bluuebunny/crossref_metadata_2025 huggingface dataset:
Hammer Motor Smashes Its Way to Speedy Success in Brazil
Authors: Gee Ryan , Ramirez Tibor , Barton Steve , de Souza Julio Cezar , da Fonseca Carlos Eduardo , Cote Brad , Valmorbida Decio
Published: June 2014

Percussive air hammer tools have been used for many years to increase drilling ROP (rate of penentration) in air drilling applications. Similar developments for mud hammer tools have not been as successful. The incompressible nature of drilling mud makes the percussive action much slower to actuate using the same design methodology, rendering the tool ineffective. Other developments have suffered from reliability issues which have limited their drilling hours, therefore making them economically unfeasible.

A novel percussive mechanically-actuated Hammer Motor, suitable for either mud or air drilling applications, has changed the landscape. This unique hammer assembly is assembled into a standard mud motor, without affecting the bit to bend distance. The percussive action of the tool is designed such that the bit remains in contact with the formation, while the hammering takes place against the top of the drive mandrel, driving the bit into the formation. The percussive impacts serve to greatly increase the effectiveness of the roller cone bit in crushing the rock, thus significantly increasing ROP.

This paper illustrates a case study from Brazil, where the Operator has been using turbine motors or conventional motors to drill vertical wells through hard rock formations. The Hammer Motor displayed significantly higher ROP than the benchmark established by the other motors, while also reducing bit costs. These improvements in drilling performance improve the economics of drilling these hard rock formations, and are also applicable to other drilling applications.
Wormhole Propagation in Tar During Matrix Acidizing of Carbonate Formation
Authors: Al-Mutairi S. H. , Al-Obied M. A. , Al-Yami I. S. , Shebatalhamd A. M. , Al-Shehri D. A.
Published: June 2014

Heavy, viscous oil deposits and tar have low °API gravities and occur as part of several oil formations. Unlike normal oil deposits, heavy oil and tar tend to contain more inorganic impurities and to be more sulfurous and aromatic. And as so, they tend to have different responses to acidizing fluids during matrix acidizing treatments. One fundamentally interesting phenomenon is the wormholing characteristics ofacidizing tar formation. This paper discusses the effect of acid and its wormholing characteristic on tar and on carbonate rock that was saturated with crudes that have varying °API gravities.

Experiments included acid flooding of core plugs that were saturated with different °API gravities. The extreme case included flooding the acid through tarsaturated plugs. The wormholes were characterized by CT Scanning. Differential pressures, number and sizes of wormholes and breakthrough volumes were all measured for each experiment. The tests involved regular hydrochloric acid and emulsified acids.

This study showed that regular and emulsified acids produced comparable wormhole penetration in tar. Tar formations were difficult to exhibit face dissolution even at extremely low injection rates. In general, it was noticed that penetration and, hence, benefit from emulsified acid is reduced when higher °API oil saturated the rock. The wormhole breakthrough volume in a rock saturated with intermediate oil was less than that of a rock saturated with condensate oil. Condensate might have allowed better diffusion of acid droplets to react with the rock.

This work provided a fundamental investigation that can lead to development in producing these challenging prospects. In addition, these results are of special interest when long horizontal injectors or producers are placed within the tar zone of conventional oil reservoirs.
Solving Multiple Carbonate Challenges: TCI Delivers Performance Step-Change Drilling Deep 28-in Hole Section
Authors: Al Saeedi Mohammed J. , Al Fayez Fayez , Sounderrajan Mahesh , Al Mudhaf Mishary N. , Portwood Gary R. , Ghoneim Osama , Maliekkal Harish
Published: June 2014

It is well documented carbonate formations cause a multitude of drilling problems. Because the majority of reservoirs in Kuwait are carbonates, the operator is consistently searching for technology to improve drilling efficiency. To reach the hard Jurassic carbonate reservoir, the operator must drill through a series of demanding Tertiary and Cretaceous formations. The fractured Dammam and Tayarat formations are notorious thief zones and can aggravate drilling problems.

The strategy to get maximum hole size to the deep HPHT Jurassic reservoir starts by constructing a 28" borehole through Dammam to TD in Mutriba. The section is interbedded with anhydrite/shale and has compressive strengths between 4- 30Kpsi. At TD, 24" casing is run to isolate the problematic formations. The hole section is approximately 5000ft long but varies depending on the field. These interbedded formations and thief zones create a major challenge for rollercone bits including, impact damage from hard stringers, high WOB and on-bottom time in excess of 250 hours can reduce average ROP to an unacceptable level. Additionally, heat-induced bearing stress caused by low circulation rate in loss-prone formations adds to the applications complexity.

