bluuebunny/crossref_metadata_2025 huggingface dataset:
Restored Productivity Using Dynamic Underbalance
Authors: Gasmi Khaled , Alarcon Bianca , Guerrero Monica , Daoud Mohamed
Published: May 2015

Perforations-reduced connectivity to the producing formation is an ongoing industry challenge. Whether it is caused by high debris or formation compaction, this reduction can be as high as 90%. Several methods were developed to overcome the reduction. Methods such as dynamic underbalance and acidizing bypass damage by using propellants or employing new process such as hydraulic fracturing.

Dynamic underbalance is an effective method to stimulate productivity when it is accurately applied using the right conditions at the initial perforation event. Some wells, however, face reduced productivity because of plugging in the existing perforations.

The case presented in this study examines the application of dynamic underbalance in a well that was treated by generating a surge at the level of the perforations, without resorting to elaborate and costly operations of re-perforating the zone, acidizing or using propellants. The technique was applied in a single wireline run which led to restored connectivity and yielded quadruple the rate of productivity.

This paper emphasizes the need for pre-job modelling to avoid unnecessary operations, presents the associated sensitivity analysis, the deployment methodology and the sequence of operations, as well as the operational advantages over other cleanup methods. Additionally, it assesses the conditions that make a well a good candidate for dynamic underbalance while reducing complex logistics and mitigating the risks of failure. Finally, it presents the results of the operation and increased productivity.
Development and Field Application of an Innovative, Minimally Damaging, Low-ECD Invert Emulsion Fluid for Enhanced Drilling and Completion of HP/HT Wells
Authors: McMillan D. Nelson , Lunde Odd Halvard , Mikalsen Renate , Mæland Yngve , Wroblewski Tomasz , Vatne Åsgeir , Dillner Birgitte
Published: May 2015

This paper describes the first field application of a high-pressure/high-temperature (HP/HT) organophilic clay-free invert emulsion fluid (OCF IEF) weighted with small-particle-sized (SPS) barite, qualification of which was achieved through extensive laboratory investigations (described elsewhere). The paper describes detailed observations of the fluid performance during first use (i.e., “critical first well application”) on a Statoil-operated HP/HT field in the North Sea.

In the well selected for first application, finger-printing was performed so that behaviors of the 1.96-specfic gravity (sg) invert emulsion fluid (IEF) could be examined and recorded before entering the open hole. When in the open hole, observational tests were continued throughout the well. Before and after trips, fluid behavior and properties were monitored and recorded. Additionally, extensive fluid testing was conducted on the rig (rheology, HP/HT fluid loss, particle plugging test [PPT] static sag, and viscometer sag shoe test [VSST]). Before running stand-alone screens (SAS), screen flow-through tests were performed.

Extensive tests showed acceptable fluid performance within stringent, defined criteria at all times. When re-initiating circulation on several consecutive connections, pump ramp-up time was gradually reduced. No pressures above drilling equivalent circulating density (ECD) were observed at any time. While drilling, the ECD values were maintained well within the required values. No barite sag was observed on any occasion, even after 90 hours static or during a slow circulation rate test performed to simulate conditions likely to induce dynamic sag. Fluid loss control (PPT) was maintained within specifications through the addition of ground marble. A decrease of approximately 60% in fluid treatments compared to a conventional HP/HT IEF resulted in a reduction in chemical and logistical costs and manual handling. The well was drilled well ahead of plan, resulting in saved rig time. No issues were observed when running screens to total depth (TD) with the IEF. The well was easily brought on production after ∼30 days, with the IEF being produced back to surface, consistent with expectations from the qualification laboratory testing undertaken at Statoil's laboratory facilities. Highly acceptable production rates were achieved, indicating minimal productivity impairment.

The efficient drilling of the well, along with being able to complete the well in the same IEF and not displace to brine, as was previously performed, resulted in substantial cost savings compared to other qualified solutions. This successful first application demonstrated that the well could be drilled and completed in the same fluid with an enhanced drilling performance and highly acceptable productivity outcome.
Integrated Approach to Sand Management in Matured Field Operations
Authors: Ruslan M. , Lee P. Y.
Published: May 2015

The integrated approach to sand management is crucial to address the sanding risk in the producers and injectors in the North Sea mature field. The concepts incorporates the LEAN approach and developed with major focus on the rehabilitation of mature fields where each barrel of oil counts and uncertainty, both technical and economical, are becoming more challenging at industry level. High decline in productivity and increased operational challenges are common issues for mature fields.

The sand management is divided into 4 major live phases which are sand prediction, sand prevention, sand production and evaluation/feedback. Each stage is mapped and associated with field redevelopment plan, project management control level, the time cycle (short: operation efficiency, medium: production optimization and long: reservoir management), digital oilfield, roles and responsibilities, enabling technologies and fine-tuned workflows.

