bluuebunny/crossref_metadata_2025 huggingface dataset:
Reservoir Evaluation & Completion Optimization in Heavy Oil Sands with Dielectric & Diffusion Measurements
Authors: Ramos Y. , Chavez M. , Bustos U. , Decoster E.
Published: April 2012

Major heavy oil accumulations are found in the tertiary sandstones of the Lagunillas Formation of the Costanero Bolivar Field, located in Lake Maracaibo, Venezuela. The hydrocarbons are found in poorly consolidated shaly-deltaic sands, at depths of around 1200 ft to 2350 ft. The oil ranges from 10 to 18 degrees API, with viscosities ranging from 400 cP to 10000 cP. The formation water salinity is below 5000 ppm and variable within the reservoir, after years of injection of fresh water and steam to increase recovery. Consequently there is today no correlation between water cut and resistivity and the differenciation between oil and water with conventional petrophysical techniques is inaccurate. Conventional log analysis has limited potential since the resistivity shows identical values in both oil and water bearing levels.

Deciding on a completion strategy from an inaccurate saturation computation is a major challenge. Additionally, the free water presence reduces the net pay and rapidly increases the probability of water production in this high oil viscosity environment. Therefore an accurate assessment of free water and oil viscosity is a critical factor in the economics of the field. The present work incorporates dielectric and molecular diffusion measurements, showing significant progress in detecting free water from oil and defining the most prospective intervals.

Movable oil and fresh water are clearly identified using dielectric polarization at multiple frequencies. The dielectric measurement provides the water-filled porosity, while the magnetic resonance identifies the irreducible versus free water within that volume. This allows predicting the likelihood of producing hydrocarbon or water in areas with high oil saturation. In conclusion, the integration of dielectric polarization and diffusion information at multiple depths into the reservoir enable to distinguish oil from free and bound water and to estimate the oil viscosity, a result impossible to obtain with conventional logs in these environments. This integrated methodology allows accurate reservoir characterization and definition of the production potential of these heavy oil sands, leading to improved completion decisions.

The development campaign in Lagunillas sands now has a new workable technique to reduce uncertainties and to optimize heavy oil production.
Managing Risk in EOR Projects
Authors: Hite J. Roger , Blanton M. Lee , Kuhlman M. , Fair W.
Published: April 2012

Many companies, both international and national producers, are faced with the challenge of increasing reserves and production. Opportunities are often limited – enhanced oil recovery (EOR), gas shales, ultra-heavy oils, deep reservoirs and exploration - each with their own challenges. Understanding best practices in managing risk for EOR projects will facilitate using these processes to commercialize new resources in existing reservoirs.

The challenge for EOR is typically one of managing risk, so that investments can be made with an acceptable certainty of achieving the desired objectives. EOR is new to many organizations. It is frequently not well established in areas of interest. Performance histories are lacking. Support systems are weak. Training needs for engineers, operators and managers are high.

In this paper we recommend management and engineering design processes to manage technical and business risks. When followed, wasted time and money are minimized and the chances of success are increased.

There is a structured approach to developing technology in an efficient and cost effective manner and to bringing all stakeholders together as decisions are reached.
Unload Procedure with Control of Liquid Flow Rate Through Gas Lift Valve
Authors: Garcia Artur Posenato , Rosa Vinícius Ramos
Published: April 2012

Gas lift unloading is a transient process to lift well bore fluids and remove the liquid from the annulus (between tubing and casing). The field procedure developed in this work consists of finding the maximum allowable gas lift injection pressure during unloads. Its objective is to avoid erosion of gas lift valve by liquid flow rate and increase its service life. It was observed that the maximum injection pressure was not constant during the unload process. Two pressure gauges are required, one at the tubing and one at the casing (or gas lift flow line) since the pressures must be monitored during the unloading process. The liquid flow rate during its displacement is controlled by the gas lift injection choke.

The procedure was designed for offshore gas lift wells due to its high intervention costs to replace damaged valves by erosion. Damages in gas lift valves might decrease the maximum flow rate and cause production instabilities. This procedure can be equally applied to all gas lift wells that have at least two pressure gauges, one in the tubing and the other in the casing. The practice can only be applied in wells which have one single gas lift injection point.

Given that it is not possible to measure the liquid flow rate through gas lift valves in field applications, the procedure was validated against transient simulations. It was possible to observe a very good match with simulation results.

