bluuebunny/crossref_metadata_2025 huggingface dataset:
Integrity Management of Hydrocarbon Riser Caisson System
Authors: Anunobi Kingsley
Published: July 2010

The major design consideration for the hydrocarbon caisson is to protect the risers against external impact from supply vessels, intervention vessels etc. It also protects the riser from hydrodynamic loading and corrosion but in contrary makes the inspection of the riser external and caisson internal wall difficult.

A hydrocarbon riser caisson represents a safety critical item of an offshore platform installation. The major threat of loss of riser caisson integrity cannot be over emphasised. Loss of containment could be as a result of corrosion of the riser external and the caisson internal if the caisson annulus is not well managed. The corrosion process will gradually reduce the wall thickness of the riser until failure resulting from pressure build-up of hydrocarbon within the caisson annulus. The likelihood of caisson failure is increased if the caisson itself has suffered from internal or external corrosion.

This paper will describe the processes involved in managing the integrity of riser caissons/j-tubes as highlighted by the failure of a gas lift riser located within a hydrocarbon caisson. A study of the associated riser Caissons is presented highlighting the basic approach taken for the integrity review/re-assessment of all the remaining hydrocarbon riser caisson facilities within the North Sea field complex. The integrity review process applied, involved the detailed review of the general arrangement of the system, the design intent, the current integrity management status and the integrity management requirements for the riser caissons.

A risk based inspection approach could then be used to generate an integrity management plan based on the current integrity management strategy developed. In this way further loss of hydrocarbon containment issues, with their associated risk and cost within the field complex, could be prevented.
Prevention Better Than Cure – Emulsion Prevention of SOBM With Heavy Brine & Frac Pack Fluid in a GoM Gas Well
Authors: McBee Jim , Singh Amit , Arceneaux C. , Berry S.
Published: July 2010

A gas well in GoM was drilled with Synthetic Oil-Based Mud (SOBM) to achieve acceptable completion efficiency. During the drilling phase more than 4,200 bbl of SOBM was lost to the pay zones. Wells within near proximity, drilled with SOBM in similar reservoirs had a history of emulsion problems with SOBM, heavy-density completion brines and frac pack fluids. Those wells experienced productivity issues related to high drawdowns due to emulsions that were visibly produced to surface. Remedial treatments were necessary to produce these wells effectively. The results after remedial treatments were effective, but did not maximize production to its full potential. Hence, prevention rather than remedial treatments of the emulsion was desired during planning of the new completion.

This paper examines the completion of a gas well, where efforts were made to prevent the formation of emulsions. Detailed laboratory testing and compatibility studies of the lost SOBM with heavy brine and frac pack fluid systems helped to select suitable chemical and surfactant packages. This emulsion prevention package was pumped ahead of frac pack fluids and was an inherent part of all the fluid systems injected into formation during completion phase.

This approach and application was utilized to complete two zones in this well. Production testing and flow back of both zones indicated the absence of any emulsion issues. Laboratory testing of the recovered fluid samples confirmed the nonappearance of any emulsions. The initial gas production from each zone is more than 5 MMscf/D at a low drawdown at its planned potential. The selection and application of a suitable chemical & surfactant additive system successfully prevented the emulsion problem.

Detailed laboratory studies and pre-planning helped to develop an emulsion prevention package, and its application prevented the formation of emulsions with successful production.
Simulation on the Water Controlling Performance of RPM in Hydraulic Fracturing of Low Permeability Reservoirs
Authors: Luo Mingliang , Wen Qingzhi , Liu Hongjian , Liu Jialin , Jia Zilong , Sun Hu
Published: July 2010

Hydraulic fracturing is the most effective method for improving hydrocarbon production in low or ultra-low permeability oil reservoirs, but the majority of selected wells for fracture stimulation are considered "risky" because of significant water cut increase after stimulation. Relative Permeability Modifiers (RPM) have proven to be an effective method to enhance oil recovery, especially under linear flow conditions achieved after fracturing. However, RPM treatments are not always effective. At present, the evaluation of water controlling performance of RPM is mainly based on the core flow test in lab and the actual water product after RPM treatment and the results can not provide the effective support for the RPM treatments in hydraulic fracturing, especially for low or ultra-low permeability reservoir.