History case including the utilization of dynamic multiphase flow simulator to fully understand the water hammer sanding behavior and the remedial job enabling technologies will be discussed briefly to demonstrate the utilization of the integrated sand management approach.

The paper will also highlight the key challenges to ensure that the sand management is a continuous improvement effort that is suitable for high level planning and yet practical for day to day operation.

The sand management has been developed based on multidisciplinary approach, lessons learnt and best practices acquired in mature field rehabilitation projects with major consideration to maximize the recoverable reserves and optimize the matured asset added value creation.
Swellable Packer Fluids Designed for Zonal Isolation in Openhole Completions
Authors: Offenbacher Matt , Gadiyar Bala , Messler Dave , Krishnamoorthy Suba-Rao , Abasher Doha
Published: May 2015

A weighted, all-oil fluid system was developed to activate oil-swell packers and maintain compatibility with water-based filtercakes. This fluid system has enabled the successful installation of multiple openhole gravel pack completions to date.

Traditionally, base oils, such as diesel, serve as activating fluids. The low density of the base oil risks compromising well control and/or borehole stability. There are products available to viscosify the base oil and suspend weight material for some applications, but jobs most require special shearing equipment operating at temperatures above safe limits for base oil. Other products are required at significant concentrations that risk adverse reactions with the water-based filtercake and filtrate. Invert emulsion systems offer greater density and viscosity, but they are incompatible with the water-based filtercakes, risking formation damage.

This new fluid system utilizes a new viscosifying agent that easily mixes using rig equipment along with an acid-soluble, treated weight material to maintain a dispersion in oil. All of the products are micronized to reduce any risk of plugging downhole completion equipment. The all-oil system is spotted in the open hole, allowing the swell packers to expand. The system may either remain in the wellbore to flow back with production or circulate out of the wellbore prior to gravel packing. Flexibility in additive concentrations aids to effectively displacing the fluid in and out of the well.

This paper discusses the development process of this all-oil system in the laboratory and the challenges overcome to deliver a rig-practical solution. A review of field planning and execution is included for the initial wells employing the system.
Bursting the Skin Bubble – Decoupling Formation Damage from Skin in Complex Well Geometries
Authors: Byrne Michael , McPhee Colin , Lemanczyk Rick
Published: May 2015

The dimensionless parameter “skin” is commonly used to describe actual well performance with reference to an ideal case, and a number of analytical correlations have been derived over the years to account for the effect on well productivity caused by well geometry, completion design, formation damage and production rate. In a previous publication (Byrne and McPhee, 2012) we outlined the case for reducing the industry's reliance on analytical skin factors for well performance evaluation, particularly since the various “components” of skin, or “pseudo skins,” are often lumped together, and their interaction and interrelationship are often confused.

The concept of well design without recourse to a “total” or lumped skin parameter merits further description. For example, whilst hydraulic fractures may present an opportunity for significant enhancement in well performance, the fact remains that the fractured well itself, while an improvement on the unfractured case, may still not be producing at an optimum rate, especially if there is damage in the formation, at the fracture face or in the proppant pack. An overall total “negative skin,” which arises naturally when characterising the fractured well productivity with reference to an ideal vertical, unfractured well, can actually mask the true well potential. There is a tendency to believe that performance has been optimised but this is simply not the case.

If the geometry of the wellbore, including the completion and induced fractures, are relatively well understood and can be described then the well productivity can be modelled based on the system architecture without the need to compare it to some hypothetical simpler geometry. The quantity and location of formation damage can then be imposed on the model to determine the impact of damage in the fracture, at the fracture face and deeper within the formation.

This paper will illustrate how an indiscriminate use of skin factors can lead to sub-optimal well design and resulting performance prediction, and how this can be improved by representing the real system geometry as rigorously as possible. Decoupling formation damage from its association with other pseudo skins enables a proper description of the impact of damage and its contribution to well performance.
The Effect of pH on Silicate Scaling
Authors: Sazali R. A. , Sorbie K. S. , Boak L. S.
Published: May 2015

Silicate scaling during high pH Alkaline Surfactant Polymer (ASP) flooding is known to adversely affect oil production. The silicate scale occurs as a result of the dissolution of silicates under high pH conditions and where the fluids subsequently flow into a region of lower pH where they then precipitate. The precipitation of magnesium silicate strongly depends on solution pH and temperature and is affected by the kinetics of the silicate scaling reaction.

