bluuebunny/crossref_metadata_2025_split huggingface dataset:
Formation Loading and Deformation of Expandable Sand Screens
Authors: Jones Colin , Watson Ken , Morgan Quentin 
Published: June 2011

Abstract
The slotted version of Expandable Sand Screens (ESS) is easy to expand into compliant contact with the wellbore. This has numerous advantages in sand retention, completion reliability and the maintenance of high productivity. However, the use of a slotted base pipe design will limit mechanical strength.
A joint industry project was undertaken under the auspices of the Production Engineering Association. PEA 182 studied the effect on the ESS of loading at high stress in rocks of various cohesions and friction angles. The project showed that the ESS could withstand any conceivable combination of drawdown and depletion and stay within its design limits except in rocks with a very low friction angle, where excessive deformation was possible.
To ensure against use of the technology in an unsuitable formation, every proposed application is screened using either an analytical or FEA geomechanical model. The results of the PEA 182 tests were used to test the veracity of the FEA methodology. An excellent fit to the experimental data was achieved, both for unconsolidated sands and weak sandstones.
The FEA model of the ESS formation interaction is very versatile and has been used to study a number of different scenarios, such as the effect of sand/shale layers, non-compliance in washouts, solids production and time dependent effects in shales. The model uses the actual structure of the ESS. The first stage of the simulation is to expand the ESS. This ensures that the proper work hardening is included in the analysis. After expansion the mud overbalance is removed, then drawdown and depletion applied in the proper time scales.
The FEA results have also been compared to caliper data and compares reasonably well given the uncertainties in the stress field and the rock strength.
A New Technique to Control Fines Migration in Poorly Consolidated Sandstones - Laboratory Development and Case Histories
Authors: Christanti Yenny , Ferrara Giovanni , Ritz Travis , Busby Brent , Jeanpert Julie , Abad Carlos , Gadiyar Bala 
Published: June 2011

Abstract
Unconsolidated formations and high permeability reservoirs are susceptible to fines migration. The main contributing factors are high formation fluid velocity, wettability alteration, change in water salinity, and rock failure. Typically, fines migration problem occur in the near-wellbore vicinity due to high drawdown pressures. Depending on the severity, it can result in rapid productivity decline, erosion damage to downhole and/or surface hardware, and surface facility upsets.
A properly designed frac pack frac pack can mitigate the migration of fines if it is indeed a problem. However, as insurance there are some technologies currently used to address fines migration in frac packs. These technologies have some limitation such as only being designed to treat the fracture but not the near-wellbore vicinity, prone to causing long-term damage to proppant pack conductivity, and needing remedial work to cleanup the proppant pack followed by retreatment.
In this paper, we will discuss the development of a new technique that effectively controls the migration of fines both within the formation surrounding the near wellbore as well as fracture area, and which does not affect proppant pack conductivity. We first detail the laboratory testing program followed to develop this technology including synthetic pack fines migration core flow evaluation, compatibility with frac-pack fluids, proppant pack and formation damage. Thereafter, we discuss the field deployment process and compliment with case histories. The laboratory results demonstrate that fines migration in the synthetic pack is drastically reduced with this new technique, that the technique is applicable up to 280°F, and that it can be deployed in commonly used frac-pack fluids. Production results of treated frac-pack wells have met expectation and after a year no fines production has been reported.
Optimizing the Design of Matrix Treatments
Authors: Bulgakova Guzel T. , Kharisov Rinat Ya. , Sharifullin Andrey R. , Pestrikov Aleksey V. 
Published: June 2011

Abstract
The up-to-date requirements suggests that the design of a carbonate rock matrix treatment should be calculated based on the models of key physical and chemical processes by means of a specialized software. In wells with a heterogeneous vertical permeability, the problem of acid distribution across the reservoir zone cannot be addressed correctly without using a numerical simulation. Moreover, numerical simulators help find solutions for the feasibility assessment of acidizing operations by simulating scenarios with different injection volumes and rates, agent staging, and initial economic conditions.
The paper describes the design optimization problem in carbonate reservoir acidizing using viscous diverter fluids. The mathematical model of acidizing process was created in the well scale. This model accounts for the flow of insoluble clay and silica particles in a porous medium and their deposition at the pore throats. Core laboratory tests showed that the treatment pressure is affected by a suffosion process. Numerical simulation allowed calculating acid concentration in the reservoir at different injection stages, as well as pressure; porosity and permeability dynamics; the treating agent distribution and flow in the layered heterogeneous reservoir; the skin factors in target zones; and the effect of the diverter fluids. These calculations help to determine the optimal parameters, which drive the acidizing efficiency. The incremental oil production rate and variance of post-treatment productivity for the heterogeneous reservoir are used as the target parameters for treatment optimization. The developed simulator of the heterogeneous laminated reservoir acidizing was applied for evaluating the real field operations, and the results were found consistent with actual historical data.
Improving Return Permeability Test Data through Representative Drawdown Simulation
Authors: Byrne M. , McPhee C. , Rojas E. 
Published: June 2011

