bluuebunny/crossref_metadata_2025 huggingface dataset:
Use of Emulsified Acid System with Corrosion Protection up to 350°F
Authors: Wadekar Sushant , Pandya Nisha
Published: June 2014

Acidizing operations increasingly present challenges in deeper formations. The formation of wormholes and inhibition of corrosion are particularly becoming significant because both are drastically affected in deeper wells with higher temperatures. In emulsified acid fluids, the direct contact between the acid and formation is reduced, thus enhancing the formation of wormholes at high temperatures. Emulsions also reduce the direct contact between acid and metal, thus improving the inhibition of corrosion. This makes emulsified acids one of the most promising fluids for high-temperature acidizing operations; however, the primary challenge is stabilizing the emulsion system at increased temperatures and in the presence of corrosion inhibitors. Using the existing emulsifiers, it is often difficult to formulate a stable emulsified acid that can pass corrosion testing above 300°F.

This paper discusses the study of a new emulsifier with a high molecular weight and branched nature. Because of these structural aspects, the new emulsifier retained its emulsifying power at high temperatures and in the presence of corrosion inhibitors. This helped enable the use of appropriate quantities of corrosion inhibitors within the system. The emulsified acid system was further optimized to pass static high-pressure/high-temperature (HP/HT) corrosion testing at 350°F with 20% hydrochloric acid (HCl) strength. The same fluid also passed corrosion testing with 28% HCl strength at 325°F. Per the data, the use of this new emulsifier helped improve both emulsion stability and corrosion inhibition because of better separation between the acid and metal surface. The new emulsifier system also has a lower chemistry scoring index (CSI) than existing emulsifiers.

The acidizing operation of carbonate reservoirs with bottomhole static temperatures (BHSTs) up to 350°F become attainable using the new emulsified acid system. Guidelines for designing acidizing fluids with this higher temperature limit are presented.
Performance Evaluation and Challenges Using Open Hole Multistage Fracturing Completion to Develop Tight Gas Reservoirs in Saudi Arabia
Authors: Al-Dawood Mahdi , Abdul Aziz Azly , Al-Omair Ahmed , Rahim Zillur
Published: June 2014

A low permeability gas condensate carbonate reservoir in the Khuff formation is one of the main producing reservoirs in Field-A in Saudi Arabia. This early Triassic carbonate reservoir, first discovered in 1980, holds significant gas-in-place but is a blend of conventional and tight intervals. Vertical completions, horizontal wells with maximum reservoir contacts, and acid stimulation (matrix and fracturing) are some of the current practices to effectively develop the reserves from the tighter intervals.

In late 2009, the open hole horizontal multistage fracturing (OHMSF) completion assemblies were deployed in several horizontal wells in the tight gas area with the goal of achieving multiple independent hydraulic fractures, greater acid stimulation efficiency, and thereby enhancing well productivity. The OHMSF systems enable the open hole section to be divided into segments based on the reservoir's petrophysical and flow properties by the use of mechanical open hole isolation packers and customizing the stimulation treatment for each segment via fracturing ports that are installed in between the packer assemblies.

Since the inception of OHMFS, many wells were treated and varying results were obtained. The results are dependent not only on reservoir quality and development, but also on the placement of the fracturing ports, number of fracture stages conducted, and fracturing strategy.

This paper provides insight into the planning, challenges encountered, sensitivity analysis and performance analysis of the OHMSF wells in comparison with non-OHMSF wells. It also details several case histories and highlights the results as well as lessons learned that can be applied in the future to improve the recovery.
CT Extended Reach Acid Stimulation in Openhole Wells, Offshore Saudi Arabia: A 23-Well Case Study
Authors: Arukhe James , Hanbzazah Shadi , Ahmari Abdulrahman , Adesegha Rotimi , Perez Joan , Noguera Jose , Krishnan Gopi , Nakhwa Amit
Published: June 2014

A new generation of ultradeep wells has significantly increased in Saudi Arabia in green and brown field developments. One ongoing complex field development is the Manifa field, which is located in northeast Saudi Arabia. Manifa is probably the largest extended reach hydrocarbon producer project globally, with more than two-thirds of its 350 wells being extended or mega reach wells. The offshore portion of the field contains 83 developed wells in 13 platforms with openhole sections within the range of 3,000 to 9,000 ft, where acid stimulation intervention is necessary to remove reservoir damage and to help improve well performance after drilling operations. Although the openhole completions provide superior deliverability, a primary challenge remains with respect to rigless intervention.

The offshore platforms have limited deck load capacity and available deck space necessary for performing coiled tubing (CT) stimulation operations. To overcome these constraints, applicable CT operations from a jackup barge combined with a support pumping vessel were introduced and subsequently developed to allow well interventions using large treatment fluid volumes.