In this paper, the interrelations between the water controlling performance of RPM and the main parameters in hydraulic fracturing such as the properties of reservoir matrix, fracture and fluid (reservoir fluid and treatment fluid) etc, were studied using a model. The model is a radial, isothermal, two-phase, multi-component and single layer mathematical model, in which the threshold pressure gradient is considered. Through simulation, we can conclude that the most influential factors in the treatment response, i.e. the water cut reduction, are the combination of polymer adsorption type (kinetic or equilibrium) with method of application of the resistance factors (threshold or variable), resistance factor ratio, reservoir fluid properties, fracture properties and reservoir layout. On the other hand, the polymer solution rheology is not an important factor regarding the treatment response. Hence, the factors that affect the polymer solution viscosity such as shear stress, reservoir salinity and pH are of some importance with respect to drawdown, but they do not have a major influence on the response outcomes in terms of oil recovery.
Alternative Method to Determine Pore Volume Compressibility Attributable to Production-Induced Reservoir Compaction
Authors: Bai Mao , Shen Xinpu , Li Gang
Published: July 2010

In evaluating the process of rock deformation as a result of fluid withdrawal, two approaches prevail: macromechanical and micromechanical methods. In the oil and gas industry, the macromechanical method assesses the formation compaction arising from hydrocarbon production under reservoir field scales. The micromechanical method examines the origin of formation compaction arising from hydrocarbon production under micro-pore scale. The primary purpose of this micromechanical approach is to determine the critical pore strains subjected to the specified rock deformation and fluid drawdown that may lead to excessive reservoir compaction that is detrimental to the stability of subsurface structures (such as generating excessive sand production). This paper proposes the alternative conceptualization and formulation of pore volume reduction under both hydrostatic and uniaxial strain loading conditions. The result can be calibrated by the conventional pore volume compressibility (PVC)/compaction experiments. Furthermore, the proposed method considers the simplified concepts of pore volume reduction and solid volume reduction under the simple loading conditions amenable to laboratory testing techniques. The collective solutions yield the pore volume reduction in the form of reservoir porosity change that becomes a useful assessment to the planned reservoir production rate, and associated reservoir compaction, which is particularly important to the production in soft rock reservoirs where the reservoir compaction is often too significant to be manageable. The application of the developed critical pore strain in relation to bulk compressibility and PVC along with the variation of pore pressure and in-situ stress under the uniaxial strain testing conditions is illustrated in a simple case study.
Limitations in Numerical Well Rest Modelling of Fractured Carbonate Rocks
Authors: Corbett P. W. , Geiger S. , Borges L. , Garayev M. , Gonzalez J. G. , Valdez C.
Published: July 2010

Interpreting well-tests in (fractured) carbonate reservoirs poses significant challenges because these reservoirs often demonstrate triple porosity system (fracture-matrix-vugs) characteristics. However, there is no "unique" triple porosity system: The matrix can behave as a double porosity/dual permeability system whilst the fractures provide the third system; there may be two fracture systems and a single matrix; there may be vugs (macropores), mesopores and micropores to provide very large contrasts in matrix permeabilities. Modelling these systems is challenging because of the need to include heterogeneity for the matrix (or multiple matrices) and fracture(s) and determine the correct coupling between these systems.

The typical well test response in fractured systems – the classic double porosity "V" – can provide factors such as ω and λ as a description of fracture-matrix interaction (storativity ratio and the interporosity flow coefficient, respectively). Understanding how these two parameters relate to the description of matrix and fracture properties in triple porosity systems requires exploration of new scenarios in numerical well test modelling (sometimes called "geological well testing"). In this paper, we set out some of the reservoir description, modelling and simulation challenges to provide guidance on how to set up systematic models and determine the appropriate family of geotype (families of closely related pressure derivative response) curves for fractured carbonate systems in order to understand the interpretation of ω and λ.
History Matching with Differential Evolution Approach; a Look at New Search Strategies
Authors: Hajizadeh Yasin , Christie Mike , Demyanov Vasily
Published: July 2010

History matching and uncertainty quantification are two important aspects of modern reservoir engineering studies. Finding multiple history matched models for uncertainty quantification with fast and efficient optimization algorithms are the focus of research in assisted history matching methods. Recently a new approach for history matching has been proposed based on differential evolution optimization algorithm. Differential evolution is a very powerful optimization method with a simple structure and few tuning parameters which makes it easy to use in automatic history matching frameworks.

In this paper we are looking at three new search strategies as alternates to the proposed method in previous publication for obtaining multiple history-matched reservoir models. These strategies of differential evolution are different in the way that new models are generated during automatic history matching process. The comparative study presents the differences between performances of new search schemes for a simple reservoir simulation case in Gulf of Mexico. We compare the best history matching results and sensitivity of algorithms to starting conditions. Tradeoff between speed of convergence to good fitting regions and coverage of the search space is also demonstrated for different variants of differential evolution. We show that some variants of differential evolution exhibit global searching characteristics, while other ones quickly obtain good results, saving time and computational resources in reservoir engineering studies. Final part of this paper focuses on the uncertainty of production forecasts, discussing the prediction capability of applied differential evolution algorithms.
Advantages of Inflatable Packer Technology for Temporary or Permanent Well Abandonment in the Gulf of Mexico
Authors: Vaucher David , Brooks Robert
Published: July 2010

With so many wells operated in the Gulf of Mexico, one would think that the process of eventually abandoning these wells temporarily (during hurricane season), or permanently plugging and abandoning (P&A) them is by now more routine. Certainly, there are years worth of procedures and case studies on the subject, yet there are always "special cases" that require more specialized planning and equipment. For instance, toppled rigs present the challenge of "kinked" tubing, while other wells have several tubing or casing strings through which a plug must pass before setting in a larger diameter opening. For these non-routine operations, inflatable packer technology presents several significant advantages: small restriction clearances and high expansion ratios as compared to traditional mechanical bridge plugs. Additionally, inflatable plugs are incredibly versatile in that they can be conveyed to depth using either coil tubing, threaded tubing, even slickline and wireline. Finally, inflatable plugs do cover a wide range of hole conditions (temperature, washouts, etc), and are therefore robust enough for most well decommissioning jobs.

