena , van Kins Simon , Baksteen Erik , Cheong Anthony 
Published: June 2013

Abstract
Precipitation, deposition and gelling of paraffins are common production chemistry challenges associated with upstream exploration and production. In this paper the different steps used to identify the wax-related issues from project to start-up and steady state are discussed. The development is a field under steam-assisted gravity drainage (SAGD). Critical to the mapping of production chemistry risks are the many specific analytical and modeling procedures employed. During the project stages, the main risks identified were: wax precipitation downhole and potential gelling of the export pipeline. Clear strategies were put in place to manage both these potential problems. During the start-up of the field, a number of wells were suffering from poor inflow performance. A downhole deposit was retrieved and analyzed. This was identified as wax, with an increase in paraffin distribution compared to the parent crude oil. Successful mitigation of wax deposition downhole was achieved for a selective number of wells using a combination of fluid treatment and extended soak time. This suggests wax deposition is occurring in the near wellbore area. Noticeable effects of SAGD drive on the wax properties of individual well samples are observed reflected in increasing pour points (for wells where heat has broken through). No effect yet is observed on the export crude oil. Long-term surveillance for wells and the facility will continue to rely on wax measurements in combination with tubing head temperatures. Mitigation options will be further developed for continuous operational improvement.
An Investigation of the Plugging Mechanisms in a Slotted Liner from the Steam Assisted Gravity Operations
Authors: Romanova U. G. , Ma T. 
Published: June 2013

Abstract
A slotted liner recovered from the well 07P05 located in the McMurray formation of the Long Lake area, Canada, where Nexen Inc. is producing bitumen with the Steam Assisted Gravity Drainage (SAGD) technology, was investigated in the study. The study was aimed to determine the conditions of the liner and assist Nexen in identifying the mechanisms of the liner failure. The study included a physical examination of the liner, direct measurements of the liner aperture, permeability measurements, epoxy impregnation of the selected sections of the liner, and the analysis of plugging material and surface of slots. The study results show the corrosion and/or plugging and/or poor slot specification result in effective apertures being different than the specification. The study also shows that pressure drops across the liner sections are small, likely due to removal of the surface plugging clay and fines. The plugging material consists of large amount of corrosion products, significant amount of iron sulphide, clay fines (mostly kaolinite), and some quartz grains. The examination of the slots show that films of the plugging material consisting of predominantly corrosion products and clay, gradually choking slots.
Type Curves for Injectivity Decline
Authors: Kalantariasl Azim , Duhan Sundeep , Bedrikovetsky Pavel 
Published: June 2013

Abstract
Injectivity decline is a wide spread phenomenon for seawater injection, produced water re-injection, disposal of produced water in aquifers and whatever waterflood project with a poor quality injected water. The typical injectivity decline curves appear for impedance (normalised reciprocal to well index) versus PVI. They consist of linear growth interval for deep bed filtration, another interval for the linear growth during formation of external filter cake, ending up with the stabilised value. This paper discusses the stabilised impedance calculation.
The mathematical model for the stabilised impedance is based on the torque balance of attaching (electrostatic and permeate) and detaching (drag, lifting and gravity) forces exerting upon a particle on the cake surface. If compared with the previous models, this paper accounts for electrostatic force and for varying non-unit value of the permeate factor. It was shown that the electrostatic force can exceed other forces and cannot be neglected. Moreover, the permeate factor can highly exceed one. Accounting for the two above factors completely change the order of magnitude for the lever arm ratio as obtained from the stabilised injectivity, if compared with previous works. The lever arm was also calculated from the particle deformation by permeate and electrostatic forces using Hertz theory, resulting in the same order of magnitude as that obtained from well data. It validates the model for stabilised injectivity.
Analysis of 35 injector histories results in probabilistic distributions for 5 injectivity impairment coefficients, including the lever arm ratio. It provides with fully predictive tool for injectivity decline.
Drilling Depleted Reservoirs - Is Formation Damage Sometimes a Good Thing?
Authors: Byrne Michael , Oyovwevotu Joy , Retalie Ian 
Published: June 2013

Abstract
Drilling depleted reservoirs can present many challenges from a drilling, completion and production perspective. Formation damage due to increased overbalance for example, is well documented as a particular concern. But could we see some drilling benefit from increased formation damage at higher overbalance?
This paper will outline experience in drilling depleted reservoirs and discuss the impact of formation damage on well productivity, injectivity and drilling performance. In several examples, the benefits of formation damage outweigh the deficits and we propose a planned approach for future wells in depleted reservoirs. Formation damage is measured in the same way as for assessment of the productivity or injectivity impact but the data is applied to a different challenge. The additional pressure drop in the near wellbore area as a result of formation damage can protect the reservoir and minimise fracture propagation. Whilst formation damage can be important in depleted reservoirs it is largely irrelevant if wells cannot be drilled. With the method proposed wells can be planned, drilled, completed and produced (or injected).
The paper proposes better understanding of the impact of formation damage in order to enable drilling, completion and development of depleted reservoirs or intervals and proposes a new methodology to use formation damage as part of a well planning workflow.
Formation Damage Matters, Sometimes - Quantification of Damage Using Detailed Numerical Modeling
Authors: Byrne M , Rojas E 
Published: June 2013