In this paper, the effect of pH on the stoichiometry and morphology of silicate scale is studied. A range of spectroscopic techniques, including Environmental Scanning Electron Microscope/ Energy Dispersive X-Ray Spectroscopy (ESEM/EDX), Fourier Transform Infrared (FTIR) and X-Ray Powder Diffraction (XRD) are applied in order to analyse the precipitated silicate scales in the laboratory. These spectroscopic techniques, when used along with reference sample spectra, yield a number of interpretive clues as to the nature of the silicate precipitates which are formed. The further analysis of the solution and precipitate by Inductively Coupled Plasma-Optical Emission Spectroscopy (ICP-OES) and ESEM/EDX also gave complementary information which was consistent with the results obtained from the other spectral methods above.

The approach used in this work has enabled us to establish the composition and morphology of the silicate scales formed under different pH condition. There is relationship between the pH conditions and the compounds appearing in the precipitate. Results obtained can be used to help determine the most appropriate type of scale inhibitor for silicate scale mitigation in future.
Understanding Perforation Geometry Influence on Flow Performance Using CFD
Authors: Allison Simon , Löhken Jörn , Nelis Liam Mc , Djayapertapa Lesmana , Byrne Michael , Watson Ken , Clarke Alistair
Published: May 2015

Perforations are required to establish effective hydraulic communication between the wellbore and the surrounding formation. An often considered key attribute is to achieve maximum penetration, providing an effective flow path by extending through the near-wellbore damaged region, penetrating undamaged reservoir beyond.

The challenge is always to design the perforation system to maximise flow efficiency. In the majority of instances deeper penetration is a key design parameter, but penetration is affected not only by the shaped charge, but also critically by rock strength and stress effects. Therefore, perhaps of greater importance are perforations that are both clean and less damaged, providing a more effective connection to the reservoir, whilst maintaining maximum penetration.

Much has been done to enhance perforation efficiency through the development of dynamic underbalance systems and, where appropriate, the application of reactive charge technology. However, little has been done to explore possible benefits resulting from significant changes in perforation geometry, beyond conventional premium system design.

This paper provides a detailed insight into a comprehensive research and development study, following the conclusions obtained for a new convergent perforation system. The system is optimised through harnessed shock-wave energy, achieved by focusing charge groups at a fixed point within the reservoir.

A rigorous section IV test programme was conducted to evaluate the potential flow performance enhancement for such a perforation system. Lab results highlighted a >15% increase in the tested productivity ratio, compared directly to standard system shots, executed under identical conditions.

API-19b Section IV test data validation was carried out using Computation Fluid Dynamics (CFD). A key objective was to match the lab flow performance data, replicating boundary conditions and perforation geometry within each model. CFD modelling enabled further detailed assessment of key relevant parameters influencing improved flow performance, i.e. crushed zone damage and improved channel geometry effects.

Furthermore, CFD was used effectively to model a series of short radial well models, using each matched perforation geometry, comparing the convergent perforation system against the standard HSD system. These models provided further evaluation of key performance influencing factors such as shot arrangement and phasing effects.

In conclusion, the study has shown, through various levels of verification, adopting a convergent perforation approach to gun system design, can enhance perforation flow efficiency through geometry improvement. CFD modelling also showing, within a radial wellbore arrangement, such a system is capable of improving flow performance by as much as 50%.
Graded Proppant Injection into Coal Seam Gas and Shale Gas Reservoirs for Well Stimulation
Authors: Keshavarz Alireza , Badalyan Alexander , Carageorgos Themis , Bedrikovetsky Pavel , Johnson Ray
Published: May 2015

Low productivity indices are observed in many moderate-to low-permeability coal bed methane (CBM) and shale gas (SG) reservoirs due to low aperture and poor connectivity of natural cleats.

A method is proposed for injection of graded proppant particles into a cleat system below the fracturing pressure to keep coal cleats and shale fractures open during water-gas production. Graded proppant injection in CBM and SG reservoirs can: stimulate a stress sensitive cleat system below the fracturing pressure; enhance fracturing treatment by invading cleats, lowering fluid leak-off, and maintaining aperture during production; and provide a periodic or remedial treatment to counter effective stress on the cleats improving production by maintaining cleat aperture.

Laboratory tests on bituminous coal core flooding with water under increasing pore pressure with graded proppant injection at the maximum pore pressure (minimum effective stress) have been carried out at different ionic strengths and high pH of the injected water. Proppant particles penetrate deeper into coal matrix at low ionic strength of injected water corresponding to electrostatic particle-particle and particle-coal repulsion. No particle agglomeration and formation of particle-formed cake at the entrance of coal cleats are observed at these conditions. Coal permeability increases by about 2.2 times as the result of a single-sized small particle injection. Followed injection of larger particles leads to a greater enhancement of coal core permeability. An overall increase of coal core permeability after graded proppant injection is about 2.7 times.