To solve the challenge, the drilling team produced an optimized 28" TCI rollercone bit with custom insert geometry and updated carbide grades to increase cutting structure longevity. Over the last several years the new-style bit, along with optimized operating parameters has consistently drilled the entire section in one run and set a multitude of new footage and ROP records. The authors will discuss the application challenges and TCI bit development. They will present an in-depth engineering analysis that documents footage increases and several new ROP benchmarks in Kuwait. The improved performance has resulted in an average per application cost savings of 3.5 rig days/$175,000 for the operator.
Modeling of Square Mesh Screens in Slurry Test Conditions for Standalone Screen Applications
Authors: Chanpura R. A. , Mondal S. , Andrews J. S. , Mathisen A. , Ayoub J. A. , Parlar M. , Sharma M. M.
Published: June 2014

There are two types of sand retention tests generally used in the industry to evaluate the performance of sand control screens for standalone screen applications: pre-pack tests and slurry tests. They represent complete hole collapse and gradual rock failure around the wellbore, respectively.

In this paper, we present analytical results as well as Monte Carlo simulations to estimate sand production in slurry type sand retention tests with square mesh screens taking into account the full particle size distribution of the formation sand. We also compare the model results with experimental data and demonstrate that this approach can be used to predict sand production for different sand size distribution/screen size combinations without the need for physical tests. This work augments previously published slurry test models that were limited to wire-wrap screens, and enables comparison of the performance of square mesh screens to wire-wrap screens.

The analytical model along with Monte Carlo simulations provide a direct and reliable way to estimate the amount of sand that will be produced for a given sand size distribution and a given screen size. Since the proposed methods are much more quantitative, they represent a significant improvement over current methods that rely on single design points or rules of thumb for screen selection.
Low Extrusion Pressure Polymer Gel for Water Shutoff in Narrow Aperture Fractures in Tight and Shale Gas and Oil Reservoirs
Authors: Gakhar K. , Lane R. H.
Published: June 2014

Excess water production can lead to premature operating cost escalation or well abandonment in conventional oil and gas reservoirs. This can also happen in tight and source rock production in cases where hydraulic fractures connect the stimulated well to a water source, especially with low hydrocarbon production rates. Polymer gel technology has been successfully used in controlling water influx with no or minimal damage to hydrocarbon production in conventional naturally fractured or hydraulically fractured reservoirs. However, there has been no public description of polymer gels tailored for shutting off water flow from fractures with the very narrow apertures expected in tight and source rock reservoirs.

Established water shutoff polymer gels like those based on hydrolyzed polyacrylamide (HPAM) crosslinked with chromium(III) acetate will exhibit high extrusion pressure while penetrating the expected narrow aperture fractures present in source rock and tight gas reservoirs. This is likely to cause significant limitations to their application in unconventional resources, thus giving rise to this study on development of a polymer gel system that can be used for shutting off water flow from narrow aperture fractures. In addition to improved placement rheology, an improved gel system should ideally be composed of components that are less of an environmental concern than metal ion-crosslinked systems.

This report focuses on developing a low viscosity, environmentally benign polymer gel system based on high molecular weight (HPAM), as the polymer component and a commercial grade polyamine containing polyethyleneimine (PEI) as an organic crosslinker. Gelant and gel samples of different concentration ratios of polymer and crosslinker were prepared, subjected to rheological measurements and classified using a semi-quantitative gel strength coding to find optimum concentration ratios that gave good gels. Results indicate that the HPAM/PEI system can provide a gelant with lower initial viscosity, higher final gel strength and potential greater stability at higher temperatures than current metal ion crosslinked gel systems.
Waterless Cement Slurry Controls Water Production in Southern Mexico Naturally Fractured Oil Wells
Authors: Sourget A. , Milne A. , Diaz. L. , Lian E. , Larios. H. , Flores P. , Macip M.
Published: June 2014

Water control is one of the greatest challenges in Southern Mexico wells, where the reservoirs are generally fractured carbonates. Many of the wells have early water breakthrough as a result of one or more of the following: water coning, near- wellbore flow, high-conductivity channels, high-conductivity layer breakthrough, segregated layering, and inadequate completions.

In cases where it is possible to shut off the producing interval and recomplete the well in a new interval, reticulated polymer gels and/or cement slurries can control water production. However, when the water is produced in a different interval than the oil, the success rate of reducing the water cut is less than 30%.

In these cases, waterless cement slurry squeezes have proven to be an effective solution to unwanted water production. This method has been used to successfully reduce water cut in several fields in South Mexico with a nearly 100% success rate.

A well which was carefully evaluated as a candidate and then treated with a waterless cement slurry resulted in a reduction in water cut from 71% to 5%, while oil production increased from 290 barrels of oil per day (BOPD) to 1054 BOPD. In addition, the deferred production was greatly reduced using this technique—less than four days compared with several weeks using alternative techniques.