The Injectivity Index (II) could be used to calculate liquid flow rate through the gas lift valve. Unfortunately, the Injectivity Index is usually unavailable. Besides that, the production flow rate measurement is likewise sometimes unavailable during unloading. The procedure was developed to deal with these limitations. Other possible benefit is the optimization of unloading time by injecting the maximum liquid flow rate allowable.
Semi-Analytic Time-Domain Solution to Reservoir Models
Authors: Garcia Artur Posenato , de Souza Carvalho Renato
Published: April 2012

Analytic time-domain solutions are not possible even to some simple reservoir models, such as the finite radial model, which has a Laplace domain closed form solution. Several numerical inversion techniques of Laplace transform are available and find ready application for reservoir simulations. Stehfest is the most applied, however it leads to a purely numerical timedomain solution and all computational effort must be repeated for each required point of the response curve. This work develops a simple and efficient numerical inversion technique that leads to an explicit time-domain solution. The idea is to select a transfer function Gn(s) having an explicit inverse and evaluate its parameters by a curve fitting technique (Weighted Least Squares) with the impulse response of the reservoir model in the Laplace domain. The explicit function gn(t) obtained provides an accurate approximation for the impulse response. As we are usually interested in the step response, the function gn(t) still needs to be integrated in time and we find another analytical function for the step response.

Any reservoir model which can be described in the Laplace domain by a combination of Bessel functions that is impossible to by analytically inverted is suitable to this method.

The first test consisted of matching the results of this semi-analytic method with a model which has an analytic time-domain solution. The infinite reservoir model was approximated by a semi-analytic solution and the time-domain response was compared with the integral exponential solution. Next, the finite reservoir model was approximated by the same semi-analytic function of the infinite reservoir but with different coefficients. The time domain response was compared with the Stehfest inversion algorithm and results showed good agreement.

A method of numerical inversion of Laplace domain solutions is described in which the problem is converted to the solution of linear systems. It leads to a series of explicit equations for the time domain that reasonably matches with the traditional Stehfest inversion algorithm. The semi-analytic reservoir model can be applied to reservoirs in which the quality of the information does not warrant the use of a more sophisticated model.
A Thorough Diagnostics-Solution Approach to Increase the Recovery Factor from Horizontal Wells in Complex Dolomites
Authors: Fouchardiere Benoit de , Sapon Ronaldo , Valencia Diana , Guatemala Perenco , Aviles Rodrigo , Flores Jose G. , Resendiz Tadeo , Roman Igork San , Quevedo Manuel A. , Davila Luis E. , Vaquer Luis , Paz Alvaro
Published: April 2012

Xan is Guatemala's largest oil field, accounting for more than 90% of the country's production. Xan produces from a complex dolomite reservoir at average rates of 10,500 BOPD, with most of the production coming from 8 horizontal wells with typical open-hole completion lengths of 1,500 ft. The majority of the horizontal wells at Xan do not produce at their fullest potential because of near wellbore damage, associated to drilling fluid residues, and problems related to the high production of water, averaging 90% water cut at the field level.

This paper presents an innovative approach combining diagnostics supported with fiber optics distributed temperature survey data feedback and matrix stimulation systems, tailored to address specific needs, including viscous-highly retarded emulsified acid systems, multifunctional solvents, and surfactant visco-elastic diverting agents, all deployed through coiled tubing to remove the damage and maximize the treatment penetration in the reservoir. The solution was tested in two horizontal wells with severe formation damage and water production problems. The use of coiled-tubing deployed fiber optics facilitated monitoring and evaluating the stimulation treatments and fluids behavior in realtime, by capturing a sequence of temperature profiles and temperature responses to the acid injection at different times through the treatment. As a result, zonal coverage and effectiveness of the stimulation and diversion systems could be quantified as the treatment was pumped; allowing optimization of the stimulation program and pumping variables to accommodate to the actual well's response.

Production results have been outstanding, oil production increased by 54% from the two horizontal wells, which is equivalent to the production of a brand-new development well in this field, at a much lower cost. The diagnostics-solution approach developed for this reservoir helped accurately diagnosing the problem and implementing a fit-for-purpose stimulation treatment that actually improved oil production. The proposed methodology has substantially changed the process of stimulating horizontal sections in the Peten basin of Guatemala.
Oil Reserves Positive Adjustment of the Middle Eocene Calcarenites Reservoir Through a Correct Interpretation of the Oil/Water Contact: Ku Maloob Zaap Fields, Mexico
Authors: Angeles J. , Del Angel J. G. , Lopez M. C.
Published: April 2012

The middle Eocene calcarenites from the Ku, Maloob and Zaap fields are formed by packstone-wackstone limestones of high porosity; 20%, permeability between 10 and 400 md and low shale content. They are formations with excellent petrophysical quality. The core data contains the following fossils groups: Globorotalia lenheri, Globorotalia spinulosa, Truncorotaloides rohri, Lepidocyclina antillea, Porticulasphaera Mexicana; wich all are representative of the Middle Eocene. There is also Wackestone and Mudstones textures and few illyte mineral precence. It presents a lowstand slope fan deposit. The area is limited by the ausence of the Calcarenite rocks and sismic interpretation, their vertical limit are the silicate rocks of the same age.