The proposed method can significantly increase very low productivity index in stress sensitive coals and shales without hydraulic fracturing. It can be also used as a non-damaging leak-off additive during hydraulic fracturing stimulation treatments and to aid long-term conductivity.
A Novel Method for Optimal Perforation Design
Authors: Pasztor Adam , Kosztin Bela
Published: May 2015

In case of hydrocarbon production optimization it is essential to know the relationship between the inflow rate and the performance of a perforated production well. It describes the flow rate at the bottom of the well in function of the applied drawdown pressure. The process is strongly influenced by the perforation parameters, formation characteristics and the properties of produced reservoir fluids. The correct calculation gives optimum perforation design and optimized fluid production.

In a cased and perforated well, the reservoir fluids flow through the perforation channels before entering into the well. Thus the parameters of the perforations like penetration depth, phase angle, length of perforated interval, entry hole diameter, average radius of perforation channels and the radius of the crushed zone, etc. have significant impact on the relationship between the flow rate and the well performance. The very first examinations on this phenomenon dates back to the mid 70's. Several equations have been developed to describe the pressure drop through the perforation. However, numerous assumptions have been applied in the derivations of these equations, which have resulted significant loss in accuracy. A new calculating method has been derived and presented in this paper by applying the most accepted methods, i.e. the equation of McLeod and the one of Tariq and Karakas.

The new complex method takes all of the perforation parameters and their effects into account to provide more accurate results. The effect of different perforation parameters on the productivity of oil and gas producing wells are also demonstrated.

As this method takes all the effects of perforation parameters into consideration, different perforation designs can easily be compared and optimized. The great advantage of this method is that it points out the difference between effects regarding the inflow performance of oil and gas wells.
Molecular Weight Effects in Polymeric Scale Inhibitor Precipitation Squeeze Treatments
Authors: Farooqui N. M. , Sorbie K. S. , Boak L. S.
Published: May 2015

The most common scale inhibitors (SI) in the oil industry are polymeric and phosphonate species which are widely used to prevent calcium carbonate and barium sulphate scale formation, and these SIs may be applied in the field in downhole “squeeze” treatments. This paper focuses on the underlying mechanisms associated with polymeric precipitation squeeze treatments, where the polymer is precipitated in situ to enhance its retention in the formation and thus extend squeeze lifetime. Three polymeric SIs of similar structure are studied in this work, PPCA, SPPCA and PFC (full names in paper). Inhibition efficiency (IE) results are presented and analysed in terms of the molecular weight distributions (MWD) of the these polymers. IE and MWD results are shown for each for these polymers “as supplied” (the stock solution) and also for the “precipitated” and “supernatant” fractions, as would occur in a precipitation squeeze treatment. For PPCA, this precipitate has been shown to be a calcium complex of the polymer with stoichiometry, PPCA-Can (n ≈ 30). It is shown that the precipitated forms of PPCA and SPPCA are more efficient at inhibiting barite than either the stock or the supernatant due to the fact that they preferentially contain the larger molecular weight species, which increased the IE. However, the corresponding inhibition efficiency results for the PFC copolymer are rather different to those for SPPCA and PPCA and this is described in the paper.

Further studies of the solubility of the PPCA-Can complex in successive samples of fresh brine suggest a “stripping model” for the dissolution/solubility of this complex, in which the lower molecular weight (MW) species are preferentially dissolved into supernatant brine until some equilibrium is reached. This, in turn, results in the original precipitate being enriched in higher MW species which are less soluble than the lower MW species. This model of dissolution is very different from a “solubility product” model as would describe a sparingly soluble mineral salt. This should now be taken into account in the modeling of polymeric SI precipitation squeeze processes, and it also has implications for the laboratory testing of polymeric SIs for application in precipitation squeeze treatments.
An Advanced Proppant Based Fracture Stimulation Treatment on an Extended Reach Well in the Southern North Sea Utilising a New Purpose Built Vessel: a Case Study
Authors: Souza L. , Oliveira E. , Angheloiu I. , Barry J. Du , Leigh H. , Austin S. , Shaoul J. , Spitzer W.
Published: May 2015

An extended-reach, S-shaped appraisal/development well drilled from a platform to prove up and drain a field extension in a Rotliegendes sandstone reservoir has been hydraulically fractured with a proppant-based stimulation treatment. The hydraulic fracture was a means to optimise the production rate and involved an injectivity test followed by a main treatment.

The hydraulic fracture was performed utilising a stimulation vessel constructed in 2013 that is equipped to perform large-scale acid and proppant hydraulic fracturing and acid matrix stimulation treatments. This treatment was the first massive proppant hydraulic fracturing operation performed by the vessel. Prior to this operation, the vessel had been used to perform numerous acid-based stimulation operations.