This paper describes CT stimulation campaigns performed on extended reach horizontal wells in the Manifa field. A summary of the steps involved during an improved CT intervention technique successfully implemented within this field to access some of the longest openhole horizontal wells is presented. The importance of a combined application of jackup and stimulation vessel units to help ensure safe project execution on offshore platforms is reviewed.
Environmentally Acceptable Swell Packer Fluid for Unconventional Reservoirs with High-Temperature Applications
Authors: Pandya Nisha , Kalgaonkar Rajendra , Allison Dave
Published: June 2014

In unconventional reservoirs, such as shale reservoirs, the use of sliding-sleeve completions along with chemical swelling external casing packers can lead to increased production rates. This method has been used in unconventional reservoirs (shale) that are drilled horizontally (for maximum reservoir exposure) and hydraulically fracture stimulated in multiple stages. When fracturing a new zone, it is necessary to isolate the various zones that have been previously fractured. By using completion assemblies with sliding sleeves and swell packers activated with chemicals, the various pay zones in a single wellbore can be managed with the option of closing off one or more sliding sleeves at a future date, and isolation is facilitated by using the swell packers.

Swell packers can be activated using water-or hydrocarbon-based fluids. However, these conventional fluids have shown a tendency to damage certain shale formations, thus increasing operator concern when using such fluids in shale reservoirs.

A new environmentally acceptable shale-optimized activation fluid system was developed for use with swell packers. It is an oil-external invert-emulsion consisting largely of an aqueous internal phase incorporated into the hydrocarbon external phase. It is an effective low-leakoff fluid that provides controllable swell profiles for the swell packers while causing minimum physio-chemical damage to shale. Additionally, the system is free of any benzene, ethylbenzene, toluene, and xylenes (BETX) hydrocarbons and incorporates an environmentally acceptable emulsifier. This provides it with an improved environmental profile. Moreover, this emulsion can be stabilized with nanomaterials to promote longevity under high-temperature reservoir conditions up to 225°F. This paper documents the laboratory investigation and development of the novel environmentally acceptable activation fluid system.
The First Successful Multistage Acid Frac of an Oil Producer in Saudi Arabia
Authors: Rafie Majid , Said Rifat , Al-Hajri Muhammad , Almubarak Tariq , Al-Thiyabi Adel , Nugraha Ikhsan , Soriano Eduardo , Lucado Jared
Published: June 2014

In Saudi Arabia, conventional oil reservoirs have been treated using conventional stimulation methods. The challenge is that many of the formations now are tighter and require improved stimulation methods. Fracturing is a major topic discussed in the industry as of late and as such, using it in this formation will serve as a trial to shift from conventional stimulation methods to fracturing when facing tighter formations.

This particular acid frac was performed in a tight carbonate formation. The chosen well is a newly drilled trilateral producer completed with a multistage frac completion in the motherbore and will serve as a pilot well for this reservoir in the area. The acid frac was a seven stage completion utilizing hydraulic fracturing. Several methods using pressure and injection were used to determine reservoir fracturing response and petrophysical properties.

This paper will discuss the first multistage acid frac performed in an oil producer in Saudi Arabia. It will examine the entire process of candidate assessment, job preparation, and execution. In addition, the paper will discuss challenges faced, solutions taken, and the post-decision results. The paper will show how an injectivity test performed pre-and post-frac was used as a benchmarking tool to analyze the effectiveness of the frac. Finally, we will discuss the flow back of the well, initial results, lessons learned, and optimization of future jobs.
Density-Driven Flow Simulation in Anisotropic Porous Media: Application to CO2 Geological Sequestration
Authors: Negara Ardiansyah , Salama Amgad , Sun Shuyu
Published: June 2014

Carbon dioxide (CO2) sequestration in saline aquifers is considered as one of the most viable and promising ways to reduce CO2 concentration in the atmosphere. CO2 is injected into deep saline formations at supercritical state where its density is smaller than the hosting brine. This motivates an upward motion and eventually CO2 is trapped beneath the cap rock. The trapped CO2 slowly dissolves into the brine causing the density of the mixture to become larger than the host brine. This causes gravitational instabilities that is propagated and magnified with time. In this kind of density-driven flows, the CO2-rich brines migrate downward while the brines with low CO2 concentration move upward. With respect to the properties of the subsurface aquifers, there are instances where saline formations can possess anisotropy with respect to their hydraulic properties. Such anisotropy can have significant effect on the onset and propagation of flow instabilities. Anisotropy is predicted to be more influential in dictating the direction of the convective flow. To account for permeability anisotropy, the method of multipoint flux approximation (MPFA) in the framework of finite differences schemes is used. The MPFA method requires more point stencil than the traditional two-point flux approximation (TPFA). For example, calculation of one flux component requires 6-point stencil and 18-point stencil in 2-D and 3-D cases, respectively. As consequence, the matrix of coefficient for obtaining the pressure fields will be quite complex. Therefore, we combine the MPFA method with the experimenting pressure field technique in which the problem is reduced to solving multitude of local problems and the global matrix of coefficients is constructed automatically, which significantly reduces the complexity. We present several numerical scenarios of density-driven flow simulation in homogeneous, layered, and heterogeneous anisotropic porous media. The numerical results emphasize the significant effects of anisotropy in driving the migration of dissolved CO2 along the principal direction of anisotropy even if the porous medium is highly heterogeneous. Furthermore, the impacts of the increase of density difference between the brine and the CO2-saturated brine with respect to the onset time of convection, the CO2 flux, and the CO2 total dissolved mass are also discussed in this paper.
Evaluation of Diagenetic Scaling on Flowback Proppants
Authors: Nanda Jajati , Pal Omprakash , Patil Anil
Published: June 2014