Water cement squeezes are a cost-effective way to reduce water production in the producing intervals of naturally fractured reservoirs. This technique has increased oil production while resulting in significant cost savings in terms of both treatment costs and deferred production.
The Influence of Fluid Loss Additives in High-Temperature Reservoirs
Authors: Watson R. B. , Viste P. , Lauritzen J. R.
Published: June 2014

Reservoir drilling and completion fluids are affected by temperature. Fluids that perform well at one temperature range can experience major problems at higher temperature ranges. A series of studies have been conducted over the last four years looking in detail at the effect of reservoir drilling fluid design for high-temperature, high-pressure (HTHP) reservoirs, with significant developments in the understanding of the role of fluid loss additives. The focus of these studies was to reduce and control formation damage, in addition to allowing efficient drilling and effective logging of exploration wells. This paper reviews and explains the findings of these investigations and the significance on past and future reservoir exploration and drilling operations.

The studies were all required to assist in a number of specific drilling campaigns where logging of reservoir pressures was planned or had been performed and was believed to be influenced by formation damage. The investigations were initiated with sufficient time to allow hundreds of formulations to be tested with regards to drilling properties, stability and formation damage.

Very distinctive improvements in HTHP return permeability and filter cake thickness were obtained, which was accompanied by logging success. The most notable controlling factor of return permeability under HTHP conditions was determined to be the fluid loss additive. The selection and quantity of fluid loss additive was so significant that it alone could vary the return permeability by more than 80%.

The findings from these investigations have been put to practical use in a number of exploration wells where pressure measurements have been taken with great success. One notable investigation focused on a formulation used 10 years ago on a reservoir where pressure measurements could not be taken. The reservoir was abandoned until recently due to the apparent lack of pressure. This paper details the problems encountered and the results of the investigation in addition to the techniques used to prevent similar problems occurring again.
New and Effective Filter Cake Removal Optimizes Water Injectivity
Authors: Davidson E. , Mota L. , Mosley N. , Chimara G. , Morrison A. , Archibald I.
Published: June 2014

The Captain Field which lies off the coast of Scotland is a shallow sandstone reservoir (3000 ft) comprising clean, unconsolidated sand with high permeability (up to 5D). The oil is heavy and bottomhole temperature very low (30o C). Throughout the development of this field (14 years) two of the main challenges have been control of unconsolidated sand and maximising production of the oil by water injection to maintain reservoir pressure.

Particular attention has been paid to drilling and completion of the water injection wells. The drill-in fluid used was initially oil based mud but changing to water based drill-in fluid facilitated use of faster completion procedures. Initially, when using a water based drill-in fluid, displacement of the openhole to clear brine was always troublesome. This issue was resolved by the introduction of a new low temperature starch into the drilling operation. Adoption of the new formulation has facilitated a simpler, faster displacement operation and made it easier to test various techniques that are offered for filtercake clean up. Treatments, involving acetic acid released in situ, enzymes, sequestering agents, etc., provided questionable results. However, a breaker system that provides a delayed release of formic acid has recently been introduced and has led to a significant improvement in performance.

New techniques have introduced significant benefits, for example: the improved starch shortened the completion process by at least several hours of rig time,the four most recently completed wells which were all treated with the formic acid system had an average initial Specific Injectivity Index that was about 50% better than the average achieved for the first five wells that were completed with oil based mud.

The paper will present important aspects of the learning process on the Captain Field with particular emphasis on application of the new starch, and drilling/clean-up of the water injection wells.
Delayed Crosslink Polymer Flowing Gel System for Water Shutoff in Conventional and Unconventional Oil and Gas Reservoirs
Authors: Jayakumar Swathika , Lane Robert H.
Published: June 2014

A new polymer based gel system has been developed to address the excessive water production problem in fractured unconventional gas wells. Currently available polymer based water shut-off agents are unsuitable for treating high temperature hydraulically-fractured tight gas and shale reservoirs, where some fractures connect to water rich zones. The new gel developed is a low-concentration, low-viscosity delayed-crosslink polymeric gel system and is a significant improvement over traditional flowing gels used for fracture water shutoff in conventional reservoirs. The gel uses high molecular weight hydrolyzed polyacrylamide (HPAM) at low concentrations with a delayed organic crosslinker that is more environmentally benign, provides much longer gelation time (up to several days at temperatures well above 100 °C) and stronger final gels than comparable polymer loadings with chromium carboxylate crosslinkers. Results indicate that gelant with a few tens of centipoise viscosity can have gelation delayed to 12 hours or longer at temperatures of 100 °C and higher. Gels prepared with 4000 to 7000 ppm of HPAM and Polyethylenimine (PEI) were significantly stronger than those prepared with the Chromium(III) Acetate crosslinker for the same HPAM concentrations. This new gel system allows low-pressure extrusion of gelant into narrow-aperture fractures. The system is especially promising for deeper, hotter formations where rapid pressure buildup or gel instability prevents the use of current flowing gel systems. The gelant can be pumped with low pressures due to low concentration of polymer and delayed gelation to effectively seal problem water zones thereby reducing operational costs and increasing recovery. By impeding water production, the gel system developed here can be used to delay water loading and subsequent premature abandonment (or installation of expensive equipment), thereby extending life and reserves of unconventional gas wells. Potential applications include the Barnett Shale, where 15 percent of wells produce more water than injected during drilling and stimulation, presumably due to hydraulic fracture growth into underlying water zones.
An Investigation of Sand Retention Testing With a View To Developing Better Guidelines for Screen Selection
Authors: Ballard Tracey , Beare Steve
Published: June 2014

