bluuebunny/crossref_metadata_2025 huggingface dataset:
Formation Loading and Deformation of Expandable Sand Screens
Authors: Jones Colin , Watson Ken , Morgan Quentin
Published: June 2011

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

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

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

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

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

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

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

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

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

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

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.
A Thorough Investigation of Cleanup Efficiency of Hydraulic Fractured Wells Using Response Surface Methodology
Authors: Ghahri P. , Jamiolahmady M. , Sohrabi M
Published: June 2011

Poor cleanup efficiency of injected fracture fluid (FF) has been considered as one of the main factors contributing to the poor performance of many hydraulically fractured wells (HFWs). Limited parametric studies evaluating the efficiency of FF cleanup have not embarked on a much needed extensive investigation of variation of all pertinent parameters.

In this work we present the results of over 130000 simulations of the process, for a HFW model that was constructed using a reservoir simulator. A computer code has been developed, which automatically, read input data, link the injection and production periods and create the output data. The impact of 16 parameters describing the gas and FF effective permeability of matrix and fracture, pressure drawdown, capillary pressure, and porosity have been studied for two injected FF volume values. Different statistical experimental design methods have been used to sample a reasonably wide range of variation of pertinent parameters. Linear and quadratic response surface models have been used to map the gas production loss (GPL), compared to 100% cleanup case.

The results indicate that GPL is mainly controlled by parameters related to FF cleanup inside the fracture particularly fracture permeability. In some cases increased back flow of FF from matrix into fracture increases GPL. As production continues, the impact of matrix permeability and gas exponent of Corey type relative permeability curve in the matrix become more pronounced. The fracture residual gas saturation and matrix gas end points have negligible effect. The relative importance of pertinent parameters is less for lower FF injection volume and especially at higher production periods. These practical findings can be used to make a better decision on the performance of such costly operations, suggested methods for improving the cleanup efficiency of FF and the optimum fracture design practices.
Hydrajet Fracture Stimulation Technique Used To Rejuvenate Three Wells In Mature Offshore Oil Field Congo - Case History
Authors: Rhodes D , Orski K , N'Gouma C , Guittiene P
Published: June 2011

The Tchendo oil field, located 18 miles off the coast of the Republic of Congo has been operated since 1991, by Total E&P Congo in approximately 100 meters of water.

The wells are deviated (more than 60 degree), completed with production casing as large as 9 5/8", and partially to extensively perforated, with poor to unknown cement quality.

The wells are produced by electrical submersible pumps.

One of the three reservoirs, the Sénonien reservoir, is an intercalation of metric carbonate layers with thicker (20 to 30 meters) but poorer quality sandstones. (0.1 to 10 mD). It is shallow (450 mVSS) and depleted (0.37 psi/ft).

Various attempts to enhance productivity were tested since initial production, including selective or extensive perforation, acid treatments on carbonate layers, and one open hole horizontal well.

However, a large part of the original oil in place still remains in the reservoir.

Therefore, it was decided to evaluate the potential of hydraulic fracturing stimulation treatments to rejuvenate the existing wells.

The well characteristics made conventional methods of hydraulic fracturing either cost prohibitive or impossible.

A first test of the hydrajet propped fracturing technique was performed in 2008, followed in 2010 by two other pilot treatments.

This paper details the lessons learned in using this innovative technique to stimulate the three wells and demonstrates limitations of the technique associated with the existing wellbore conditions. This paper will serve as a guide for revitalizing the Tchendo field and possibly other mature oil fields with low to moderate permeability.
Recent Advancements in Hydrajet Perforating and Stimulation Provide Better Penetration and Improved Stimulation
Authors: Surjaatmadja Jim B. , Gijtenbeek Klaas Van
Published: June 2011