This paper will present the unique advantages of inflatable packer technology in these decommissioning operations and will illustrate these advantages using job examples and case studies. The examples and cases used will be limited to the Gulf of Mexico, yet the advantages of these technologies can be applied to any well worldwide.
Scale Inhibitor Squeeze Treatments based on Modelling Studies
Authors: Raju Kris U. , Al-Buali Muhammad H. , Al-Saadoun Turki F. , Aramco Saudi , Mackay Eric J.
Published: July 2010

Scale inhibitor treatment programs for crude producers in Saudi Aramco have been exceptional in the oil industry. Development and application of various scale inhibitor treatment programs that incorporate the latest university industry-funded research findings improved the treatment lives over ten plus years for lowest possible cost. Phosphonate based scale inhibitor squeeze treatments provide the most effective means of preventing CaCO3 scale formation in our carbonate fields. Based on the mathematical scale inhibitor squeeze (SIS) model for horizontal wells, we applied a simple bullheaded squeeze treatment avoiding expensive coiled tubing application.

Conventional squeeze treatments with acidic scale inhibitors and an aqueous overflush generally resulted in initial high watercut and occasionally productivity decline. Recent research on phosphonate-carbonate interactions, and modelling of these interactions, and the impact of two-phase flow by the FAST group at Heriot-Watt University (HWU) - described in SPE 87448, SPE 100515 and SPE 114105 - led to improved squeeze treatment performance.

Based on the above studies, significant changes were introduced to the main scale inhibitor formulation and the overflush stages. These treatments were performed on both vertical and horizontal wells in our largest carbonate oilfield. The new modifications have resulted in better well response compared to earlier acidic scale inhibitor treatments. There was either a small drop in water-cut or else the wells maintained the same value, instead of the increase in water mobility observed with earlier treatments. Similarly, productivity changes are better with the modified treatment compared to the old program. This paper describes the theoretical background in selecting simple bullhead treatment for horizontal wells, partially neutralized phosphonate based scale inhibitor and the overflush formulations and the resulting field productivity changes after treatment.
Development of a New Corrosion Management Tool - Inhibitor Micelle Presence as an Indicator of Optimum Dose
Authors: Mackenzie C. , Magdalenic V. , Perfect E. , Achour M. , Blumer D. , Joosten M. , Rowe M.
Published: July 2010

This paper discusses the principle and proof of concept of a novel corrosion management tool based on maintaining optimum corrosion inhibitor dose in an inhibited environment. Film-forming corrosion inhibitors typically contain active ionic surfactant molecules which adsorb on surfaces and form a protective barrier against corrosion. Upon saturation of surfaces by the inhibitor, the molecules are found in the aqueous phase as micelles or in the oil phase as reverse micelles. The proposed technique is based on the hypothesis that the presence of these micelles in the water phase could be used to indicate the total surface coverage and therefore the optimum dose.

The technique has been applied in the laboratory simulating an actual inhibited multiphase production system. Fluorescent markers, that are extremely sensitive to micelle presence, have been developed and used during the lab testing. Results were compared to standard laboratory techniques, including interfacial tension (IFT) and particle size analyses (diffraction) in order to determine the efficacy for micelle detection. Corrosion bubble tests were also used to determine any link to inhibitor efficiency.

IFT results showed complex events occurring with increasing inhibitor concentration. The IFT vs. inhibitor concentration curve was non-classical, but suggested micelle formation at around 150ppm. Fluorescence analysis suggested that micelles formed starting at 150ppm dose. Particle size analysis was consistent with micelle presence beyond this concentration.

The analytical comparisons supported the underlying principles of this micelle detection technology. Further development is required to demonstrate the real-time link with corrosion protection, but other studies have already confirmed such correlation. Development of a portable device is underway and will provide an important new tool for proactive corrosion management in the oilfield, as well as a useful laboratory qualification method.
Discrete Fracture-Vug Network Model for Modeling Fluid Flow in Fractured Vuggy Porous Media
Authors: Yao Jun , Huang Zhaoqin , Li Yajun , Wang Chenchen , Lv Xinrui
Published: July 2010

Modeling and numerical simulations of fractured vuggy porous media is a challenging problem due to the presence of cavities called macro vugs which are connected via discrete fractures networks. The main difficulty is the co-existence of porous and free-flow region in such media on macro scale. In this study, a novel conceptual discontinuum model i.e. discrete fracture-vug network (DFVN) model has been proposed to this problem.