Sand screens for specific applications are often selected by reference to the results obtained from laboratory sand retention testing. Some recent publications have highlighted the problems of running some types of sand retention tests (slurry tests) at high flow rates, such that the differences between wire wraps screens and metal mesh screens may be exaggerated. With these in mind and also to address some general concerns of the authors ways to reduce flow rates in laboratory slurry tests to more realistic levels have been investigated. This has created some unforeseen effects which are discussed; video has proved invaluable in understanding these unforeseen effects. In addition, an attempt has been made to better define plugging within sand retention tests by relating the pressure build-up gradient from slurry tests to characteristics of the sand itself. Although the pressure gradient generally correlates to certain sand size and sorting parameters the spread in data suggests another factor is important. The purpose of this work is to try and better define the differences in performance between different screen designs, primarily wire wrap and metal mesh screens, in order to better define their application envelopes in terms of sand quality and hence develop more definitive guidelines for screen selection.
Effect of Coreflood Test Methodology on Appropriate Simulation of Field Treatments
Authors: Graham G. M. , Kidd S. , Stalker R. , Wright R.
Published: June 2014

Coreflood experiments are an integral part of the selection and optimisation of scale inhibitor treatments, providing information on formation damage, inhibitor return profiles and dynamic retention isotherms. Comparative returns are often used to select the chemical for field treatments. However, significant discrepancies can arise between core and field in particular due to test methodology.

Here we describe advances over previous work when we demonstrated that test methodology can have significant consequences for the comparative inhibitor returns, particularly with respect to oversaturation. It was shown that many of the limitations can be overcome through appropriate simulation techniques (see SPE 131131).

Here, we present the results of laboratory core flood tests designed to examine the effect of core flood test methodology on the derived return isotherm. This work clearly identifies certain test artefacts, in particular inhibitor oversaturation, which can impact simulation from core to field, and presents supportive core flood data with respect to the modelled isotherms. Thus the paper directly addresses the procedures involved in core flooding, recommends approaches and test protocols which allow more appropriate product ranking and allow improved simulation from core to field.
Perforated Completion Optimization Using a New, Enhanced and Integrated Perforating Job Design Tool
Authors: Zhan Lang , Doornbosch Fokko , Martin Andy , Harvey Jeremy , Grove Brenden
Published: June 2014

Optimizing the performance of a perforated completion requires reliably estimating two groups of parameters: (a) perforation tunnel geometry, particularly depth of penetration (DoP); (b) the condition of perforation tunnels (fill and crushed zone damage). A recent industry survey showed that existing DoP algorithms, which were all based on conversion of surface concrete results to downhole stressed rock penetrations, have shortcomings. Most of the surveyed perforating design tools substantially overestimate stressed rock DoP. In addition, a vast and growing amount of laboratory and field data is revealing that the post-perforation tunnel damage primarily depends on dynamic rather than static underbalance condition. Yet the industry still lacks a reliable and practical algorithm to estimate post-perforation tunnel damage for dynamic underbalance (DUB) perforating. Furthermore, existing perforating design tools usually do not handle multi-zone completions or variations of formation properties along the wellbore.

This paper describes a perforating job design process and software tool that seamlessly integrates a newly developed DoP model, a simple but robust algorithm to calculate post-perforation tunnel damage for dynamic underbalanced perforating, and a reliable model to reflect 3D fluid flow around the perforations. The new DoP model was constructed exclusively based on rigorous laboratory tests for each individual charge in different rocks under downhole conditions, rather than converted from surface concrete results. The transient pressure properties from a comprehensive wellbore dynamics simulator can be loaded into the planning tool for perforation tunnel damage estimation. The perforation skin algorithm due to DUB was developed through a combination of extensive flow tests, conducted in state-of-the-art facilities, and 3D numerical simulations. The integrated perforating design tool provides zonal productivity estimations for single or multi-zone settings. It also introduces an option to compute perforating parameters (penetration and perforation skin) along the borehole with variable formation properties obtained from well log data. The streamlined design workflow and integrated environment allows users to optimize perforating jobs with minimum efforts. The paper includes two field examples that demonstrate the software applications.
Burst and Collapse Responses of Production Casing in Thermal Applications
Authors: Dall'Acqua D. , Hodder M. , Kaiser T. M.
Published: June 2014