Abstract
A key element in formation damage assessment of drilling and completion fluids is return permeability tests on representative core samples. One of the most important test phases is the simulation of production or injection. In a well, this natural clean-up is crucial to the well performance but it is often disappointingly replicated in laboratory tests. Traditionally, drawdown in the laboratory has been simulated by rate control or pressure control. We demonstrate that neither of these techniques adequately capture the transient nature of pressure drop and fluid flow in the near wellbore area, leading to artifacts that produce unrepresentative and questionable return permeability results.
The proposed method allows both simulation of pressure controlled drawdown and a flow rate limit so that only realistic velocities are simulated. The well drawdown during start-up is determined and is scaled to reflect the likely initial drawdown across the very near wellbore. During the laboratory test, the wellbore pressure is gradually reduced simulating "bean-up" and flow rate monitored. Independently, an overriding maximum potential flow rate for the candidate lithology is determined using core plug end face surface area and assumptions on the surface area of exposed wellbore and likely well rates. This maximum flow rate constraint guarantees that unrealistic production or injection rates are never achieved and thus enhanced clean-up or unrepresentative fines movement are never experienced.
The new laboratory return permeability test protocols has resulted in much more realistic laboratory core test data. These data can therefore be used with more confidence to predict the relative performance of different drilling and completion fluids and the absolute impact of formation damage on well productivity and injectivity. It is recommended that this more credible and rigorous methodology should be considered for all return permeability tests.
Investigation of Depletion Induced Formation Damage Mechanisms in Fractured Reservoirs
Authors: Oluyemi Gbenga Folorunso 
Published: June 2011

Abstract
A great number of the world's most prolific reservoirs are naturally fractured carbonate and clastic rock systems. Optimisation of production from this kind of reservoirs is a great challenge owing to complexities inherent in their characterization. These complexities arise, in part, from the need to characterize the matrix and the fracture sub-systems separately and to continually optimize the characterization process throughout the production phase to accommodate pressure depletion effects on production.
Laboratory experiments were performed on a Clashach core sample with a simulated single fracture to investigate the mechanisms for formation damage induced by pressure depletion and subsequent increase in effective stress in fractured reservoir systems.
The experimental results show that excessive pressure depletion during production resulted in increased effective stress loading on the simulated fractured formation system. The effective stress reached a critical value at which the fracture plates were brought into contact, leading to the crushing of sand grains at these contacts. The grain crushing resulted in grain accumulation in the flow streams which, in turn, led to pore throat and fracture space blockage and increased pressure drop across the fractured core system.
The Role of Forensic Petrophysics in Formation Damage Evaluation
Authors: McPhee C. , Byrne M. , Daniels G. 
Published: June 2011

Abstract
Petrophysical analysis plays a strategic role in the evaluation of well productivity and, ultimately, hydrocarbons in place, but its importance in formation damage assessment and evaluation has often been overlooked or inappropriately applied. Over-reliance on often ambiguous well test data, and a lack of real understanding of the formation's static and dynamic petrophysical properties have combined to produce misleading conclusions on formation damage.
Two field examples are presented to illustrate the benefits of a forensic re-evaluation of log, core and test data in both the recognition and rejection of formation damage in low permeability oil and gas condensate reservoirs where data constraints precluded direct laboratory or field testing to quantify damage potential.
In the first, the results of the initial welltest interpretation proved decisive in the original operator's decision to relinquish the field license. Forensic re-evaluation of core, log and welltest data indicated that the low oil rates on test were more likely to be the consequence of formation damage rather than poor formation permeability, and challenged the negative skin factor in the original interpretation. Recognition of formation damage and the opportunity to drill a new well specifically to mitigate formation damage have persuaded the new operator of hidden potential in a reservoir that had been condemned to be non-viable. Conversely, in the second example, the poor gas productivity on test was initially attributed to formation damage. However, forensic petrophysical analysis, which integrated log, test and SCAL relative permeability data, demonstrated that the true formation permeability was significantly lower than estimated from logs and conventional core tests.
Both examples incorporate dynamic SCAL measurements which are often overlooked in classical static petrophysical interpretations. In these lower permeability reservoirs, relative permeability and stress effects significantly suppress the effective hydrocarbon permeability compared to ambient condition estimates.
The workflows and best practices described in this paper have clearly beneficial applications in reservoirs where poor productivity on test does not necessarily represent formation damage or, conversely, the true formation potential. Integrating permeability modelling results with mineralogical information and dynamic SCAL relative permeability data provides a powerful tool for verifying well and production tests; and ultimately, the assessment of formation damage. This integrated and systematic methodology has demonstrably realised the true potential of what were regarded as uneconomic prospects, or has verified that poor productivity is solely a result of poor permeability – not formation damage.
Acidizing Induced-Damage in Sandstone Injector Wells: Lab Testing and a Case History
Authors: Al-Mohammad A. M. , Al-Khaldi M. H. , Al-Mutairi S. H. , Al-Zahrani A. A. 
Published: June 2011