Proppants are used to keep hydraulic fractures open and maintain conductivity for hydrocarbons to produce at higher rates. Diagenetic growths or scales formed under in situ well conditions caused by interactions between proppants and formation minerals within the presence of water can reduce conductivity and cause a decline in production revenue. Previous papers have reported the various geochemical reactions that may occur under downhole conditions, which can cause scaling on alumina-based proppants.

This paper describes a study of diagenetic materials received with proppants that have flowed back from a fractured well. The preliminary examination of the samples under a high-resolution microscope revealed the presence of ceramic proppants, formation dust/sand, and polymers. Microscopic examination revealed white-colored deposits/scaling on the surface of the proppants, which can obstruct fracture conductivity. The polymers from the flowback samples were physically separated from the solids before analysis. Formation dust/sand and proppants were also subjected to X-ray diffraction (XRD) study, which revealed the presence of zeolites and carbonates. The original core cuttings from the respective locations were also studied for the availability of zeolites or carbonates.

The study was performed in the following steps: The flowback samples were studied using a microscope for initial assessment.The samples were studied using XRD for the identification and quantification of phases.The original cores from respective locations were studied using XRD to check the presence of zeolites or carbonates.The post-frac flowback water was studied using inductively coupled plasma atomic emission spectroscopy (ICP-AES) and ion chromatograph (IC), respectively, for cations and anions responsible for carbonate scale formation and the water properties supporting scale formation.

This paper provides a systematic method of analyzing flowback samples to help determine the downhole conditions responsible for the occurrence of diagenetic scale.
How Malfunctioning Completion Accessories Affect Well Performance in Offshore Saudi Arabia
Authors: Al-Khanferi Mohammed , Bubshait Ahmed , El-Fattah Mahmoud Abd , Al-Shabibi Hussain , Bawazir Mustafa
Published: June 2014

To overcome horizontal well reservoir and production challenges, inflow control devices are adopted as the optimal completion method in many parts of the world. The main industry drivers for adopting inflow control device completions include balancing inflow along the well, delaying water and gas breakthrough, controlling water and sand production, and providing a cost-effective reservoir completion solution to meet the majority of the reservoir challenges. In offshore Saudi Arabia, inflow control devices have been used successfully in fulfilling these objectives. The downhole completion efficiency is evaluated using multiphase production logging tools.

Many completion accessories can be run with inflow control device completion strings, these include isolation packers, liner hangers, setting tools, end-of-completion string plugs and valves. All of these accessories may affect the well's production performance. New challenges arise when one of these accessories, such as the end-of-completion valve or isolating packers malfunction and develop a leak; thus, affecting the inflow control device completion performance. A major failure can result from such a malfunction, including fluid drainage from the toe section, sand production, early water breakthrough and water coning.

This paper presents two field examples in which multiphase production logging profiles of horizontal wells are used to evaluate the inflow control device completion performance and detect any completion-accessory malfunction. Multiple sensitivity simulation runs — supported by multiphase production logging results — facilitate optimizing the inflow control device completed well performance. This integrated approach is used to recommend solutions or remedial actions to overcome suboptimal well completion performance. Also, the approach provides a comprehensive understanding of the reservoir results that should be considered in planning future completion and workover strategies.
Integrated Formation Evaluation of Tight Gas Delineation Wells: Best Practices and Lessons Learned
Authors: Hammou Nasreddine , Balawi Ali , Eid Mahmoud , Quirein John
Published: June 2014

The formation evaluation of Saudi Arabian tight gas reservoirs presents multiple challenges. The targeted gas resources discussed in this paper include both conventional and unconventional reservoirs. The complexities encountered include varying mineralogy, facies and mechanical properties, wide ranges of porosities and pore types, hydrocarbon viscosity, and variable formation water salinities. Major petrophysical uncertainties exist, including clay structure, variation of grain size distribution, electrical properties, and water salinity, that can be resolved by determining better data interpretation techniques and customizing the workflow for such reservoirs.

This paper presents interpretations from two wells within the same reservoir, based upon combining the geochemical, nuclear magnetic resonance (NMR), and conventional logging measurements. The integration of NMR data acquired with conventional logs is shown to be beneficial for the identification and quantification of hydrocarbon-bearing reservoirs and provide valuable information about porosity, relative permeability, and reservoir quality to be used for a fracturing assessment. The mineralogy and porosity information are obtained from geochemical and nuclear logs. By combining the mechanical properties results with the geochemical and NMR log total porosity interpretation, fracture parameters, such as Poisson's ratio, Young's modulus, and fracture closure pressure, can be obtained and a better fracturing job can be performed.