API design equations describing casing burst and collapse limits do not address pipe body response when axial stress in the casing exceeds the material yield strength. However, casing yielding commonly occurs in thermal operations in Western Canada, where SAGD and CSS operating temperatures generally range from 200°C to 350 °C. Cemented production casing is subject to both passive and active loading conditions during operation: thermally-induced strain-based cyclic axial loading occurs in conjunction with net internal or external differential pressure. A sound engineering basis for selecting tubular configurations that considers the combined loading state in this situation and establishes an appropriate design margin does not currently exist.

This paper describes numerical analyses for combined post-yield loading conditions and provides a starting point for burst and collapse design for thermal casing. Burst analysis of axially constrained casing indicates that, contrary to what might be inferred from elastic strength calculations, an initial thermally-induced axial compressive strain does not substantially reduce the burst (rupture) pressure. By contrast, even low net external pressures can lead to ovalization and loss of wellbore access when combined with thermally-induced axial strain if the cement sheath does not offer adequate radial support. Sensitivity studies demonstrate the strong influence of pipe D/t and pressure ratios and pipe material mechanical properties on ovalization response. Analysis results are compared to API burst and collapse predictions, thermal operating experience at Shell Canada’s Peace River project, and available physical testing results for similar loading conditions.
Reaction Rate of Emulsified Acids and Dolomite
Authors: Sayed M. A. , Nasr-El-Din H. A.
Published: June 2014

Acid-in-diesel emulsified acid has been used in the oilfield for many years. Emulsified acid systems are retarded systems that can be used effectively in stimulation of carbonate reservoirs. Emulsified acids have primarily been used in acid fracturing and matrix acidizing. The delayed nature of emulsified acids is useful in generating longer etched fractures or deeper wormholes. To predict the penetration depth of wormholes or the length obtained from an acid fracturing treatment, diffusion coefficient values need to be estimated.

This paper discusses the rheology, and reaction kinetics of emulsified acids formulated using a new emulsifier. The emulsified acid systems were prepared at 15 wt% HCl and 0.7 acid volume fraction. Emulsifier concentration was varied from 0.5 to 2.0 vol%. For all emulsions, viscosity was measured using an HPHT rheometer. Emulsified acid reaction rates, and hence acid diffusivity, were measured using a rotating disk apparatus at a temperature of 230 °F. Disk rotational speeds were varied from 100 to 1,500 rev/min. Samples of the reacted acid, from the reactor, were collected and analyzed using the Inductively Coupled Plasma, to measure calcium and magnesium concentrations.

Rheological measurements indicated that emulsified acid systems behaved as a non-Newtonian shear-thinning fluid, and this behavior can be represented by a power law model. The emulsifier concentration and temperature affect greatly the viscosity of emulsified acids. The new emulsified acid systems achieved low reaction and diffusion rates; as the emulsifier concentration increased, both reaction and diffusion rates decreased. Emulsified acid –dolomite reaction was mass transfer limited at low emulsifier concentration. The behavior was in the middle region between mass transfer limited and surface reaction limited for higher emulsifier concentrations. At high emulsifier concentration, the reaction appears to be surface reaction limited. These results can be used to optimize the design of carbonate acidizing treatments using emulsified acid.
The Impact of Annular Flows on High Rate Completions
Authors: Greene R. , Moen T.
Published: June 2014

This paper discusses a study into the effects of annular flow in standalone screen completions. Conventional stand alone screen designs do not constrain flow to within the basepipe. Flow is able to enter the toe of any joint and travel along the annulus before entering again at the heel section of the joint. The paper discusses the use of computation fluid dynamics (CFD) modelling carried out to illustrate the significance of the annular component on the flow and how this will affect annular solids transport and subsequently the erosion and lifetime performance of conventional screens.

This work is particularly significant in high rate gas completions. The conventional approach in the industry when using stand alone screens in gas wells is to maximize the flow area from annulus to basepipe by utilising the highest possible basepipe perforation density. This paper illustrates the fallacy in using this conventional approach and how this will significantly increase the potential for erosion.