In DFVN conceptual model, naturally fractured vuggy porous rock masses are considered as a composite porous material, consisting of (1) macro fractures system, (2) porous rock matrix system, and (3) macro vugs system. Macro fractures and vugs are embedded in porous rock, and the isolated vugs are connected via discrete fracture network. We model the fractured vuggy media on macroscopic scale using Navier-Stokes equations within the vugular region, Darcy's law within the porous flow region including porous rock matrix system and macro fractures system, and a Beavers-Joseph-Saffman boundary on the interface between two regions.

A standard Galerkin finite element method is implemetated for the solution of DFVN model. A good match with analytical and numerical solutions for Poiseuille flow in a free/porous channel was achieved, which verified the accuracy of our finite element numerical scheme. Both 2D DFVN models with homogeneous isotropic rock matrix and heterogeneous anisotropic rock matrix are simulated and studied. The numerical results have shown that DFVN model provides a natural way of modeling realistic fluid flow in fractured vuggy porous media.
Control and Removal of Downhole Interfacial Solids
Authors: Smith J. Kevyn , Wahus Dale , Boyd Galyn , Fu Qiang , Boyce Greg , Firouzkouhi Fafa , Deichert Dominic
Published: July 2010

The control of the formation, accumulation, and precipitation of downhole solids is critical to the efficient operation of placed equipment. Downhole solids formation can lead to premature sucker rod lift pump failure and subsequent lost production. Control of these solids is often complicated by the speciation, location and treatment availability. Well conditions, such as temperature and pressure, commonly have varying effects on the individual components of these complex solids mixtures thereby complicating the control of their formation, maturation and precipitation. Removal of these solids is generally accomplished by the application of batch treatment programs or continuous application of scale inhibitors, surfactants or iron chelators. However, there is another mode of control that is not common practice in the oil field, control of the particle size. In this paper, we seek to demonstrate the control of the particle size of a complex mixture of solids by the use of a highly surface active dispersant that is specific for FeS. In this study, removal and control of a complex scale mixture, which included FeS, FeCO3, ZnS and CaCO3 in several oil wells in North Dakota, was studied by applying the FeS dispersant and a FeCO3/CaCO3 scale inhibitor. Action against these solids present at the downhole interfacial pad, as well as those that are newly formed are inferred from observation of the suspended solids, as collected from Millipore filtration, pump friction, pump loading, and residual oil in water. Correlation of this data showed that control of the particle size, as well as, the removal of the downhole interfacial pad was achieved within a month of treatment with this highly surface active dispersant and scale inhibitor. After approximately 14 months of treatment, the long term analysis of this treatment has revealed that this approach has increased SRL pump life and decreased operational costs due to treater upsets, pump longevity and reduction of the instances of bad oil.
Scale Inhibitor Application In Northern Alberta: A Case History Of An Ultra High Temperature Scale Inhibition Solution In Fire Tube Heater Treaters
Authors: Wylde Jonathan J. , McMahon Jeff , Mayner Steve
Published: July 2010

This paper reports a challenging and unique scale forming environment in Northern Alberta, Canada. Calcite was forming on the fire tubes in a series of treaters. Bulk fluid temperature was 110°C but skin temperature of the fire tubes was in excess of 450°C. This created an incredibly high scaling potential.

The paper provides background on the field case history with a detailed description of the process and the scale forming environment. An in-depth scale modeling study characterizing the scaling up to 200°C is provided.

Further laboratory studies are reported including performance testing on candidate scale inhibitors and differential scanning calorimetry to determine their molecular stability. The testing looked at scale inhibitors and investigated the direct inhibition properties as well as any dispersion properties to prevent surface adsorption of scale on the fire tubes.

The testing found that the incumbent scale inhibitor (phosphonate based) was a good product for the bulk scale inhibition but was not stable at the temperature of the fire tubes. The most thermally stable scale inhibitors tested were polymaleic acid copolymers and polymeric acrylic acids of low to medium molecular weight. No scale inhibitors were tested to be fully stable up to 450°C but it was found in field application that the best product identified through laboratory testing was sufficient enough to delay the scale formation on the fire tubes. It is hypothesized that the product was stable at high temperature for the residence time of fluid in the treaters or imparted some degree of scale inhibition even after thermal molecular scission.

The paper concludes with data of the fire tube change out history highlighting the step change in performance when applying the polymeric inhibitor quantified by change out frequency and presence of hot spots.
DASS Well- A New Concept of Multiple Zone Well Completion
Authors: Dass Chanchal
Published: July 2010

Over the years, several techniques for multiple zone well completions were evolved in oil industry but due to some or other reasons the popularity of multiple zone well completions lost. Earlier attempts for multiple zone completions were to use multiple tubing or commingling large number reservoirs. Now a new concept of well completion is available in which all the advantages of multiple tubing completions and commingle production can be retained with a single tubing well completions.