The case study results from these two wells demonstrate how to use and integrate all the available data, including the mud logs, to understand the reservoir behavior and to generate a workflow for future wells. This process includes optimizing the NMR activation scheme and using laboratory data to define a model for determining the T2 cutoff. Finally, rock mechanics laboratory measurements are required to develop and validate the fracture parameters prediction model.
Characterization of Heavy Oil Properties in a Complex Shallow Miocene Reservoir in Saudi Arabia using NMR and Other Advanced Log Measurements
Authors: Idris Umar , Hursan Gabor , Saldungaray Pablo , Azam Hisham
Published: June 2014

The successful production of heavy oil (typically defined as oil with an API gravity of less than 20) depends on several reservoir properties such as porosity, permeability and reservoir pressure, but it is the in-situ oil viscosity that dictates the oil mobility and production approach required, and ultimately the economic viability of the project. For this reason, the possibility of estimating the hydrocarbon viscosity from logs, thereby providing a continuous record of the fluid properties along the reservoir is of great value.

Fluid viscosity has a strong effect on nuclear magnetic resonance (NMR) logs, including the NMR relaxation rate (T1 and T2 distributions), diffusivity, and signal amplitude (NMR porosity) measurements. These effects can be exploited to derive correlations to viscosity. Depending on the viscosity range, NMR standalone methods can be used, typically for 1 to 100 cp. For higher viscosities, a volumetric approach is required, combining the NMR data with other logs to develop specific correlations for particular reservoirs and oil types. These correlations are not universally applicable, and must be customized before being applied to a different environment.

Several techniques were compared to estimate oil viscosity in a shallow Miocene reservoir. The formation is characterized by very complex mineralogy, high porosity, and slightly freshwater salinity. This complicates the volumetric approach, which requires an accurate total porosity and oil volume estimation. We discuss how elemental spectroscopy and dielectric logs help to reduce the uncertainty in the viscosity estimation. The merits and applicability of NMR-only techniques in this complex environment were also explored. The log-based viscosity correlations were calibrated with in-situ and laboratory fluid sample viscosity measurements. The model will be used to predict viscosities prior to performing well tests in subsequent wells.
Optimizing Spacing of Horizontal Multistage Fractured Wells in Gas Reservoirs
Authors: Alghannam Maryam , Rahim Zillur
Published: June 2014

The growing demand for gas in the Kingdom of Saudi Arabia and the availability of multistage fracturing (MSF) of horizontal well technology have opened up the development of tight gas reservoirs throughout the country. Draining the reservoir efficiently using MSF strongly depends on well spacing, especially for low permeability reservoirs. The majority of the work done by the industry to find the optimum well spacing was based on economic considerations. Saudi Aramco optimizes field development based on sustained rate and ultimate hydrocarbon recovery. Natural gas is treated as one of the most essential commodities supporting the country's infrastructure based on the increased domestic energy demand.

Some of the significant parameters to consider for well spacing optimization are the drilling azimuth and well completion strategy that include a number of induced fractures, fracture conductivity, and fracture half-lengths. In addition, reservoir properties, such as formation thickness, reservoir permeability, and the permeability anisotropy ratio are to be considered. Due to the scarcity of interference test data in gas wells and the inaccuracy of analytical solutions, numeric simulation is the most suitable approach for such a study. To find the optimum well spacing, several simulation runs are carried out for a realistic range of well and reservoir variables. The outcomes are then translated into a 20-year cumulative production as a function of the well spacing, with the results indicating that lower permeability reservoirs require closer well spacing. In the case of a large number of long fractures, wells need to be placed further away from each other to minimize well interference. This paper gives the recommended MSF horizontal well spacing for several development scenarios in Saudi Arabian gas reservoir environments. Although each area must be individually studied and optimized, the results will provide engineers with guidelines to better plan gas field development with the application of MSF technology.
Lessons from the First Successful Oil Producer Multistage Acid Fracturing in Saudi Arabia: The QA/QC Process from the Laboratory to the Field
Authors: Almubarak Tariq , Bataweel Mohammed , Rafie Majid , Said Rifat , Al-Ibrahim Hussain , Osode Peter , Alfaifi Mohammed , Alenizi Sultan , Aldajani Omar , Karadkar Prasad
Published: June 2014

The increasing demand for energy has extended the development horizon towards relatively tighter formations. However, experience has shown that the most successful technique to optimize production from these tight carbonate formations would require multistage acid fracture stimulation treatment. Generally, laboratory tests, computer simulation and technical expert opinions yield optimistic results which are not always replicated in the field due to the absence of strong QA/QC follow-up. This field support was considered critical for a recent multi stage acid fracture treatment which involved many variables and fluid additives in an onshore Saudi Arabia multi-lateral well. This report will discuss the pre-job laboratory tests and fluid optimization process which included core flooding, compatibility, stability, and rheology tests. In addition, this paper will outline the QA/QC process adopted throughout the various operational stages and provide flowchart as recommendations for subsequent multistage acid fracture treatments in the field. Also presented is a case study from the first successful oil field multistage acid fracture treatment in Saudi Arabia.