The fields are pressure connected through a common aquifer. Within an open and connected system, with a normal hydraulic gradient, very close to 0.11 kg/cm2/m. The lower limits for the three fields are located at very close depth: 2720 TVDSS for Ku field, to 2710 TVDSS for Zaap field and 2750 TVDSS for Maloob.The oil production in the Middle Eocene Calcarenites reservoir (CCE) began in 1986 with the well Ku-10, which produces 17 ° API oil with viscosity of 8.5 cp. In previous studies

The objective of the present study was to correctly identify the depth of the fluid contacts, which directly impacts on the reserves and increased the original volume of hydrocarbons; since the oil water contact was located about 200m deeper the original oil in place increased 200%. Also it rules out the possibility of compartments from previous studies.
Gas Coning and Channeling Management in Naturally Fractured Reservoirs with Applications to the Akal-Cantarell Field
Authors: la Garza F. Rodríguez-de , Ortega-Galindo R. , Garcia-Pietri E.
Published: April 2012

A strategy to manage and control gas coning problems in the Akal-Cantarell field, based on correlations developed by extensive single-well dual porosity numerical modeling of gas coning phenomena, is presented in this paper. Attention was given to the range of reservoir parameters and production conditions that were found relevant to and representative of the Akal field. The effect of high permeability channels, left behind in the casing by improper cementation, on the evolution of gas coning was also analyzed.

It was found that the main variables that govern gas coning and channeling phenomena in the naturally fractured Akal field are: the effective permeability of fractures, Kf, oil production rate, qo, and the distance between the gas-oil contact and the perforations at gas breakthrough, Dzcp. A range of qo and Kf values, characteristic of the Akal field, was considered. For each pair of qo and Kf values, the distance between the gas-oil contact and perforations, Dzcp, at which the gas cone breaks into the well, was determined. A log-log graph of Dzcp versus qo, for given Kf value, resulted in a straight line for both coning and channeling phenomena.

Correlations developed for Dzcp as a function of qo and Kf as well as those developed to determine the times required for gas cones to dissolve, when the well is shut-in or choked, were used to define a production strategy to maximize the life of wells and optimize production. A field application is presented.
Use of Liner Drilling Technology to Ensure Proper Liner Setting: A Mexico Case Study
Authors: Belloso A. , Scott J. , Rivera J. M. , Piña J. , García J. V. , Mendez J. C. , Robles J. L.
Published: April 2012

Historically, wells drilled in the on offshore fields located on the bay of Campeche in Mexico face severe fluid losses and hole instability caused by the drastic lithology changes when drilling the Paleocene formation before entering the BTPKS formation (Breccia). Conventional drilling, even though slow and problematic, has been able to drill the interval in this particular environment.

Advances in liner drilling technologies have provided better solutions to the challenges of drilling wells where conventional drilling may not lead to optimal results. Three wells in Mexico used liner drilling technology to drill with a 7-in. liner through the Upper Paleocene, the calcareous body and the Lower Paleocene. The main objective was to isolate the shale/clay body and to enable setting the liner at the top of the BTPKS FM (Breccia), making it possible to drill the next section with sea water.

This paper will discuss the three cases where liner drilling was applied. We will cover the planning process, project analysis, operational problems faced and results. Using this technology has made it possible to: manage equivalent circulation density (ECD) to avoid inducing circulation loss; successfully isolate the shale/clay body; drill through the calcareous body; set liner in the Lower Paleocene; successfully cement the liner; and recover the running tool without setbacks.
Simulation of Intermittent Gas-Bubbly Oil Three Phase Flow in Upward Vertical Pipe Using the Two-Fluid Model
Authors: Cazarez-Candia O. , Montoya-Hernández D. J. , Bannwart A. C.
Published: April 2012

In the petroleum industry the heavy oil-gas-water three phase flow is present in both, on-shore and offshore pipelines. The adequate predictions of three-phase flow characteristics, such as flow patterns, pressure drop and holdup, can have significant impact on the proper design and operation of pipelines and on many flow assurance issues. To achieve this, experimental work and a rigorous modeling of three-phase flow must be carried out.