The name of the concept well is DASS well. DASS well stands for Dynamically Activated Super Solution wells. The well architecture is radically different from existing well completions. The reservoir fluid enters the well bore through a production chamber. Production chamber is one device which is set over perforations. Multiple production chambers can be installed in a well depending upon the number of zones available for production. A multiphase flow meter and fluid flow control valve are fitted in the production chamber which is operated from surface control panel. The well fluid is flowed from production chamber through control valve to the well bore. The well depth depends upon the expected fluid production rate. A down hole pump is installed to pump the liquid through tubing and gas is produced through annulus in such a way that surface separation minimized/eliminated.

In this paper, the author introduces "DASS well" - the new concept of multiple zone well completion with detailed description and diagram with its advantages and disadvantages.

Deepwater development demands a simple and cheap well completion technology which can help in efficient production, handling, storage and transportation of oil and gas in addition enhancing oil production through advance processes. DASS WELL-the new concept for multiple zone well completion can prove helpful in this direction.
Non-Darcy Displacement in Linear Composite and Radial Flow Porous Media
Authors: Wu Yu-Shu , Fakcharoenphol Perapon , Zhang Ronglei
Published: July 2010

This paper presents Buckley-Leverett type analytical solutions for non-Darcy displacement of two immiscible fluids in linear and radial composite porous media. High velocity or non-Darcy flow commonly occurs in the vicinity of wellbore because of smaller flowing cross-sectional area, however, the effect of such non-Darcy flow has been traditionally ignored. To examine physical behavior of multiphase immiscible fluid non-Darcy displacement, an extended Buckley-Leverett type of solution is discussed.

There exists a Buckley-Leverett type solution for describing non-Darcy displacement in a linear homogeneous reservoir. This work extends the solution to flow in linear and radial composite flow systems. We present several new Buckley-Leverett type analytical solutions for non-Darcy flow in more complicated flow geometry of linear and radial composite reservoirs, based on non-Darcy flow models of Forchheimer and Barree-Conway. As application examples, we use the analytical solutions to verify numerical simulation results as well as to discuss non-Darcy displacement behavior. The results show how non-Darcy displacement in linear and radial composite systems are controlled not only by relative permeability, but also non-Darcy coefficients, characteristic length, injection rates, and as well as discontinuities in saturation profile across the interfaces between adjacent composite flow domains.
Simple-to-Use Predictive Tool for an Accurate Estimation of the Water Content of CO2
Authors: Bahadori A. , Maddahi M. , Vuthaluru H. B.
Published: July 2010

CO2 emissions from burning fossil fuels have been identified as the major contributor to the increase in atmospheric CO2 levels that can potentially lead to global climate changes. In this work, an easy-to-use predictive tool which is simpler than existing approaches, less complicated with fewer computations, is formulated to arrive at an appropriate estimation of the water content of carbon dioxide-rich phase. The new developed method works for pressures ranging from 5 to 70 MPa (which covers the pressure that is widely considered in CO2 sequestration) and temperatures from 20 to 75°C. Comparison of predicted results with the reliable experimental data indicated excellent agreement with the average absolute deviations being less than 1.5%. This simple-to-use predictive tool can be of immense practical value for the environmental engineers and scientists to have a quick check on the water content of carbon dioxide-rich phase at various temperatures and pressures without performing any tedious experimental measurements. The proposed method is superior owing to its accuracy and clear numerical background, wherein the relevant coefficients can be retuned quickly for various cases. In particular, personnel dealing with regulatory bodies of greenhouse gas control and process industries would find the proposed approach to be user friendly involving transparent calculations with no complex expressions.
Preparation of Microgel Nanospheres and Their Application in EOR
Authors: Wang L. , Zhang G. C. , Ge J. J. , Li G. H. , Zhang J. Q. , Ding B. D.
Published: July 2010

Polyacrylamide microgel nanospheres were synthesized by inverse microemulsion polymerization with redox initiators on the basis of the preparation of water-in-oil (W/O) microemulsion with diesel oil, sorbitan monooleate, polyethylene glycol sorbitan monostearate, acrylamide, N,N′-methylenebisacrylamide and deionized water. By adopting a twice synthesis process, polymer content can be substantially lifted from 24.43 wt% to 35.04 wt%. Moreover, it's proved that nanospheres can expand from the initial 50nm or so to several microns after water absorption.