The use of hydrajetting for perforation of wells has been commonplace since the 1960s. During those early years, jetting success was consistently demonstrated. While the quality of hydrajetted perforations is admittedly better, they are generally costly to implement. Horsepower requirements and logistics are a few obstacles associated with this process in terms of cost reduction. With the birth of hydrajet-assisted fracturing (HJAF) methods in the last decade; however, these obstacles were immediately overcome when hydrajet perforating became an integral part of the stimulation process. Hence, the system quickly transposed into an effective, time-saving stimulation treatment method. Within a few years, another hydrajet perforating + frac stimulation process was developed, where coiled tubing (CT) was used for hydrajetting only, and afterward the frac stages were all pumped down the annulus of the CT and the casing, with sand plugs used to seal off after the fracture stimulation treatment to allow more stages of the "hydrajet perf + frac" applications up the well in either vertical or horizontal wells. Soon, an increased level of using hydrajet perforating as a stand-alone service also became far more common.

As these hydrajetting processes become increasingly popular, intensive studies are needed to continually improve the performance of the tools and processes. For example, increased proppant volumes combined with an increased number of fracture stages or more perforations to be placed in one trip quickly mandates creation of higher life-expectancy tools. Improving the performance requires improving the hydrajetting-technology knowledge; in addition, well completions often dictate the size limitation or design of the jetting tool itself, which in turn dictates the pumping limits of the job. Lastly, new jetting technologies might have to be created to define the optimal quality of proppant which should be used in oilfield applications.

This paper offers an in-depth study on improving our jetting expectancies and performances by knowing the various behaviors of abrasives or proppants when they are jetted through nozzles and under other conditions. This data will help us in optimizing the jetting process itself. Results of extensive laboratory tests on different types of proppant are presented which provides a much better understanding of the limitation of various proppant types. Knowing these limitations is a key to successfully using hydrajetting for stimulation purposes or maximizing hydrajet effectiveness when perforating or cutting. Examples of easy-to-use computational tools for such purposes are also presented.
Improved Oil Recovery for Fractured Granite Basement Reservoirs: Historical Lessons, Successful Application, and Possibility for Improvement
Authors: Dang Cuong T. , Chen Zhangxin , Nguyen Ngoc T. , Bae Wisup , Phung Thuoc H.
Published: June 2011

Discovery and development of naturally fractured reservoir has increased dramatically during past 15 years because more fractured reservoirs are being developed as production from conventional reservoirs is declining. Many oil reservoirs in the world are naturally fractured, but relatively little research has been done on the use of advanced oil recovery methods. In addition, very little success has been achieved in increasing the oil production from these complex reservoirs. Some laboratory experiments have been done to investigate the use of IOR methods for fractured reservoir; however, the results of these studies hard to interpret and to apply to field scale predictions. Thus, it is urgent and necessary to collect the experiences from previous successful researches to reduce the risk level.

This study addresses methods and recent advances to enhance oil production in fractured granite basement reservoir of White Tiger field. It is the biggest fractured reservoir up to now on the continental shelf of Vietnam. But, the geological characterization of this reservoir is extremely complex with high uncertainty and challenge in production strategies. Therefore, a numerous of studies were conducted to develop the favorable

IOR techniques including advanced emulsion acidizing stimulation, microbial enhanced oil recovery methods, artificial water buffer, directional drilling application, and gel treatment for basement reservoir. These special approaches were achieved many precious successes in increase the recovery factor from 29% to 44.33% and would be significantly extended the life of reservoir. Regarding to the unique characterization of White Tiger field and lack of experiences of producing in fractured basement reservoir, the lessons learned and experiences gained from past 20 historical years are a worthy case study for both current and future development of NFR in the world.
Translation of New Experimental Test Methods for the Evaluation and Design of Shaped Charge Perforators to Field Applications
Authors: Hardesty J. , Bell M. R. , Clark N. G. , Zaleski T. , Bhakta S.
Published: June 2011

Perforation performance evaluation has come under scrutiny in several recent publications. For most shaped charge perforators sold, performance is evaluated in cement targets, from which downhole performance is extrapolated. This method has been shown to generally over-predict downhole performance, with broad implications for perforating systems and shaped charge design, and well completion design.