The paper will show that the use of conventional standalone screens, and also conventional inflow control device (ICD) screens will result in a significantly high potential for erosion in the screens. This paper will propose an alternative screen philosophy for standalone screen completions in high rate gas wells, and illustrate how this philosophy will be an improvement on the current approach.
Assessing Formation Damage from Migratory Clays in Moderate Permeability Formations
Authors: Howard Paul R. , Hinkel Jerald J. , Moniaga Nita C.
Published: June 2014

As new reservoirs are developed and formations are exposed to various fluids, clay swelling and fines migration can cause serious damage. Clay stabilizers are generally added to mitigate these problems. However, the performance of formation stabilizers is not always properly assessed in the traditional analyses of formation samples. In general, laboratory testing with formation material is performed to define the best additive and concentration. Incorrect choice of stabilizer additives can result in severe damage from swelling and mobile formation clays. There appears to be no standard method for conducting formation stabilizer evaluations, therefore, it is difficult to make meaningful comparisons. Test methods based on the capillary suction time (CST) test or hot rolling lack any theoretical basis and may not show subtle effects.

A new test protocol incorporates several significant improvements over the traditional core flow methods. It considers important factors such as the critical salt concentration and the critical flow velocity. A key improvement is that the proposed method closely mimics pumping and cleanup operations actually encountered in field operations. The new test method is able to distinguish performance differences based upon both stabilizer chemistry and concentration.

Testing results from a moderately sensitive Berea core yielded a surprising finding: well-known organic stabilizers were only slightly more effective than de-ionized water, whereas inorganic salts were quite effective, even at low concentrations. Further, confirming findings by others, our results showed that the Berea core used in this study required no stabilization at 270°F.
Numerical Simulation of the Acidizing Process and PVBT Extraction Methodology Including Porosity/Permeability and Mineralogy Heterogeneity
Authors: de Oliveira T. J. , Melo A. R. , Oliveira J. A. , Pereira A. Z.
Published: June 2014

This work presents the development of a methodology to numerically represent the acid treatment in a test plug, as well as to reproduce the different existing dissolution patterns and to obtain the corresponding values of pore volumes to breakthrough (PVBT). The numerical simulation is performed in a commercial CFD package that uses finite volume method. The modeling includes the effect of heterogeneous porosity/permeability and the presence of different types of minerals that impact the PVBT value, since they have different reaction rates at usual operation temperatures. Through these considerations, the formation of preferential channels, which are characteristics of the various patterns of wormhole, is captured by the numerical simulation.

The goal of this development is the extraction of the characteristic PVBT curves for any pair formation/acid by numerical simulation. It is possible through the use of measured data during drilling, such as average porosity and range of variation, rock mineralogy, etc., and through the knowledge of reaction rates for each pair formation/acid. Using these data, the simulation is able to extract PVBT curves for different numerical test plugs, making it possible to prepare a statistical analysis that has greater significance than just a few experimental tests.

The results show that PVBT curves obtained numerically are in good agreement with the physical behavior expected when compared to experiments. The variation range of the heterogeneous porosity and the presence of different minerals, which have distinct reactivity with acid, significantly change the behavior of the process for the same operating condition.

Better understanding of acid treatment in carbonates (both limestone and dolomite) is important since the new Brazilian petroleum reservoirs are located below pre-salt layer. These rock formations are commonly subjected to acid stimulation in order to increase reservoir productivity. Therefore, the numerical PVBT curves obtained from this work could be used in simpler models to simulate the acid treatment in a reservoir scale. The use of more accurate curves can help the engineers to improve the design of operation conditions and, thus, increase the production capacity and distribute uniformly the treatment.
Customizing Drill-In Fluid for Peregrino Project in Brazil: Laboratory Development and Field Experience
Authors: Han Liqun , Clinch Duncan , van der Zwaag Claas , Galletti Eduardo , Fornasier Frank , Estevez Fabian , McMillan Nelson , Green Justin , Patey Ian
Published: June 2014

This paper describes the design and qualification process used to select a reservoir drill-in fluid (RDF) for the Peregrino field offshore Brazil, and the successful application of this fluid.

The Peregrino field is located east of Rio de Janeiro in the southwest Campos Basin area. Approximately 2.3 billion barrels of oil are in place in the Peregrino reservoir. The productive sands in this variable reservoir typically exhibit permeabilities between 6 and 15 Darcy, and are unconsolidated with interbedded shales. Peregrino crude oil is heavy (13API) and viscous. The estimated recoverable volume of crude oil is 300 million to 600 million barrels.