A total of 365.3 metric tonnes (730,536 lb) of resin-coated intermediate strength proppant was placed in the fracture, which is thought to be the largest single fracture treatment ever pumped in this particular national sector of the southern North Sea. A tip-screenout design was successfully used to achieve a high average proppant concentration of 23 kg per square metre (4.7 lb/ft2), which equates to an average propped width of 1.3 cm (0.51 in). The large width was needed to achieve sufficient fracture conductivity for the expected reservoir permeability and to minimize convergent flow pressure drop in the fracture, due to the short perforated interval that was used. A very short perforated interval was used to minimize the risk of near-wellbore problems, due to the well deviation of 40 degrees in the payzone. This approach was successful, as the treatment was pumped as per program with no vessel NPT and no HSE incidents.

Lessons learned included optimisation of perforating operations, methods to better optimise initiation of proppant flow to the blender, rationalising data sources, and effective use of equipment redundancy to ensure zero NPT.
New Alternatives in Conformance Control: Nanosilica and Liquid Polymer Aided Silicate Technology
Authors: Lakatos I. J. , Lakatos-Szabo J. , Szentes G. , Vago A. , Karaffa Zs. , Bodi T.
Published: May 2015

The main objective of the laboratory and field studies was to develop an efficient and flexible reservoir conformance control (RCC) technology through improvement of the standard silicate method with joint application of "liquid” polymer and nanoparticle (silica) suspension. Similarly, the important idea was to simplify the surface facilities and reduce cost of chemicals, treatment time, and human force. The laboratory studies focused on laser particle sizing, dissolution kinetics, colloid chemical, rheological, gelation kinetics and setting time, and flow properties of polymer and nanosilica containing silicate gel methods in porous media (sandstone). Based on the experimental findings, it was found that “liquid” polymers and “liquid” nanosilica readily and rapidly dissolve and mix in water, and the solutions are free of microgels and the mechanical entrapment was minimal even in low permeable sandstone cores. In addition, they decreased significantly the surface tension and interfacial tension.

It was proved that such “liquid” additives provide unprecedented flexibility to the technology and the enhanced methods may be attained with labor and expenditure effective way. The main effect of polymer was to stabilize the silicate gel against syneresis (spontaneous fracturing) and formed a secondary network in gel and that fact provided more thermal stability of gel. The nanosilica beneficially influenced the gelation kinetics of polymer containing silicate solutions. The main effect could be traced back to advanced nucleation of gel formation. Additional positive effect of nanoparticles is that its presence in the reaction mixture makes more flexible the pH control in both the bulk phase and in porous media. The extra beneficial properties of “liquid” polymers and nanomaterials in all oilfield chemical applications may significantly contribute to improvement of standard technologies; meanwhile the surface facilities can be simplified, or completely eliminated (e.g. the “liquid” polymer and nanosilica can be directly injected to basics sodium silicate solution at wellhead).

Earlier, the “liquid” polymer was successfully applied in water shutoff in Oman. Recently, a new field programs is running in Hungary using silicate/polymer solution with nanoparticle (silica) fillers. The paper details the “from laboratory to field” activities, and demonstrates the superiority of the novel concept. The successful field pilots, the join application “liquid” polymers, and nanosilica may open new vistas in reservoir conformance control.
Indentaion Hardness for Improved Proppant Embedment Prediction in Shale Formations
Authors: Mueller Martin , Amro Mohammed
Published: May 2015

The aim of hydraulic fracturing is the generation and maintenance of highly permeable pathways. To achieve this, a high hydraulic pressure is applied to overcome the breakdown pressure in developed formations. To avoid the closure of the generated fractures due to the acting in-situ stress in the subsurface, proppantsareused. The hydraulic conductivity (Cf) of such a fracture is defined as the permeability of the proppant pack (kpr) times the fracture width (wf). However, this value cannot be considered a constant. The increasing effective pressure leads to an increased stress on the proppants, thus increasing their embedment into the formation surface. Such a situation becomes particularly critical in weak formations and in formations where the interaction between the frac fluid and the formation can lead to a change in the mechanical properties in the fracture face. This paper will present an approach to model the embedment of various kinds of proppant packs with respect to the proppant size distribution and the proppant density. This approach uses the indentation hardness of the surface formation to calculate the embedment. The advantage of this parameter, which can be measured by applying the hardness test according to Brinell, is that it describes the mechanical properties of the surface of the formation. This area, which is highly influenced by the treatment fluid, can show great differences in the mechanical behavior compared to the untreated area. This can lead to an under- or overestimation of the embedment, since the mechanical parameters normally used for calculation are measured on core samples representing the mechanical behaviour of the untreated rock mass. The consideration of the indentation hardness can lead to a more accurate embedment prediction, since it describes the behaviour of the first 0.1-2 mm of a surface, in which the embedment alone can lead to a closure of a fracture. The first series of hardness tests according to Brinell, conducted on different shale types, have proven that the fluid composition affects the indentation hardness of the samples, which will of course affect the depth of the embedment. The measurements are the basis for the embedment modelling which will be presented in this article.
Pressure Behavior and Fracture Development During Polymer Injection in a Heavy Oil Saturated Unconsolidated Sand
Authors: Zitha P. L. , Barnhoorn A. , Logister R.
Published: May 2015