Laboratory results obtained reflected the negative impact of increased salinity on the crosslinked viscosity. In addition, a new low temperature-instant crosslinker was evaluated as an alternative which resulted in higher viscosity and faster break time. Further laboratory tests showed the sensitivity of the emulsifier used to mix emulsified acid and this led to corrective changes to the on-site mixing process. These and many other operational adjustments enabled bridging the gap between laboratory design and field implementation, thereby ensuring a successful acid fracturing treatment.
Optimization and Post-Job Analysis of the First Successful Oil Field Multistage Acid Fracture Treatment in Saudi Arabia
Authors: Almubarak Tariq , Bataweel Mohammed , Rafie Majid , Said Rifat , Al-Ibrahim Hussain , Al-Hajri Mohammad , Osode Peter , Al-Rustum Abdullah , Aldajani Omar
Published: June 2014

Multistage acid fracture treatments are utilized in low-permeability carbonate reservoirs (permeability <10 md) to stimulate the formation by creating highly conductive fractures in the formation and bypassing near wellbore damage. The fracture is generated at high pressures that are required to break the rock open while using a viscous pad. The fracture is then kept open by adding gelled or emulsified acid to create uneven etches on the surface of the fracture.

Pre-job acid fracturing treatment fluids’ reaction and compatibility analysis in the laboratory are crucial as the operational success is highly dependent on its chemicals’ reactions. The key problem with acid fracturing treatments is the difficulty in appraising the actual downhole reactions and performance of the treatment chemicals within the heterogeneous rock. This problem can be resolved when flow back fluids and the chemical ions are analyzed to understand the reactions that occurred down hole. Also, since acid fracture treatments require pumping large volume of fluids, flowing back the entire fluids becomes a challenge due to the low reservoir permeability and the associated reservoir rock capillary pressure effects.

This paper will discuss the pre-fracture treatment evaluation based on laboratory experiments - core flood, rock dissolving capacity, and fluid compatibility in addition to comparing the expected chemical ion returns with the actual ions observed in the flow-back fluids.

The results of this flow-back fluid analysis showed a recovery of 17% of the chemicals pumped during the treatment with a stabilized production rate of 3 MBOPD. Further water analysis indicated the presence of 25-30% formation water while the critical ions analyzed showed the effectiveness of the corrosion inhibitor package, acid system dissolving capacity, and crosslinker fluid recovery. It is expected that this paper will provide a learning process for optimizing future multistage acid fracture treatment in Saudi Arabia.
Pressure-Up Blowdown Combustion: A Channeled Reservoir Recovery Process
Authors: Hallam R. J. , Donnelly J. K.
Published: June 2014

The cyclic pressure-up blowdown combustion process was developed as a follow-up to cyclic steam stimulations that used fracturing to create injectivity. The process was designed to exploit a reservoir that had a high contrast between the mobility of the heated channels, left as a remnant of the cyclic steam operations, and the adjacent cold reservoir. The combined process of cyclic steam followed by combustion has the potential to achieve a recovery factor of about 30%.
A New Semi-Analytical Method for Numerical Simulation of Fluid and Heat Flow in Fractured Reservoirs
Authors: Pruess Karsten , Wu Yu-Shu
Published: June 2014

Permeability and flow in many petroleum, gas, and geothermal reservoirs are dominated by fractures. Despite major advances in recent years, mathematical modeling of fluid and heat flow in fractured reservoirs remains a difficult problem. Porous medium approximations have been shown to be inadequate for many flow processes in fractured systems, while double- or multiple-porosity techniques may involve excessive amounts of numerical work or large discretization errors.

We have developed a new method for modeling fluid and heat flow in fractured reservoirs which is an extension of a technique developed by Vinsome and Westerveld (1980), for calculating heat exchange between permeable layers and impermeable semi-infinite confining beds during thermally enhanced oil recovery. Our method combines a finite-difference description of global flow in the fractures with an analytical representation of interporosity flow by means of trial functions for fluid pressures and temperatures in the matrix blocks. The trial functions contain adjustable parameters which are calculated for each time step in a fully coupled way based on matrix block shapes and dimensions, utilizing simple mass and energy conservation principles.

We have incorporated the semi-analytical technique into our general-purpose multiphase simulator MULKOM. The method was verified by comparison with exact analytical solutions for fluid and heat exchange with individual matrix blocks. Applications were made to geothermal well test and production-injection problems with interporosity fluid and heat flow. The calculations show excellent agreement with numerical simulations using the method of "multiple interacting continua" (MINC), with no noticeable increase in computing work compared to porous medium calculations.
Simulation of Miscible Viscous Fingering Using a Modified Method of Characteristics: Effects of Gravity and Heterogeneity
Authors: Moissis D. E. , Wheeler M. F. , Miller C. A.
Published: June 2014

The effects of gravity and of the structure of the porous medium on unstable miscible displacement are studied by means of numerical simulation. The numerical method combines a modified method of characteristics with a mixed finite element method. The permeability fields used in the simulations are generated by a statistical method so that they have a given coefficient of variation and a given correlation length.