The selected fluid, a NaCl brine-weighted water-based mud employing KCl and Glycol additions for shale stabilization, was used to drill the first wells at Peregrino. Penetration rates were high and zero non-productive time occurred. To achieve this drilling performance in the high permeability, unconsolidated, heavy oil reservoir, an extensive fluid selection process was performed to optimize the drill in fluid for maximum well productivity. Key test results reviewed in this paper include: Bridging solids optimization, lubrication, shale inhibition, fluids compatibility, filtercake lift off and backflow performance, breaker fluids and formation damage

The reservoir sections of the wells were successfully drilled, open-hole-completed with sand screens and gravel packed with 100% efficiency.
Prediction of Injection Induced Formation Shear
Authors: Han H. , Khan S. , Ansari S. , Khosravi N.
Published: June 2014

Formation integrity is a critical confinement factor in any injection process such as waste injection, CO2 capture and storage, and thermal/pressure injection in oilfields. Rock can fail in tensile, shear or in combination of complex modes. In situ stresses variation caused by injection may shear the caprock posing continued risk of containment breach. We developed an integrated approach to predict the alteration of in situ stresses and shear failure potential by combining data from sonic logs, image logs, mini-frac test data, formation pressure measurement, and rock mechanical core test data. In this approach, three-dimensional Mechanical Earth Models containing the reservoir, overburden, under-burden and side-burden were constructed. Coupled simulations were then run between dynamic reservoir model and geomechanical model to quantify stresses change induced by injection. The resulted formation shear and surface heave will then be calculated regarding the location and timing of occurrence during the planed injection operations.

The methodology has been applied to several steam injection case studies in Northern Alberta oil sands area, Canada. Our analysis indicated that three years of steam injection would cause up to 2 MPa stresses contrast; formation shear failure was forecasted to occur earlier than formation tensile failure at a same time step; the calculated surface heave due to steam injection was around three 3 cm. The simulation results enabled the optimization of injection scheme and proactive monitoring plans to avoid catastrophic events.
The Application of Nanoparticle Dispersions to Remove Paraffin and Polymer Filter Cake Damage
Authors: Mcelfresh P. , Olguin C. , Ector D.
Published: June 2014

The use of stabilized nanoparticle dispersions (NPDs) containing silica particles between 4-20 nm in diameter have been shown to be effective at removing skin damage associated with paraffin blocks, as well as polymer based treating and stimulation fluids. The arrangement of particles at the three phase interface into structural arrays promotes lifting of the damage from the surface, stimulating the reservoir. Aqueous dispersions of nanoparticles used in conjunction with traditional remedial methods can effectively remove damage near the wellbore to be produced out of the well, instead of dissolution and potential displacement of the damage further into the formation.

Many of the declining oil fields around the world owe a significant portion of their decreased production to formation damage. Usually, this damage is indicative of naturally occurring blocks, like paraffin, or as a result of intervention processes that occur over the lifetime of a well during drilling, stimulation, or intermittent remediation treatments. Eventually, the well can become damaged to the point it is no longer economically viable.

This paper will show lab and field results that indicate aqueous nanoparticle dispersions are a capable, and efficient additive for stimulating a damaged well by removal of skin from the surface of reservoir rock. This effect is due to a unique force called disjoining pressure, which causes particles at the nanometer-scale to force themselves between organic matter and the substrate at the interface of the treating fluid. This force promotes the separation of an organic phase from a rock surface.
Fundamentals of Gravel Pack Performance With Mesh Screens
Authors: Martch Eddy , Hudson Andy , Bode Wouter , Fischer Christine , Constien Vernon
Published: June 2014

The Parque das Conchas project is located in the BC-10 deepwater block in the Campos Basin, approximately 120 km southeast from the city of Vitoria, in water depths of 1,500 to 2,000 meters. Shell is the operator with a 50% equity share, with joint venture partners Petrobras (35%) and ONGC (15%)17. The wells flow via Caisson ESP’s to a host FPSO. Horizontal Open-hole Gravel Pack was the sand control method selected in the low frac margin reservoirs of the Ostra Field. In preparation for completing wells in formations with anticipated sand production, a large laboratory study was conducted evaluating the performance of stand-alone woven mesh screens and gravel packs. The study was performed to select a premium mesh screen which would minimize solids production in the event of incomplete gravel pack and manage fines production that would pass through the seabed located Caisson ESP systems. Additionally, it was important to control solids production to the Floating Production, Storage and Offloading (FPSO) unit as there were no provisions installed to handle large volumes of solids at the surface. The test grid compared the performance of multiple screen sizes with and without gravel packs with three unconsolidated formation particle size distributions which were representative of the size distributions anticipated in the completions. The resulting performance data correlated the amount of solids production, size of produced solids, retained gravel pack permeability and retained screen permeability as functions of the effective size of the formation material, the gravel size and the pore size of the screen. The gravel pack media size and premium screen mesh size were selected based on the results of this testing. Screen QA/QC was determined to be critical in the event a full gravel pack was not achieved and the screens would be expected to provide sand control in a stand-alone mode. An enhanced quality process was developed and implemented to ensure the highest quality of the screens was maintained and materials were traceable during well sand control completions.