Abstract
Throughout well lifetime, formation damage can occur during the activities of drilling, completion, injection, or well stimulation treatments. Typically, remedial treatments to restore the well performance involve injection of reactive fluids capable of removing such damage. Therefore, understanding damage mechanism and type is critical for fluid selection and effective treatment design. Without this knowledge, the conducted stimulation treatment could cause a more severe form of formation damage.
This report discusses the improper use of mud acid at (9 wt% HCl/1 wt% HF) in restoring the injectivity of N-510. The subject well was stimulated with two acid stimulation treatments as an attempt to improve the poor results of a previous clean-out job, conducted to remove mud filter cake. These treatments were designed to remove the damage that has been limiting the well injectivity. However, it was found that these acidizing treatments created a new formation damage which resulted in severe decline in the well injectivity.
Integration of chemical analysis techniques of return fluids and core-flood experiments was used to assess the effectiveness of all conducted treatments. This report demonstrates the techniques used to identify the source and type of formation damage mechanism that occurred during each treatment. Based on these studies, it was found that the poor results of clean-out job were due to precipitation of calcium sulfate. This precipitation was a result of the mixing between spent cleanout acid, having a high amount of calcium, and the high-content sulfate water. Most of this precipitation occurred in the well-bore vicinity during the last stages of the well flow-back.
Calcium sulfate precipitation had a negative impact on the performance of the conducted acid stimulation treatments. In the presence of this precipitation, the two successive mud acid stimulation treatments created another form of damage, i.e. in-situ fluoride-based scale. Initially, the fresh injected mud acid dissolved most of the calcium sulfate scale and as a result it contained high amount of dissolved calcium ions. However, upon the spending of injected mud acid in the formation, calcium fluoride precipitated as a result of the increase of solution pH value.
The interactions between different acid systems and the constituent of down-hole environment, resulting in the precipitation of calcium sulfate and calcium fluoride, are discussed. In addition, this report provides recommended modifications to future stimulation treatments, conducted under similar conditions so as to prevent the formation of these scales.
Controlled Use of Downhole Calcium Carbonate Scaling for Sand Control: Laboratory & Field Results, Gullfaks
Authors: Fleming N. , Berge E. , Ridene M. , Østvold T. , Jøsang L. O. , Rohde H. C. 
Published: June 2011

Abstract
Gullfaks has been in production since 1986 and produces approximately 11 500 Sm3/d oil from three Condeep platforms. The average water cut is approximately 75 to 80% and GOR of approximately 200 Sm3/Sm3. It has been estimated that between 50 to 100 tonnes of sand is produced yearly per platform with approximately 60 to 70% of the wells in active production (around 90) are limited by sand production. The typically well completion is cased hole with selective production through perforated liners. Rock mechanics studies have shown that sand will be produced irrespective of well inclination and perforation design.
On Gullfaks, the sand management strategy used has been to produce wells at "maximum" or "acceptable" sand rates. This strategy has led to significant gains in production although there are challenges with this approach that include choke erosion, sand removal from the separators and oil in water quality associated with discharge to sea. In response to this, Statoil have investigated different methods of retaining sand downhole by chemical sand consolidation, of which in situ calcium carbonate precipitation will form the basis for the paper. This technology involves squeezing into the near wellbore predefined concentrations of urea and calcium nitrate along with the enzyme urease. After application, the well is shut in during which the enzyme catalyses the decomposition of urea to bicarbonate that reacts with calcium to form calcium carbonate.
The paper will provide details of the laboratory evaluation and, in particular, focus on the field results from the first ever application of this type. A low risk candidate well was selected that had a short perforated interval (19 m) and produced 88 Sm3/d oil with a water cut of 94 %. Results will be presented of the operation design and planning, logistics examination, thorough risk evaluation, and post-operation results with lessons learned.
Unique Self-Aligning Jetting Tool Provides Better Acid Stimulation and Better Production Results
Authors: Surjaatmadja Jim B. , Al Hamad Abdulla M. , Ables Colt 
Published: June 2011