Advanced test methodologies are an order of magnitude more complex than the simplified cement penetration tests. This paper details a set of experimental shaped charge development programs with specific geometry and/or flow performance requirements and examples of their corresponding field performance. Tests have been performed with full simulation of single shot perforation, and simplified perforating simulations into stressed rock. Results are reported for shale, sandstone, and high permeability sandstone targets. Designs tested include both conventional and reactive shaped charges.

In one example from 2008-2009, CNX completed fourteen wells using both conventional and reactive perforating systems to evaluate any impact on completion performance. Stimulation and production data have been analyzed for 81 stimulation stages. When comparing wells perforated with reactive shaped charges to conventionally perforated offsets, a reduction in breakdown pressure gradient of between 13% and 29% is observed. Subsequent treating pressures are reduced by 6% to 15%. The wells perforated with reactive shaped charges have also exhibited significantly slower productivity decline over the first nine months.

In addition, near-perforation permeability has been mapped using advanced digital imaging techniques. This allows the grain structure and permeability distribution of a perforated rock target to be accurately measured as a function of radial distance away from the perforation wall and longitudinal position along the perforation tunnel. The paper describes important improvements in our understanding of perforation damage distribution, and provides techniques for use in conjunction with API RP 19B Section 2 and 4 tests to design perforating shaped charges and systems.
Development and Testing of a Perforation Plugging Treatment Designed to Limit Reservoir Crossflow
Authors: Sanders Mark W. , Watson Russell B. , Viste Patrick , Wylie Graeme , Radcliffe Paul
Published: June 2011

Permanently isolating one or more producing zones from another is occasionally required as a means of maximising net flow from a producing well. In this case, zonal isolation is required to minimise the crossflow of a high-temperature depleted, perforated, upper sand section from a lower, higher-pressured zone targeted for future production. Any chemical isolation treatment applied to the upper sand perforations must withstand not only the high temperature involved, but also differential pressures in the region of 300 bar (4,351 psi). Following the treatment, flow would then be initiated from the lower sands by removing an isolating sand plug. By effectively plugging a formation, crossflow between the two producing sections of the well would be minimised, the degree of which would be dependent upon the efficiency of any final perforation seal.

The treatment incorporates specially sized and selected particles designed to invade the matrix permeability, a temperature-triggered bonding agent and ingredients which ensure that the treatment reaches the target. The mixture of the bonding agent and the sized particles creates a well defined seal within the perforation tunnel.

Both the development and testing of the perforation plugging treatment incorporated high-temperature, high-pressure permeability plugging tests in combination with innovative coreflood testing techniques. Detailed analysis of the treatment, cores and perforations with electron microscopy and computed tomography (CT) allowed the initial idea to be tailored and perfected for the specifics of the field application.

This paper will discuss the laboratory development of a perforation plugging treatment designed to limit reservoir crossflow under conditions of high-temperature and high-differential pressures.
Engineered Particle-Size Distribution while Drilling Helps Minimize Wellbore Damage in Sandstone Reservoirs
Authors: Mohamed Monir
Published: June 2011

Inducing formation damage in sandstone reservoirs through poor drilling fluids management can impair well productivity. A detailed mud-management plan that addresses fluid design and particle-size monitoring can help minimize formation damage and improve well productivity. This management plan was demonstrated successfully on 29 wells where the operator implemented an engineered oil-based drill-in fluid (DIF) and a particle-size distribution (PSD) analyzer in the field while drilling the reservoir.

The oil-based DIF was formulated with a 70/30 oil/water ratio and then treated with sized calcium-carbonate bridging agent. The PSD analyzer was used continuously while drilling to monitor and maintain optimal PSD values in the DIF. Maintaining controlled ROP was essential while drilling a reservoir section along with the hourly addition of sized calcium carbonate and efficient solid control equipment running all the time while drilling. Overbalance pressures were also minimized to reduce the risk of differential sticking.

To achieve better bridging results, D90, D50, and D10 particle-size distributions were maintained in the programmed range throughout the entire reservoir section. Upon reaching total depth (TD), the bottomhole assembly was changed and the entire section was reamed to TD. A wiper trip was done to casing shoe then tripped back to bottom without pumping to simulate hole conditions that would occur while running screens.