Results indicate that a displacement may be dominated by gravity override or by viscous fingering or both mechanisms may be important. When gravity tonguing is dominant, the results are early breakthrough and little oil recovery after breakthrough.

Finger generation is governed by the permeability distribution near the inflow end. Shielding and merging during the displacement reduce the initial number of fingers to a smaller number of "active fingers", which dominate the displacement. The number of active fingers is a decreasing function of the correlation length, the coefficient of permeability variation and the viscosity ratio, but, with these parameters fixed, it is largely independent of the specific permeability distribution. The root mean square growth rate of the fingers stays approximately constant throughout the displacement; its value is an increasing function of the viscosity ratio and coefficient of variation, while its dependence on the correlation length is of a more complex character.
Thermally Stable Gels for Near-Wellbore Permeability Contrast Corrections
Authors: Moradi-Aragbx A. , Bjornson G. , Doe P. H.
Published: June 2014

The application of metallic or organic crosslinkers for gelation of polyacrylamides or polysaccharides is limited to relatively low temperatures and hardness levels. These polymers will initially produce good gels under hostile environment conditions (Hardness > 200 ppm, Temperature>167°F (75°C)), but the acrylamide gels undergo substantial syneresis due to the hydrolysis of the amide groups followed by additional crosslinking with the divalent cations present in the brine. Due to chain scission of the inherently weak ether linkages in the polymer structure, polysaccharide gels do not survive extended aging under hostile environment conditions.

Copolymerization of acrylamide with other monomers can provide protection against excessive thermal hydrolysis. These acrylamide containing polymers can be crosslinked with mixtures of phenolic compounds and formaldehyde to produce gels which are tolerant to the harsh conditions common to most deeper reservoirs. The gels produced by the reaction of these polymers with phenol and formaldehyde in a brine such as seawater containing 3.4% TDS and 1700 ppm hardness have survived over 2 1/2 years of aging at 235°F (113°C). A similar gel had survived over 9 months of aging at 300°F (149°C) in seawater when the test was terminated.

Metallic crosslinkers such as Cr(III) produced in-situ, when used in conjunction with a different thermally stable polymer, resulted in the formation of a stable gel in a brine containing 2.45% TDS and 1, 555 ppm Ca(II). This gel had survived 2 years of aging at 220°F (104°C) before the test was terminated. A similar gel made with polyacrylamide began to synerese within a month and shrank more than 80% in less than three months of aging at 200°F (93°C).

A producing oil well with a bottomhole temperature of 230°F (110°C), treated with organic crosslinking of a thermally stable polymer, has produced over 33, 000 bbls of incremental oil in 54 months since the treatment.
Three-Phase Studies of Gas-Condensate Flow Behavior
Authors: Fishlock T. P. , Smith R. A. K.
Published: June 2014

Experiments have shown that an oil phase introduced by condensation reduces gas relative permeability in the presence of an immobile water saturation. Such an oil phase, however, reduces both the waterflood residual gas saturation and the critical gas saturation for remobilization by depressurization after a waterflood almost to the extent of the oil-phase saturation.
An Analytical Solution for Steam/Oil/Water Displacements
Authors: Wingard J. S. , Orr F. M.
Published: June 2014

Analytical solutions, obtained by the method of characteristics, are reported for displacement of oil and water by injected steam in one dimension. We describe a mathematical model of purely convective flow of two or three phases with temperature variation. The model includes effects of volume change with changes of temperature and phase but excludes efFects of longitudinal conduction or transverse heat loss. We outline the formulation of the resulting eigenvalue problem, and we state and solve the shock balances that are an essential part of the solutions.

We report and compare example solutions for displacement of two oils. The first is a light oil, and the second is an oil with a high viscosity and a strong temperature dependence. The solutions obtained show a steam/oil zone near the injection end, an oil/water zone at the downstream end, and a three-phase steam/oil/water zone in between. We show, for the oil properties and relative permeabilities used, (1) that the steam saturation in the steam/oil zone and the three-phase region is a strong function of oil viscosity, (2) that the overall flow velocity is nearly constant except at shocks where the number of phases change, and (3) that the formation of an oil bank ahead of the three-phase region is possible only for a sufficiently viscous oil.
An Explicit Phase-Behavior Model for Pseudocompositional Reservoir Simulation
Authors: Hustad O. S. , Dalen V.
Published: June 2014

An efficient phase behavior model for pseudocompositional reservoir simulation has been developed.1 The model is based on relatively few pseudocomponents and permits an explicit solution of the phase equilibrium problem. The model parameters are generated from a (simulated) laboratory experiment, that gives suitable compositional and volumetric data. A principal component analysis2 is performed on the compositions from the experiment for the selection of optimal pseudocomponents. The model has been implemented in a compositional reservoir simulator, and comparisons between results obtained with an equation of state approach and the proposed model indicate that the proposed model in many cases may be an attractive alternative to a full compositional treatment for cases where a black oil model is not representative.
Effective Relative Permeabilities for Viscously-Dominated Flow Through Cross-Bedded Units
Authors: Kasap Ekrem , Lake Larry W.
Published: June 2014

The size of the local heterogeneity of most naturally-occurring permeable media is too small to be included in a numerical simulation. However, we can characterize the medium with prototype regularities in the heterogeneity and express the effects of these prototypes through effective relative permeability functions. Cross-bedded flow units, found mainly in sandstone reservoirs, are good candidates for this procedure.