Polymer injection into unconsolidated sand-packs saturated with either brine or model medium-heavy oil was investigated using a bore-hole simulator (BHS). The high-pressure vessel of this apparatus enables fluid injection under radial or spherical flow regimes into porous specimens having diameter 40 cm and height up to 60 cm and at typical reservoir axial and radial stresses, i.e. up to 40 and 60 MPa respectively. We found that injectivity into heavy oil saturated sand-pack drops steeply to a minimum and then increases again rapidly before leveling off to a plateau. This behavior is in stark contrast with water or polymer injection into water saturated sand-packs, where constant injectivity is established after a rather short transient increase. The behavior of polymer injection into the oil saturated sand-pack strongly supports the idea of the stimulation of the near-wellbore area even though post-mortem visual observations of the porous sample it did not reveal open hydraulic fractures.
From Computerized Tomography to CFD: Production Flow Prediction in Realistic Perforation Tunnels
Authors: Satti Rajani , Kim Dong , Ji Minsuk , Bale Derek
Published: May 2015

Perforated completions have become a standard process of well completions, where the wellbore is connected to the reservoir by perforating the casing/cement wall and the formation to provide flow paths through which formation fluids can enter the wellbore. This flow path (defined by the perforation tunnel) is usually encompassed by drilling damage, crushed and the native formation zones, which influence the ability of the tunnel to flow hydrocarbons into the wellbore. Most numerical models assume the tunnel to be uniformly cylindrical in shape due to limited information available from downhole conditions as well as complexity involved in modeling detailed geometries. Such an assumption leads to discrepancies between computed and true flow efficiency and productivity of the tunnel.

In this paper, our objective is to develop a novel production flow model combining the capabilities of a perforation flow laboratory, computerized tomography (CT scan) and Computational Fluid Dynamics (CFD). As a first step, the complex geometry of the perforation tunnel (from a typical API RP-19B Section IV experiment) is obtained using a CT-scan. Next, the CT scan images are transformed using image processing software to generate a CAD model. The CAD model is then translated to a CFD model, where the conservation equations of mass, momentum and energy are solved to conduct a full-scale three-dimensional flow simulation around the tunnel. The fluid flow simulations provide details on the fluid velocities, pressures, skin factors and most importantly, the productivity ratio. Additionally, we have developed an analytical model that is aimed towards complementing the CFD model by computing the static/dynamic underbalance effects in conjunction with the tunnel's inflow characteristics.

The computational approach presented in this study is a first step towards leveraging digital rock physics to characterize the efficiency of a perforated completion. The study provides understanding into the steady/transient flow dynamics around realistic perforation tunnel geometries along with providing the framework for a completion engineer to better understand the design and optimization of a perforating job. Subsequently, it provides insight into devising the overall completion strategy for enhanced reservoir productivity.
Long Interval Foamed Diversion Treatment: A Mid-Scale Multizone Diversion Treatment Study
Authors: Parton C. , Singh D. , Khamatnurova T. , Lewis C. , Vo L. K.
Published: May 2015

Effective and uniform placement of treatment fluid across multiple zones can be challenging. This is particularly true during stimulation or remedial treatments for formation sand control, as well as during water shutoff treatments. Such challenges can be greatly enhanced when a long interval sand formation is largely heterogeneous. Good diversion technology is often what dictates treatment success. Current laboratory methods used to study diversion at downhole conditions can leave a large gap between laboratory and actual operational results. A recent midscale laboratory study involving a new complex multizone formation testing system has helped provide a method for closely simulating downhole conditions.