Once the open hole was deemed in good condition, the well was displaced to a solids-free invert mud maintained at the same density as the DIF. This fluid was circulated over a 265-mesh screen prior to running the screens to ensure all fine sand and excess filter cake had been removed.

Testing results indicated minimum skin damage and good stable production rates.
Acid Placement in Acid Jetting Treatments in Long Horizontal Wells
Authors: Sasongko H. , Zhu D. , Hill A. D.
Published: June 2011

In the Middle East, extended reach horizontal wells (on the order of 25,000 feet of horizontal displacement) are commonly acid stimulated by jetting acid out of drill pipe. The acid is jetted onto the face of the openhole wellbore as the drill pipe is withdrawn from the well. The jetting action helps to remove the drilling fluid filter cake and promote the acid to penetrate into the formation and form wormholes to stimulate the well. However, with very long sections of wellbore open to flow, the acid placement and subsequent wormhole distribution and penetration depths are uncertain.

We have modeled this process using a comprehensive model of acid placement and wormhole propagation in a horizontal well. We presume that the acid jetting tool removes the drilling mud filter cake, so that no filter cake exists between the end of the drill pipe and the toe of the well. Correspondingly, we assume that there is an intact, low-permeability filter cake on the borehole wall between the end of the drill pipe and the heel of the well. The drill pipe is modeled as being withdrawn from the well during the acid jetting treatment, as is done in practice.

The acidizing simulator predicts the distribution of acid and the depths of wormholes formed as functions of time and position during the acid jetting treatment. The model shows that the acid jetting process as typically applied in these wells preferentially stimulates the toe region of the horizontal well. Comparisons of the simulation predictions with published data for acid jetting treatments in such wells showed good general agreement. Based on the simulation study, we present recommendations for improved acid jetting treatment procedures to improve the distribution of acid injected into the formation.
Well Productivity Decline due to Fines Migration and Production: (Analytical model for the Regime of strained particles accumulation)
Authors: Bedrikovetsky Pavel , Vaz Alexandre , Machado Fernando , Zeinijahromi Abbas , Borazjani Sara
Published: June 2011

Well index decline has been widely observed for oil, gas and artesian wells producing the reservoir fines. It has often been explained by the lifting, migration and subsequent plugging of pores by fine particles, which have been observed in numerous core flood tests. In this work, the basic equations for the detachment of fine particles, their migration and size exclusion, causing the rock permeability decline, have been derived. The analytical model, developed for the regime of steady state production with gradual accumulation of strained particles, show the linear skin factor growth vs time and vs the amount of produced reservoir fines.
Pre-Crosslinked Pills Provide Efficient and Consistent Fluid Loss Control
Authors: Gibson Jacob D. , Javora Paul H. , Adkins Mike
Published: June 2011

Solids-free completion brine is the ideal fluid to complete wells employing sophisticated downhole tools with limited metal-to-metal clearances, as well as those requiring sand control operations. Unfortunately, clear brines have no inherent control of fluid loss, leading to poor completion performance, increased formation damage and well control issues, all of which contribute to lost production time. More specifically, fluid engineers have reported greater formation damage due to increased brine-formation interaction while reporting losses as high as 100 barrels per hour. Critical evaluation of these factors coupled with the complexity and cost of today's projects, reinforces the need for chemical systems that immediately and effectively control fluid loss with minimal formation invasion.

Cross-linked pills prepared at the rig site gained industry-wide acceptance by reducing fluid loss to just a few barrels per hour. However, deficiencies of rig-prepared pills occur, such as loss of incompletely cross-linked material into the formation, pre-mature cross-linking that inhibits delivery, significant time needed to make a quality pill, and associated HSE issues that limit the manufacturing of pills at the rig. As a result, researches developed second-generation solids-free FLC pills, which feature pre-cross-linked polymer. This second-generation system provides new dimensions in pill technology that further improve the efficiency and consistency of traditional rig-prepared FLC pills.