This study describes an analytic method to generate effective relative permeabilities that account for the effects of heterogeneity on a miscible displacement in viscously dominated (gravity-free) flow. The method consists of discretizing a flow unit into subunits to which is assigned an effective permeability tensor that resolves cross bedding and cross-bed orientation. The effective permeability is, in general, a tensor that has nonzero off-diagonal elements. We then analytically generate effective (pseudo) relative permeabilities to account for vertical efficiency sweep caused by differences between the subunits.

We validate the proposed procedure with results that model permeability laminations explicitly on a very fine scale with a finite element simulator. The comparison indicates that analytically generated effective relative permeabilities can accurately account for small heterogeneities in numerical simulations. Thus, effective relative permeabilities, an immiscible flow concept, are used to represent heterogeneities in a miscible displacement. The procedure is limited, however, to viscously-dominated flow.
An Improved Viscosity Correlation for CO2/Reservoir Oil Systems
Authors: Lansangan R. M. , Taylor M. , Smith J. L. , Kovarik F. S.
Published: June 2014

This paper presents a correlation for predicting viscosities of CO2/-hydrocarbon mixtures. Viscosities were measured with a piezoelectric quartz crystal over a range of conditions from 32.2°C [90°F] to 121.1°C [250°F] and 6.89 MPa [1000 psi] to 34.5 MPa [5000 psi]. Crude oils and several synthetic oils were used in the study. The Lohrenz, Bray, and Clark (LBC) correlation was modified using the Corresponding States Principle coupled with new mixing rules to include mixtures with CO2 concentrations of up to 98 mole%. The new correlation showed about 70% improvement in average absolute deviation compared to the LBC procedure. The new correlation is expected to improve our capability to predict oil recovery performance both in the laboratory and in the field.
A Comprehensive Approach to In-Situ Combustion Modeling
Authors: Belgrave J. D. M. , Moore R. G. , Ursenbach M. G. , Bennion D. W.
Published: June 2014

Low temperature oxidation (LTO) has long been recognized as one of the dominant mechanisms controlling fuel availability in in-situ combustion. Its effect on the physical properties of crude oils is also well known. In spite of these findings, the prevailing conceptual model of in-situ combustion still hinges on thermal cracking (in isolation) ahead of the firefront, to provide sufficient fuel (coke) for propagation of the reaction zone. Previous simulation studies, which purported to include LTO as part of the reaction scheme, have unrealistically specified the reaction products as carbon oxides and water. Furthermore, oil compositional changes due to oxidation have been completely neglected.

This paper describes a unified pseudo-mechanistic reaction model for mathematical modeling of in-situ combustion of Athabasca bitumen. The model represents a consolidation of individual experimental kinetic studies on thermal cracking and low temperature oxidation of Athabasca bitumen, and reported data for the high temperature oxidation of coke. The formulation is comprehensive in that it allows bitumen to undergo density and viscosity increases, as well as reduced reactivity to oxidation, with increased oxidation extent. Hydrocarbon bypassing due to quenching of the combustion front is also permitted with the proposed kinetic model.

The paper includes application of the reaction model in numerical simulations of adiabatic combustion tube tests performed on Athabasca bitumen. A significant feature of the model is its ability to predict the dual oxidation uptake peaks associated with ramped temperature oxidation experiments.
Effect of Rock type and Brine Composition on Adsorption of Two Foam-Forming Surfactants
Authors: Mannhardt Karin , Schramm L. L. , Novosad J. J.
Published: June 2014

Adsorption levels of two surfactants (anionic and amphoteric) suitable for foam flooding in high-salinity and high-hardness conditions were measured on sandstone and limestone with different brines. The anionic surfactant adsorbed more strongly on limestone than on sandstone, while the opposite behavior was observed with the amphoteric surfactant. The presence of divalent ions increased adsorption levels of both surfactants on both rocks. Adsorption mechanisms are suggested from measured surface charge properties of the rocks.
Effect of Drying on Travis Peak Cores Containing Fibrous lllite
Authors: Luffel D. L. , Herrington K. L. , Walls J. D.
Published: June 2014

We conducted a laboratory study in the east Texas Travis Peak sandstone, which contains a small but significant amount of fibrous illite, to determine properties of preserved cores compared with those of dried and resaturated cores. Results showed that the drying process significantly changed effective water permeability, capillary pressure behavior, and electrical properties but that effective gas permeability as a function of water saturation did not change.
Experimental Micro-modeling and Numerical Simulation of Gas/Water Injection/Withdrawal Cycles as Applied to Underground Gas Storage Reservoir
Authors: Billiotte J. , de Moegen H. , Oren P. E.
Published: June 2014