This paper describes a new laboratory testing setup, which allows an effective dynamic study of diversion. The new testing apparatus allows for evaluation of different critical parameters, such as concentration, temperature, and pressure on the diversion mechanism. Results are presented for laboratory case studies of diversion during different scenarios, including formation sand/fines control treatment and water shutoff treatment. The results generated can provide insight to help bridge the gap between a laboratory study and operations encountering multiple zones.
A Method for Determination of Near-wellbore Zone Properties Alteration during Well Drilling, Completion and Cleanup Operations by Combination of Numerical Simulations and Special Experimental Technique
Authors: Mikhailov D. , Ryzhikov N. , Makarova A. , Shako V. , Burukhin A. , Theuveny B.
Published: May 2015

Near-wellbore properties can be modified by invaded components of drilling muds or other technological fluids during drilling, completion, and workover operations. At different penetration depths, mud-component invasion creates multizone structures in the vicinity of the wellbore. These structures include external mudcake (mud solid components deposited at the sandface), internal mudcake (which is formed by mud components invaded into the reservoir formation), and mud-filtrate invaded zones. We suggest a model which is able to reproduce the dynamics of near-wellbore zone properties due to the invasion and removal of mud components. The model includes external mud cake buildup and lift-off processes, dynamics of internal mud cake, invasion of the mud filtrate. A new technique is suggested for estimating empirical parameters of both external and internal mudcakes by combining laboratory mud filtration experiments with core samples and a profile of invaded mud components reconstructed by X-ray microCT, image processing of a cleaved sample, and ultrasonic wave scanning.

Examples of reconstructed profiles of invaded mud components (solid particles and bentonite clay) as well as the procedure of determining internal mudcake parameters are discussed. A sensitivity study of the characteristics of mud invasion and early production stage is carried out to the properties of reservoir, external and internal mud cake and perforation length. The effects of fines migration and wettability alterations on dynamics of early production stage are simulated. It is shown that modification of properties of near-wellbore zone can significantly increase the final skin-factor and even kill the productivity of some formation layers that is especially applicable to the open-hole completion.
Investigation of Formation Damage By Deep Eutectic Solvents As A New EOR Agents
Authors: Mohsenzadeh A. , Al-Wahaibi Y. , Al-Hajri R. , Jibril B. , Joshi S. , Pracejus B.
Published: May 2015

Chemical injection into oil reservoirs is considered as an effective enhanced oil recovery (EOR) method. Although some of the chemicals improve oil recovery, they may have side effects on reservoirs such as formation damage due to fluids incompatibility or chemical interactions with reservoir rocks and fluids. Since our previous work indicated promising results from Deep Eutectic Solvents (DESs; DES1 - choline chloride:glycerol = 1:2 and DES2 - choline chloride:urea = 1:2) on enhanced heavy oil recovery, we now examine the possible effects of these DESs on sandstone formation damage.

Core flooding tests were performed at reservoir pressure and different temperatures to measure possible permeability changes by DESs injection. To understand the mechanisms of formation damage, different measurements were performed: Critical injection rate beyond which fines migration will take place, water shock effects on formation damage, dry core weight measurements before and after each core flooding tests, scanning electron microscopy (SEM), X-ray diffraction (XRD), and computed tomography (CT) scanning studies of fresh and treated core samples.

Permeability measurements by core flooding tests showed that the water shock phenomenon caused severe damage (65% reduction in absolute permeability) when distilled water was injected after brine flooding. Both DESs showed positive effect on reducing the water shock damages at different temperatures, where DES2 was much more effective when compared with DES1. Core weight measurements confirmed that whenever permeability damages were higher, the amount of core weight increase was also high. Moreover, results of SEM and quantitative XRD showed that precipitation and deposition inside pores are the main sources of formation damage. In addition, CT-scanning images provided good comparisons between fresh and damaged cores. We observed that using DESs showed that despite the DES's solutions role in preventing severe water shock damage and stabilizing the clays, there was still some formation damage caused by re-crystallization and precipitation processes reducing the permeability of the core samples.
Nearly Perfect Proppant Transport by Particle Fracturing Fluids Yields Exciting Opportunities in Well Completion Applications
Authors: Zhou Jia , Carman Paul , Sun Hong , Wheeler Richard , Brannon Harold , Gupta D. V.
Published: May 2015

Reservoir completion techniques, such as hydraulic fracturing for low permeability wells and frac pack for unconsolidated formation treatments, are normally applied to increase well productivity. The production of treated wells can be greatly enhanced by increased propped fracture area and proppant pack conductivity, both of which are highly dependent on proppant distribution in the fracture. Stimulation fluids with high viscosity are traditionally employed to open fractures and carry proppant into created fracture area in the formation. Although conventional crosslinked fluids are observed to provide good proppant suspension in laboratory environments, they might not provide the desired proppant transport under downhole conditions. Crosslinked fluids can be difficult to clean up, due to residual gel damage to proppant pack and formation. Post-treatment production analyses with crosslinked gel often indicate that the treatment did not achieve the designed conductive fracture area, which could be attributed to non-ideal proppant placement and/or significantly damaged fracture conductivity.