This paper presents methodology for using this new class of pre-cross-linked solids-free FLC pills as well as data defining their properties and characteristics including significant reduction in rigsite HSE issues and superior quality control conducted at the manufacturing plant. This paper also presents field case histories demonstrating the use and effectiveness of optimized, fully pre-cross-linked FLC pills ready for immediate use at the rig.
Development of Small Field in Malaysia Using Cost-Effective Open Hole Sandface Completion Technologies – A Case Study
Authors: Safiin N. , Ahmad Mahdzan A. A. , Nik Khansani N. Z. , Ghazali N. M. , Zainal Abidin O. , Zeidan A. A. , Elliot C. , Khalid M. Zaidan , Regulacion R. , Domia P. , Lim P. S. , Abdul Rahim M. F. , Jackson P.
Published: June 2011

Many small oilfields in poorly sorted and highly non-uniform unconsolidated formations with high fines content cannot be developed economically using the preferred sand control method, gravel pack. ‘J’ Field in Malaysia is a small oilfield with marginal economics that was developed successfully using stand-alone screen (SAS), a cost-effective open hole (OH) sand control method. Deployment of SAS in ‘J’ Field does not meet the industry-accepted criteria for sand control methods but provided the operator adequate sand control while fulfilling its economic needs. Recent advances in OH sandface completion technologies such as multi-layer mesh screens, inflow control devices (ICDs), and zonal isolation using swellable packers provided improved performance and reliability of recent SAS installations.

This project marks a few firsts in sand control screen technology: World's first installation of multi-layer mesh screenMulti-layer mesh screen is the current state-of-the-art in premium mesh screen technology. It uses several layers of woven metal mesh filters of gradually decreasing micron rating and diffusion-bonded together, which creates a filter that provides better plugging resistance and solids retention capacity.Malaysia's first installation of tube-type ICDICDs are passive flow control devices that are used in OH horizontal (Hz) wells to delay the onset of water breakthrough and minimize its effect by balancing inflow from toe to heel or between high-perm and low-perm zones. ICDs are integrated with sand control screens for use in unconsolidated formations. Swellable packers are used in ICD completions to provide compartmentalization.

This paper highlights the recent success of utilization of these cost-effective OH sandface completion technologies in the development of ‘J’ Field.
Laboratory and Theoretical Investigation of Size Exclusion Suspension Flow in Rocks
Authors: Chalk P. , Gooding N. , Hutten S. , You Z. , Bedrikovetsky P.
Published: June 2011

Particle transport in suspension flow with pore plugging and particle capture is encountered in a wide range of porous media including reservoir rocks. Based on the particle population balance, a micro scale model accounting for particle size exclusion mechanism and triangular shaped pore throat geometry, has been developed. The steady state case, which corresponds to the initial stage of size exclusion deep bed filtration, allows for an analytical solution. The recovered outlet concentration of suspended particles from this solution is then matched with the measurement from well designed challenge coreflood testing which guarantees net particle-grain repulsion for pure straining condition. The comparison shows good agreement between the modelling result and the laboratory measurement, which also results in the evaluation of pore throat size distribution.
Experimental Investigation of Clay Minerals' Effects on the Permeability Reduction in Water Injection Process in the Oil Fields
Authors: Abbasi Saeed , Shahrabadi Abbas , Golghanddashti Hassan
Published: June 2011

Water availability for injection into oil reservoirs is an effective factor for superiority of water injection project. One of the parameters that cause undesirable effects on reservoir rock injectivity is clay minerals. The different structures of clay minerals will result in undesirable effects on rock permeability. Clay minerals enter into the pores and throats by injected water or they are a part of the structure of the reservoir rocks. Clay swelling from the viewpoint of the clay minerals type and structure can reduce the permeability of reservoir rock. In this study after the effects of clay minerals and their performance mechanisms, some of the rock samples were chosen from one of the field in south of Iran that is injecting water in aquifer.

Then it has been tried with XRD examination to specify the clay minerals type, and to estimate the percentage of each type; however permeability reduction was estimated for each one of core samples in core flooding experiments by injecting distilled water and formation water to the sample and creation of clay swelling. Also results comparison could show their performance and effect in the water injection process to estimate permeability reduction.