In this paper, synergy effects of the emulsifiers (sorbitan monooleate and polyethylene glycol sorbitan monostearate) separately with alkalis and surfactants are firstly proposed and verified via the achievement of ultra-low interfacial tension (IFT). Profile control and oil displacement tests by sandpacks further demonstrated the promising future of nanospheres in enhanced oil recovery (EOR) with incremental oil recovery over 20% OOIP after primary recovery.
Changing the Game of Fluid Placement: Intelligent-Well Intervention on a Trilateral Horizontal Well
Authors: Jacobsen J. R. , Kharrat W. , Noya J. V.
Published: July 2010

Matrix acidizing stimulation in carbonate formations with open hole and multilateral completions presents several challenges to insure an optimum treatment is performed. Each lateral must be accessed to place and clean up the acid treatment. The key objective of the intervention is not only to eliminate as much as possible the damage in the matrix produced by the drilling and completion process, but also trying to connect to high conductive fractures that will maximize the drainage of hydrocarbons out of the formation. In this type of completions, traditional practices are limited to spot stages of fluids (pre-flush, acid, and diversion) in front of the formation without much control over the placement.

This document describes, through a field experience, how new Coiled Tubing (CT) conveyed downhole measurements can assist to overcome the challenges above, enabling more intelligent interventions. An innovative workflow designed to optimize stimulation treatments as they occur was implemented for the first time in Saudi Arabia on a sub-hydrostatic, trilateral horizontal openhole oil producer. The workflow uses as reference formation porosity or permeability logs as well as Distributed Temperature Surveys (DTS) for the evaluation of distribution and fluid temperature responses to decide selective placement of stimulation fluids. A consistent lateral fluid flow distribution from the preflush stages and acid stage treatments in each well's lateral, as well as a bullhead injection test recorded in the main bore, is presented. Selective lateral access was enabled by using an Indexing Flow-activated Bent Sub (IFBS) and confirmed upon entry using a real-time casing collar locator (CCL).

The well began producing at the maximum capacity of the ESP pump used to clean the well after the acid treatment, with results that exceeded expectations, effectively overcoming the high drawdown and low Productivity Index (PI) observed in the well.

This experience demonstrates that innovative downhole measurements in combination with the referred workflow make possible to understand fluid distribution and control fluid placement with Coiled Tubing, unlocking the well production potential. This new technique is proven to be an optimum solution for the type of completions commonly found in Middle East.
Modeling of Multisegmented Thermal Wells in Reservoir Simulation
Authors: Semenova Anna , Livescu Silviu , Durlofsky Louis J. , Aziz Khalid
Published: July 2010

Advanced wells are being used more and more frequently to improve the economics of oil field operations. Such wells can contact larger regions of the reservoir than is possible with standard wells. Because these wells can be very long, pressure drop along the well and temperature effects (in thermal problems) can became quite important. Modeling of advanced wells where thermal effects need to be included is a difficult task, and available models are often limited in their capabilities or are inefficient.

A suitable model should be able to handle complicated well trajectories, heat transfer to and from the well, the hold-up of fluids due to slip between phases, and pressure change due to friction. This paper presents a comprehensive multisegmented well model that includes these features. The model has been implemented in Stanford's General Purpose Research Simulator (GPRS). It calculates both pressure and temperature profiles along the well for standard wells and wells with complicated trajectories. One of the advantages of our model is that both homogeneous (no slip) and drift-flux flow models can be used to determine phase distribution within the well. The hydrocarbon fluids can be described either through a black oil representation or using a general compositional model with an arbitrary number of components. The proposed multisegmented well model was tested with a number of challenging and realistic examples. Our results show that the model is stable and in most cases converges in only a few iterations even with reasonably large time steps. The capabilities of the model are demonstrated using three examples. The first example involves a vertical production well with the fluid represented in terms of six hydrocarbon components and water. For this case we demonstrate the importance of slip between phases. The second example is for a thermal multilateral well with two branches and a fluid with three hydrocarbon components. The third example shows our ability to model phase appearance and disappearance in the wellbore and demonstrates the impact of temperature on oil and gas rates during production.
The Effects of Barium Sulphate Saturation Ratio, Calcium and Magnesium on the Inhibition Efficiency: II Polymeric Scale Inhibitors
Authors: Shaw S. S. , Sorbie K. S. , Boak L. S.
Published: July 2010

In oilfield produced waters, the mineral scaling problem is a "moving target" since the seawater/formation water (SW/FW) mixing ratio is constantly changing. Therefore, for barium sulphate for example, the barite saturation ratio (SR), the yield of barite precipitate and molar ratio of Ca2+/Mg2+ in the produced waters are all evolving over time.