Perfect proppant suspension and transportation under downhole conditions is the ultimate dream for any fracturing fluid technology as it suggests proppant placement throughout the created fracture area to maximize stimulation efficiency of the treatment. Unlike conventional fracturing fluid technology which uses fluid rheology, polymer chains overlap and inter-chain crosslinking to generate viscosity, as the way to suspend proppant. The new concept involves a novel approach of particle packing mechanism to provide the near perfect proppant suspension in the new fluid, while maintaining minimum formation and proppant pack damage after breaking with frac fluid breakers. As to proppant transport mechanics with conventional fluids, viscosity and velocity above threshold levels can move proppant in a generally horizontal direction until gravity prevails as the velocity decays. However, neither viscosity nor velocity can overcome gravity to effectively move proppant upwardly from the wellbore. The packing mechanics of the soft particle fluids substantially mitigate the effects of gravity until such time as fracture closure confines the proppant.

This paper discusses laboratory results for this unique particle fluid system (1) to enhance proppant carrying capacity, (2) to deliver significantly better proppant vertical distribution of the fracture, (3) and to yield near 100% regained proppant pack conductivity. The system can unlock reservoir potential in areas requiring high propped fracture area and high regained conductivity, such as unconventional liquid-rich and offshore unconsolidated formations.
Study of Filtrate and Mud Cake Characterization in HPHT: Implications for Formation Damage Control
Authors: Salehi Saeed , Ghalambor Ali , Saleh Fatemeh K. , Jabbari Hadi , Hussmann Stefanie
Published: May 2015

Filtration from drilling fluids is a time-dependent and complex process. Mud composition, formation pressure, and temperature and permeability are some of the key factors affecting filtration behavior. Formation damage control and wellbore stability are the critical issues dealing with drilling fluid's filtration. The effects of mud cake build up and filtration with time aids the understanding the physical mechanisms. The increase of drilling in high temperature and pressure zones (HTHP) necessitates studies that can predict filtrate invasion, and particle bridging. Decreasing the near wellbore permeability by forming an ultra-low mud cake can strengthen the wellbore and mitigate further lost circulation problems. Very few studies have investigated filtration and filter cake build up under HPHT situations where effect of different mud particles and bridging solids can be analyzed.

This paper focuses on experimental methods quantifying water based muds used by the industry and investigating effects on particle bridging, filtrate invasion and permeability. To show the particle bridging effect, high temperature and pressure (HTHP) filtration tests were conducted at different time steps on sandstone cores with permeability ranging from 10 mD to more than 1100 md. The study also utilizes analytical models to calculate mud cake permeability for the tests using different mix design. The Scanning Electron Microscope (SEM) analysis conducted on the cores presents an expected trend of particle invasion with depth and time. The results from this study can be applied for designing wellbore strengthening fluids to mitigate wellbore stability and formation damage.
Modeling Pressure-Transient Data for Characterizing the Formation Damage in Water Injection Wells Operating above the Fracturing Pressure
Authors: BinAkresh Saud A. , Rahman N. M.
Published: May 2015

Injection wells are widely used in the petroleum industry to support sustained oil production. Water is injected into the reservoir for filling in the void space left by produced oil and to maintain the reservoir pressure. These injectors are frequently evaluated with fall-off tests to assess their injectivity with time. However, most fall-off tests on these wells are unexpectedly dominated by prolonged storage effects with a long unit-slope line on the log-log plot. As a result, the radial flow regime on the pressure derivative plot gets a little chance to develop within the stipulated test period. A high skin damage factor with an abnormally-high storage coefficient (e.g., 1 to 3 bbl/psi, which is one or two orders of magnitude larger than the typical values in regular wellbores) have to be introduced to the well test models to match the pressure behavior from these wells. This anomalous behavior suggests that the wellbore is connected to additional storage volume due to an induced fracture system around the well, having been intersected by a section of it. Apparently, these fractures close gradually after shutting in the well for a pressure fall-off test, manifesting as a prolonged storage effect in the data. This can be explained with the fact that most of the injectors inject water under fracturing conditions, which induce large fractures around the wellbore over time. The fracture system might play a role in taking the damage further inside the reservoir and complicate subsequent remedial work to restore well's injectivity.

In this paper, we will show and discuss several fall-off tests from water injection wells in giant oil fields in the Middle East. The results of these tests, conducted over the years, are to show how the entire test duration is progressively dominated by larger wellbore storage with increasing fracture volume around the wellbore. A changing wellbore storage model (Spivey and Lee) is useful in illustrating the phenomenon of dual storage effect – one due to the wellbore, followed by the other one due to the fracture volume. The model is also used to identify the damage conditions of two regions – one just around the wellbore and the other is located slightly deeper into the reservoir.