The laboratory tests identified combinations of screen and gravel packs which appeared to indicate the best choice for controlling solids production in an acceptable range while maintaining high flow capacity, maximizing production at minimum drawdown pressures. An enhanced QA/QC process for screen manufacturing contributed to the success of the completions. Production history for the first 2 years indicates minimal sand production.
Novel Method To Characterize Formation Damage Caused by Polymers
Authors: Maxey J. , Van Zanten R.
Published: June 2014

Formation damage can occur through several different mechanisms ranging from scaling/precipitates to pore plugging by small particles. Polymer invasion into the reservoir pore spaces during drilling, completion or fracturing can be especially damaging and difficult to remediate. This has been previously reported to result from increases in the extensional viscosity that occurs as the polymer is extruded through the pores of the formation. This increase in extensional viscosity traps the polymer in the pore throat and creates a liquid crystalline type state that does not allow the polymer to relax and exit the pore space or allow remedial treatments such as acidizing to contact to polymer to break it down.

This paper will detail a laboratory investigation combining rheological studies of extensional viscosity of polymeric and viscoelastic surfactant fluids with formation damage testing performed on Berea sandstone cores. Using a laboratory rheometer, the shear rate applied to a sample will be increased exponentially, creating strong flows comparable to those experienced in flow through porous media. The type of polymers will be varied to include simple linear biopolymers (HEC), varying degrees of branched biopolymers (xanthan gum, scleroglucan gum), and hyper-branched synthetic polymers; fluids viscosified with polymers will then be compared with viscoelastic surfactant gels. A direct correlation between the rheological properties of the fluid to the formation damage potential of the fluid will be made. This correlation will allow for screening of fluids that will contact the reservoir through a much simpler rheological methodology as compared to the time consuming and highly variable formation damage tests via core flood experiments.
The Influence of Production Rate, Permeability Variation and Well Spacing on Solution-Gas-Drive Performance
Authors: Heuer G.J. , Clark G.C. , Dew J.N.
Published: June 2014

The effect on well behavior of partial permeability barriers, changes in producing rates and well spacings have been calculated through use of a radial, unsteady-state, two-phase-flow mathematical model. This model allows for variations in permeabilities and porosities with distance from the wellbore. The numerical methods necessary to solve the problem require use of a high-speed digital computer, in this case an IBM 704.

In each instance, pressure and saturation gradients, gas-oil ratios and recoveries around a well producing by solution-gas drive have been calculated as a function of time and distance from the wellbore. Comparisons are made to show the effect of changes in producing rate and of varying permeability near the wellbore and out in the formation on the production and pressure history of the well. The effect of different well spacings on producing rate and ultimate recovery is considered. Although the mathematical description of the reservoir is simplified in comparison to an actual reservoir, the results do give some insight into the difficult problem of spacing and proration in a heterogeneous solution-gas-drive reservoir. Results show that for the cases considered spacing has little effect on ultimate recovery and that permeability barriers removed from the well decrease producing rate for a period of time but have only a small effect on ultimate production.

Introduction

The effect of spacing and producing rate on the production characteristics and ultimate recovery of a well producing by the solution-gas-drive mechanism have been topics of interest to the oil industry for many years and the subject of many hearings before state regulatory bodies. The problem is very complicated because of the difficulty of simulating in the laboratory a reservoir producing by the solution-gas-drive mechanism under anything like normal field conditions. This paper gives the initial results of a study aimed at determining the effect of these factors on production from reservoirs simulated by a mathematical model. Two-phase, unsteady-state equations are used to calculate pressures, saturations, and rates of oil and gas flow as a function of time and distance from the wellbore. The model is radial, and reservoir properties may he varied with distance from the wellbore. A decrease in permeability at a given distance results in a low-permeability ring concentric with the wellbore through which all the fluids from more distant portions of the reservoir must flow.
Petrophysical Properties Evaluation of Tight Gas Sands Using NMR and Conventional Logs
Authors: Hamada G. M.
Published: June 2014

Analysis of heterogeneous sandstone reservoirs is one of the most difficult problems. These reservoirs usually produce from multiple layers with different permeability and complex formation, which is often enhanced by natural fracturing. Therefore, using new well logging techniques like NMR or a combination of NMR and conventional open hole logs, as well as developing new interpretation methodologies are essential for improved reservoir characterization. Nuclear magnetic resonance (NMR) logs differ from conventional neutron, density, sonic and resistivity logs because the NMR measurements provide mainly lithology independent detailed porosity and offer a good evaluation of the hydrocarbon potential. Integration of NMR logs, other open hole logs and SCAL minimizes uncertainties in the determination of formation porosity, permeability and capillary pressure curve.

This paper focuses on determination of three petrophysical parameters of heterogeneous gas sand reservoirs; 1) Determination of DMR porosity, 𝚽DMR, it is deduced from NMR porosity and density porosity, 2) NMR permeability, KBGMR, it is based on the dynamic concept of gas movement and bulk gas volume in the invaded zone and 3) Capillary pressure, it is derived from relaxation time T2 distribution