This paper describes the effects of saturation ratio (SR) and Ca2+/Mg2+ ratio on barium sulphate inhibition efficiency (IE) of the polymeric scale inhibitors (SI), PPCA (phosphino poly carboxylic acid), MAT (maleic acid terpolymer), and SPPCA (sulphonated PPCA). The behaviour for polymers is compared with similar results for phosphonates reported in Paper I (SPE 130373). IE experiments were carried out for a wide range of SW/FW compositions (i.e. SR and Ca2+/Mg2+ varying). The minimum inhibitor concentration (MIC) levels of these polymeric SIs broadly correlate with the level of barite saturation ratio (SR). When experiments were repeated but the produced brine Ca2+/Mg2+ ratio was fixed, a similar IE trend is maintained. However, using the non-sulphonated polycarboxylate SIs (PPCA and MAT), the base case MICs are lower than the fixed case MICs whereas using SPPCA, the converse is true i.e. the fixed Ca2+/Mg2+ case MIC < base case MIC. We have demonstrated that the high [Ca] in the fixed case tests causes some SI precipitation with brine Ca2+ when PPCA is being evaluated. Sulphonate functional groups on polymeric SI molecules help to prevent such problems encountered with brine Ca2+. Low levels of brine calcium (~500–700ppm) can be very beneficial to the IE performance of PPCA. However, when the [Ca2+] reaches a certain level (~1000ppm+); this causes some precipitation of a Ca_PPCA complex. We show that lower [Ca2+] levels are optimum (~500–700ppm) and we deduce this is why non-sulphonated polycarboxylate SIs PPCA and MAT perform better under base case mixing conditions (lower [Ca2+] mix).
Effective Perforating Design for Matrix Acidizing in Pre-Salt Carbonates
Authors: Filho Hercilio , William A. , Gabriel E. , Junk E. , Boucher A. , Baumann C. E.
Published: July 2010

Engineers face many challenges in deciding how to complete Pre-Salt, carbonate reservoirs offshore Brazil. These challenges include: predicting reservoir performance; evaluating well productivity; determining the best completion design strategy; and finally, determining the best matrix stimulation techniques. Matrix acidizing is a common approach to enhance production from carbonate reservoirs. Well defined wormholes bypass near wellbore damage and provide greater reservoir productivity. Poorly known microbial carbonate can impact acidizing diversion and effectiveness in such rock. Optimizing the stimulation process by perforating and acidizing in the correct way in such high-cost projects is a crucial issue for improved well productivity.

This paper discusses how effective perforation design positively impacted the evaluation (Well Testing) and acidizing efficiency in such formations. Results from pre and post matrix acidizing PLT logs and transient analysis from downhole and surface well test data demonstrates perforating design efficiency and how it aides in diverting acid over the entire interval compared to another well in the same field.
Breaking Oil Recovery Limit in Malaysian Thin Oil Rim Reservoirs: Force Balance Revisited
Authors: Razak Ezzam A. , Chan Keng Seng , Darman Nasir
Published: July 2010

The goal of an oil field development project is to accelerate the hydrocarbon production and optimize the recovery at the lowest cost. For a thin oil rim reservoir with a large gas cap on top and a strong aquifer below, achieving such goal can be very challenging since recovery of both oil and gas needs to be optimized. A successful project may entail plan first to accelerate the oil production with re-injection of the produced gas at the gas cap, maximizing the oil recovery prior to the start-up of the gas cap blow-down (Ref. 1–2).

The maximum oil recovery factor achievable in thin oil rim reservoirs was evaluated for a Malaysian thin oil rim reservoir based on dynamic flow properties. The force balance between the gas cap expansion, aquifer expansion and viscous withdrawal (volumetric fluid production) was demonstrated by showing the model simulated water-oil and gas-oil contact movement. The understanding of the force balance progressively guided the field development project team to selectively re-activate some of the idle wells, to selectively place new additional infill horizontal wells, and to plan selective water and gas injection in key reservoir sectors.

In this paper, the impact of changing force balance on oil recovery by increasing viscous withdrawal with increasing idle well re-activation and infill horizontal well drilling at their respective optimum produced gas re-injection was reported. This effort showed a potential of improving the current recovery factor from 35% up to 48%, at and above the estimated theoretical maximum oil recovery efficiency.
Effects of Sulphide Scales (PbS, ZnS & FeS) on BaSO4 Crystal Growth and Dissolution
Authors: Okocha C. , Sorbie K. S.
Published: July 2010

Sulphide scales (iron sulphide, FeS, zinc sulphide, ZnS, and lead sulphide, PbS) are occurring more commonly in many water producers and these deposits and colloids may lead to various production problems. In addition to being a problem, the presence of these sulphides also affects barium sulphate deposition. The resulting crystal distortions of the barite may play an important role in either enhancing or retarding the barite scale inhibition itself. This study investigates the effects that sulphide scales have on the crystal lattice of barite during its formation. These effects vary based on the type of sulphide scale which co-precipitates with the barite scale. FeS was found to have the most profound effect on the barite crystal by causing severe crystal distortions and it also adheres more strongly to the outer layers of the barite. It is also found that the FeS/barite scales are also the easiest of the mixed scales to inhibit. The ZnS and PbS scales did not cause significant crystal distortion of barite compared to the FeS and they were also the hardest mixed scales to inhibit. The effects of generic scale inhibitors (DETPMP and PPCA) on the barite crystal in the presence of sulphide scales were also studied and several interesting findings are noted. The experiments described were carried out using the static bottle tests and crystal morphology was monitored using Environmental Scanning Electron Microscope (ESEM) techniques. Better understanding of the effects of FeS, ZnS, and PbS on harder mineral scales such as barite will help in the design and application of scale inhibitors for mixed scaling systems which occur quite regularly in the field as well as in designing downhole squeeze treatments.
Case Study: Shallow Surface Casing Corrosion Mitigation Evaluation
Authors: Blakney R. G. , Loveland M. J. , Klein P.
Published: July 2010