This paper presents the results of an experimental and theoretical study of mechanisms responsible for the evolution and structure of the gas bubble during air-water injection-withdrawal cycles in 2D glass micromodels. Wetting films located in the corners of throat section conduct flow. Wetting film flow generates gas loop structure which increases injection efficiency and also the amount of trapped gas during withdrawal. During the next injection, blob distribution and wetting film flow induce a quicker breakthrough. Using a network simulator which takes into account wetting film flow, the influence of flow-rate on cycling is highlighted
Investigation of Crude-Oil/Mineral Interactions: Factors Influencing Wettability Alteration
Authors: Wolcott J. M. , Groves F. R. , Trujillo D. E. , Lee H. G.
Published: June 2014

The influences of core-pretreatment, brine saturation, and CO2-flooding on wettability alteration, and the site, nature and extent of organic deposition in Berea sandstone cores were investigated. Core samples were evaluated using the Amott method for wettability determination, pyrolysis, thin-section microscopy, and scanning electron microscopy (SEM). Investigations showed that CO2-flooding, KOH-treatment, and the presence of brine influenced wettability and the extent of organic deposition; however, there was little correlation between the degree of wettability alteration and the extent of organic deposition.
Scale Problems in Namorado Field
Authors: de Almeida Armando Ferreira , Ferreira Deise Massulo , Tavares Antônio Fernando Cabral , Bezerra Maria Carmen Moreira , Khalil Carlos N.
Published: June 2014

Namorado field was discovered in November, 1975, and is located in the Campos Basin (Brazil) at about 80 kilometers from the sea-shore, in a water depth that varies from 130 to 240 m. The main reservoir is the Namorado Sandstone 1 with an original oil-in-place of 100 MM m3 (630 MMSTB).

The production was started in June, 1979, and the reservoir showed, initially, a great pressure decline caused by the absence of natural mechanisms of pressure maintainance. In order to maintain the reservoir pressure (energy) and obtain the maximum oil recovery, a sea water injection was started in May, 1984.

Today the field is producing around 7600 m3/d (48,000 BPD) with a recovery efficiency higher than 20%. A final recovery factor of 40% is expected to be reached with the water injection.

The water injection project has shown to be very efficient until now and the pressure has been stabilized around the bubble point pressure since the beggining of the injection. As a result of incompatibilities between the formation water and sea water, several wells have presented production problems caused by scale formation, mainly barium sulfate and strontium sulfate.

This paper presents the several problems caused by scale formation and gives an overview of what has been done to find a definitive and economically viable solution. This experience will help solving similar problems that may appear in other fields.
Numerical Simulation of Two-Phase Flow Using Locally Refined Grids in Three Space Dimensions
Authors: Mulder W. A. , Meyling R. H. J. Gmelig
Published: June 2014

A numerical method for incompressible, immiscible, two-phase flow is presented, that uses dynamic local grid refinement and operator splitting. Elliptic equations are solved by a multigrid method, hyperbolic equations by a nonlinear characteristic method. Large time steps are permitted and high accuracy and efficiency are obtained if the total flow field does not strongly depend on the saturation distribution.
Analysis of a Hydraulically Fractured, Low Permeability Gas Reservoir Using Numerical Simulation
Authors: Bastian Peter A. , Sherman Jan B.
Published: June 2014

We have used a three-dimensional, multi-phase reservoir model to history match the post-fracture performance data of two separate completions in the complex, low permeability Travis Peak formation. This model consists of a two-layer, two-phase (gas-water) reservoir in communication with the wellbore via a vertical hydraulic fracture. The two-layer, two-phase reservoir model accurately matches post-fracture production data and pressure buildup test data from each Travis Peak completion interval.

Our results show that the properties of the hydraulic fractures determined by this reservoir simulation are in good agreement with the fracture properties determined by a three-dimensional (3-D) fracture propagation model. In addition, reservoir simulation history matching determined that a multi-layer reservoir system was necessary to model the performance in the lower Travis Peak completion interval.
Buckley-Leverett Flow in Composite Porous Media
Authors: Wu Yu-Shu , Pruess Karsten , Chen Z. X.
Published: June 2014

This paper presents a Buckley-Leverett-type analytical solution for one-dimensional immiscible displacement in a linear composite porous medium. The classical Buckley-Leverett theory, applicable only to flow in a homogeneous porous medium, has been extended to flow in an inhomogeneous porous medium, in which the formation system is treated as consisting of a number of flow domains with different rock properties. The analytical solution, obtained under the conditions for the Buckley-Leverett solution for each flow domain, can be used to determine the complete saturation profile in the composite system at all times. The analytical results indicate that noncapillary immiscible displacement of two fluids in a composite system is characterized by discontinuities in saturation profiles across the interfaces between adjacent flow domains.