Abstract
Formation damage sometimes has a significant impact on well productivity or injectivity. Much of the work undertaken to mitigate against formation damage serves to qualify the impact of damage and for example, determine the least damaging introduced fluids. Whilst qualification is important, quantification of damage impact is a much greater prize.
Taking advantage of increased computational power and speed, Computational Fluid Dynamics (CFD) has been applied in the last five years to numerically model and quantify flow restriction in wells and the near wellbore (Byrne et al 2009). This process enables better prediction of the real impact of formation damage on well productivity. The process has been applied to many real fields and wells and in this paper we present some of the latest revelations on the impact of formation damage on well performance.
In order to illustrate the simplicity of the process a sensitivity analysis of typical formation damage restrictions has been applied. This demonstrates the impact of different formation damage quantities and depths on different well trajectories and lengths in the same reservoir. In some cases the impact of damage that could be classed as "severe" in a laboratory test has little impact on eventual well productivity. In others the damage has a profound impact on well performance. With the obvious caveat that every well is different, we propose some consistent guidelines on the impact of damage based on our numerical modelling work.
Modelling of this kind does not reduce the necessity to understand or simulate damage, instead it enables focus where formation damage has greatest impact and creates a greater awareness of the importance of damage to our industry. Through increasing use of appropriate modelling, uncertainty is reduced and better wells can be drilled and completed.
Influence of Tensile Strength and Production Effects on Hydraulic Fracturing in Low Porosity Carbonates: The South Arne Case
Authors: Vejbæk Ole V. , Jakobsen Erik , Lamb Ricky , Troelsen Benny , Bazan Lucas W. , Brown Eric K. , Tran Phi , Meyer Bruce R. 
Published: June 2013

Abstract
Well planning in mature fields can be challenging as the more marginal reserves are targeted. Hydraulic fracture stimulation is a key technology to access multiple reservoir layers and thereby maximize recovery. However, fracture propagation in low porosity carbonates may be strongly confined because of high tensile strengths in bounding layers. The strong confinement can impede vertical fracture propagation and the ability to access reservoir units adjacent to the initiation interval. Understanding vertical hydraulic fracture growth through low porosity layers improves the hydraulic fracture design, enhances reservoir deliverability potential and enables the identification of infill well potential and intervention opportunities.
The South Arne field is located in the northern part of the Danish sector of the North Sea. The Tor and Ekofisk formations are high porosity/low permeability chalks with low to moderate natural fracturing. Porosities may reach 45%, but a hard low porosity interval of 10% or less at the bottom of the Ekofisk formation separates and partially compartmentalizes (horizontally) the two formations. A series of indirect tensile strength measurements on South Arne cores were conducted. The measurements verified a suspected exponential increase in tensile strength at low porosities, essentially causing the tensile strength to exceed 1,500 psi in some cases.
Recent 4D seismic surveys have enabled separate sweep patterns for each reservoir unit to be mapped and indicate that the sweep is much less efficient in the Ekofisk. This supports that the hydraulic fracture stimulation treatments initiated in the Tor formation are not accessing the upper units to the degree previously assumed and it appears that connection is occurring via pre-existing faults and/or natural fractures. The hydraulic fractures propagate nearly longitudinal to the wellbore, guided by regional stresses, with limited height growth. However, production effects, specifically compaction induced by draw down, may perturb the stress field sufficiently so that the preferred alignment is not achieved, further reducing sweep efficiency. This is indicated by 3D coupled geomechanical modeling and is corroborated by 4D seismic observations.
Particle Size Analysis For Sand Control Applications
Authors: Ballard Tracey , Beare Steve 
Published: June 2013

Abstract
Sand screen selection relies on accurate particle size information for the sands that need to be controlled. Within the oil industry there is awareness of the differences between dry sieve analysis and laser particle size analysis (LPSA), but there can also be wide variations between LPSA performed in different laboratories even when such variables as sample preparation are taken into consideration. Recent work by the authors has shown that such variables as sonication time and amplitude can have a significant effect on certain sands, and there is evidence to indicate that the sensitivity to sonication is dependent on the mineralogy of the sand. Other factors have also been examined to address the widespread view within the oil industry that LPSA exaggerates the fines content, whereas the opposite view is held in sedimentology and soil science in that the coarse fraction is believed to dominate. Work has been performed to examine which view might be most relevant for reservoir sands, and guidelines for performing LPSA are proposed.
Productivity Improvement in Highly Unconsolidated Formation: Skin Characterization and Mitigation, Case History
Authors: Lastre M. , Milne A. , Pinto C. 
Published: June 2013

Abstract
The productivity of highly permeable and unconsolidated sandstone reservoirs is expected to be high; however, the production seldom meets expectation as these reservoirs are more sensitive to the formation damage from the drilling and completion of the well.
There are extensive publications regarding characterization and identification of formation damage and the total final skin of thick unconsolidated oil reservoirs, with or without sand control (Okoye et al., 1992; Benion et al., 1994). However, many of the currently producing unconsolidated reservoirs are thin formations, with poor defined barriers producing heavy oil with a high water cut and sand production.
To optimize productivity in wells completed in multiple thin highly permeable sands it has proved necessary to develop a new completion optimization methodology. The methodology accounts for formation damage mechanisms and mechanical skin factors - completion, perforation and non-Darcy effects - to select the optimum production strategy and final completion, including sand control.
The completion optimization methodology can also be applied to existing wells to identify the factors limiting productivity and so evaluate the technical and economic of alternative remedial actions.
The methodology was applied in one field with 15 wells completed with gravel pack completions in thin laminated sandstone reservoirs ranging in height from 4 to 15ft. producing intermediate crude with an average rate of 2000 BFPD, despite a high positive skin. Initially the skin was attributed to formation damage - fines and scaling. However, the damage was correctly determined to be due to non-Darcy flow due to inadequate sand control. Recompleting these wells and changing the production strategy the final skin was reduced by an average of 60% and production increased by 35%. The completion optimization methodology has proved to be a versatile means of optimizing production in a number of different fields with wells completed in a number of thin highly permeable sands, producing intermediate crude and water.