Abstract
Acid stimulation for damage removal is performed when a well is expected to produce satisfactorily when the skin is approximately equal to one. Blindly flowing acid into the well is the easiest thing to do and is commonly performed when the exposure length of the well is relatively short (commonly done in vertical wells). However, as wellbore lengths become longer, this approach is not preferred because it can create massive enlargements to sections near the top of the formation and complications could occur, ranging from re-entry issues and lack of treatment coverage to wellbore collapse.
Tubing-conveyed acid, mostly by coiled tubing (CT), would be the logical choice for acid placement because it evenly spreads the acid throughout the wellbore. Spotting acid throughout a long wellbore has been widely accepted as a viable solution for cleaning the surface of the wellbore. Using CT, acid washing is another common process that can improve stimulation without much additional expense. Using a jetting tool with many jets, acid can be sprayed onto the wellbore wall, and the active agitation caused by this acid-wash process increases the chemical reactivity of the acid at the desired locations.
This paper discusses the implementation of an improvement to the process that uses specialized jetting mechanisms which position the jets closer to the target. This process also uses higher horsepower to provide higher jet-impact pressure onto the wellbore wall. This improvement provides several benefits, including effectively penetrating natural fractures and opening them while stimulating them. Moreover, at certain locations, larger fractures can also be created, which can result in even better production. Actual results of such stimulations are presented.
Numerical Simulation Model of Geological Storage of Carbon Dioxide in Onshore Gippsland Basin, Victoria
Authors: Bu Ali A. T. , Alali M. , Alzaid M. , Bunch M. , Menacherry S. 
Published: June 2011

Abstract
Carbon dioxide sequestration within the subsurface is an emerging field of research to mitigate the problem of increasing concentrations of atmospheric CO2. The onshore/nearshore Gippsland Basin in the state of Victoria, SE Australia, contains deep saline formations that have been identified as potential targets for CO2 storage. Intensive and careful examinations are to be carried out to evaluate these targets. Numerical simulations presented in this study, which were developed using ECLIPSE software, have been designed to investigate certain parameters that influence CO2 behaviour within the subsurface structures. Analysis of results from these simulations will ultimately aid the evaluation of the Gippsland Basin as a suitable prospect for CO2 storage.
Parameters of interest are the ratio of vertical to horizontal permeability, injection rate and the location/depth of perforation. Each one was varied based on a typical range. A 30-year period of CO2 injection followed by a 70-year monitoring period was used as the timeframe for each simulation run. Results of this study indicate that high values of vertical to horizontal permeability are favourable from a trapping efficiency point-of-view. However, they are not appealing from a containment perspective because they enhance buoyant migration of CO2 towards the top seal resulting in a high possibility that ultimate containment will be lost. With respect to injection rate, altering the injection rate does not have apparent effects on trapping efficiencies, namely storage by dissolution and residual gas saturation trapping. Although high values are preferable for dealing with an increased storage volume of CO2, a critical point has to be emphasized. Simulation results suggest that high reservoir injectivity rates cause CO2 to travel faster under buoyancy towards cap rock. Low injection rate decreases the storage volume of CO2. Therefore, a prudent design of injection rate is critical in order to optimise these counterbalancing factors. Additionally, perforation of the lowest section of the reservoir maximises trapping and containment efficiency as far as the injection rate is not compromised. Further emphasis should be placed on improving the resolution, accuracy and thus, the reliability of the geological model as it will directly impact numerical simulation results.
Modelling the Near Wellbore and Formation Damage - A Comprehensive Review of Current and Future Options
Authors: Byrne M. , Jimenez M. A. , Salimi S. 
Published: June 2011

Abstract
In order to accurately predict and assess the impact of formation damage on well production or injection models of near wellbore are frequently employed. These models can range in detail and accuracy from basic analytical models to comprehensive numerical models. But which is most appropriate for a specific reservoir or well type? This paper presents a review of the principle options available and their potential applications. In addition a vision of potential future developments in modelling is presented.
A constant challenge to the formation damage community is predicting the impact of damage and the value in its reduction or elimination. Thus modelling the impact of damage is usually undertaken in order to answer the question "what does this mean for my well?". Many different model types have been employed over the years. The different approaches, their logic and potential applications in different well and reservoir types are presented together with a brief history of near wellbore modelling. With continuing dramatic advances in computational power and in software, the future of reservoir, near wellbore and well modelling has previously unimagined potential. Some of this potential is also explored and its' applicability discussed.
The paper provides a comprehensive overview of near wellbore and formation damage modelling and should provide a useful first entry in to this subject for novices and will no doubt draw constructive responses from the various near wellbore model advocates.