Shallow surface casing failures have occurred in some wells in the Kuparuk oil field located on the North Slope of Alaska. A previous investigation into these failures has shown that they are caused by shallow external corrosion of the surface casing within the conductor annulus. The corrosion is believed to be caused by the presence of oxygenated surface water in the annulus and exacerbated by the extremely corrosive environment created when this water mixes with the ion-rich cement.

To combat this issue a field wide corrosion mitigation program began in 2006. The program focuses on injecting a corrosion inhibiting compound into the outer most annulus. At the time of this paper, 870 out of 1270 wells have had the mitigation completed. The goal of this compound is to coat the pipe and stop the influx of water into the annulus; without the water influx the corrosion should be reduced.

Concurrent with the mitigation program, a memory logging tool was used to monitor corrosion rates. This tool surveys variations in pipe metal thickness by measuring variation is velocity and amplitude of alternating magnetic waves. The log results display total metal volume by calibrating the tool at a depth that is assumed to be undamaged. The accuracy of this tool was verified for specific casing configurations on 14 wells that were excavated and inspected after logging. Since then, this log has been run several months prior to, at the time of, and several months after injecting the corrosion inhibitor into the annulus on various wells.

Using the data available from the logs and surface casing failures, the effectiveness of the corrosion mitigation program was evaluated. The main focus of this paper will be the methodology and conclusions obtained from the evaluation.

This paper will: Review the cause of shallow surface casing corrosion.Discuss current mitigation methods for reducing this corrosion.Detail how these methods vary based on well head design.Discuss the logging tool, its limitations, and how it was used for evaluation.Summarize the results of the evaluation.Discuss recommendations for improving the effectiveness of corrosion mitigation project on remaining wells.Outline the future of the corrosion mitigation project.
Effects of Oil Compressibility on Production Performance of Fractured Reservoirs Evaluated by Streamline Dual-Porosity Simulation
Authors: Tanaka Shusei , Arihara Norio , Al-Marhoun Muhammad
Published: July 2010

As naturally fractured reservoirs (NFR) present wide ranges of geological characteristics and complex flow mechanisms between matrix and fracture, reservoir simulation is highly necessary to properly evaluate production performance. The production performance depends on fracture distributions and matrix/fracture properties as well as on fluid properties. We studied by simulation particularly about effects of oil compressibility below bubble-point pressure on production performance. Also evaluated was how the compressibility effects vary with different fracture spacing that is generally uncertain even in a production stage and should be characterized by simulation.

We first developed and validated a 3-phase 3-dimensional dual-porosity model with the streamline method. The fluid compressibility is a primary parameter that directly affects the reservoir performance. We accounted for compressibility effects with the total compressibility in the 3-D pressure equations, and with the effective density in the 1-D flow equations along streamlines. A flash-calculation algorithm was incorporated to treat the gas and oil phases correctly. We also considered dissolved gas, capillary pressure and gravity

The oil and gas compressibility definitions presented by Perrine, that have been being used conventionally, show a physical inconsistency such that oil compressibility below the bubble-point pressure increases with the increase of density, and that the mass of gas phase remains constant with changing pressures below the bubble-point pressure. To correct those, new derivation based on the basic compressibility definition was introduced.

With constant water-injection and liquid production rates in a 5-spot well pattern, simulation results using the new and conventional compressibility formulation were compared for different fracture and fluid properties such as shape factor and solution gas-oil ratio. With the new compressibility, we obtained slower declines of the reservoir pressure, higher oil- production rates, lower water-production rates, and slower increases of production GOR. Differences between the results with the new and conventional compressibility are augmented as the fracture spacing decreases.
Alkyl Polyglycoside/1-naphthol Formulations with Ultra-low Interfacial Tensions Against N-octane for Enhanced Oil Recovery
Authors: Iglauer Stefan , Wu Yongfu , Shuler Patrick , Tang Yongchun , Goddard William
Published: July 2010

We present Alkyl polyglycoside (APG)/1-naphthol formulations which show ultra-low interfacial tensions (IFT) against n-octane. We demonstrate that 1-naphthol is very efficient as a cosolvent in terms of reducing IFT. These formulations are therefore potentially suitable as agents for enhanced oil recovery (EOR). An increasing APG concentration strongly increased viscosity, and the formulations showed shear-thinning behavior. In a coreflood EOR test we showed that this type of formulation significantly increased oil production.