When water, heavy oil and gas flow simultaneously through experimental vertical pipes, in such a way that water is the continuous phase, the Intermittent gas-Bubbly oil (Ig-Bo) flow pattern may appear. In this work a one-dimensional, thermal, transient, two-fluid, mathematical model for Ig-Bo flow is presented. The model was developed under the hypothesis that the Ig-Bo flow pattern can be approached by two different flow patterns, each one in neighboring regions: heavy oil-water bubbly flow in an annular region and heavy oil-gas-water bubbly flow in a slug region. The model consists of mass, momentum and energy conservation equations for every phase whose numerical solution is based on the finite difference technique in implicit scheme. The model is able to predict pressure, temperature, volumetric fraction and velocity profiles for each phase. The ratio between the liquid-slug length and the slug-unit length (Λ2), commonly used in two-phase flow, was modified to take into account the presence of heavy oil. It was observed that (Λ2) is larger than the two-phase flow and the correlation allow having the best predictions. The predictions are in agreement with experimental data reported in literature.
Modeling Multiple-Porosity Transport in Gas-Bearing Shale Formations
Authors: Hudson John , Civan Faruk , Michel-Villazon Guillermo , Devegowda Deepak , Sigal Richard
Published: April 2012

Gas-bearing shales are characterized by pore systems that are present in the organic (kerogen) matrix, inorganic matrix, natural fractures, and induced fractures. Each pore system has different physical properties. The organic matrix essentially has gas-wet nanopores with adsorptive properties. The inorganic matrix is an ultra-low permeability matrix that is most likely water-wet but could have more complex wettability. Two alternative but complementary approaches, namely a lumped tank model and a continuum model, for describing gas transport in shale are developed and their capabilities are demonstrated by various applications. Our continuum approach describes gas transport in a manner analogous to the methods employed by commercial simulators. The model is discretized and petrophysical and fluid parameters incorporated into the model that may then be calibrated to obtain a history match. Often, this process leads to non-uniqueness in the match because the number of observations is likely to be smaller than the number of parameters to be resolved. Our lumped tank approach treats the porosity systems within shales as tanks interacting with each other such that relevant physical phenomena, such as adsorption, are described by rate equations. Calibration of this model to production data enables the quantification of grouped parameters and not necessarily the individual storage- and transport-related parameters, thereby reducing the severity of the non-uniqueness of the history matching process. Several case studies conducted exclusively delineate the advantages and disadvantages of both approaches in shale-gas production analysis and simulation. Comparisons between the tank model and the continuum approach for different case studies show good matches within an acceptable measure of tolerance. Reservoir parameters determined from the tank approach are compared with the values used in the continuum approach. The new models are shown to accommodate the inherent complexities of transport processes occurring in shale-gas reservoirs.
Experimental Study of Gel Particles Transport Through Porous Media
Authors: Al-Ibadi A.. , Civan F..
Published: April 2012

Conditions leading to plugging in weak or highly permeable formations and the resulting permeability impairment occurring during flow of suspensions of deformable gel particles are investigated by core flow tests. Effect of concentration, flow rate, and particle diameter of gel particle suspensions on the relevant pore plugging processes is studied. Effective impairment and trapping mechanisms are identified under various conditions by means of the diagnostic equations. Appropriate dimensionless groups are used to develop empirical correlations of experimental data. This reveals valuable information about the functional trends of porous media plugging by gel particle suspensions which is essential for successful mitigation of formation plugging in the field.
Closure of Natural Fractures Caused by Increased Effective Stress, A Case Study: Reservoir Robore III, Bulo Bulo Field, Bolivia
Authors: Vega Navarro O. G.
Published: April 2012

The gas condensate reservoir Robore III, in the Bulo Bulo field, is comprised by a set of naturally fractured, interbedded shales and sandstones. Recently, this reservoir observed a notorious reduction of its gas reserves and production rates. This reduction in reserves was found to be caused by the geomechanical effect of collapse/closure of its natural fractures. The effect was generated by the sudden increase of effective stress upon the formation. This publication documents the study and investigation of such phenomenon based on core analysis studies, pressure measurements and production data.

Sustained gas production and pressure decline lead to closure of natural fractures as both increase the effective stress and confinement pressure. Consider the fracture network lacks the sufficient natural support agent to counteract increasing pressure, it eventually collapses altering the reservoir quality in the near wellbore region and turning it into a simple matrix permeability reservoir with very low magnitudes of measured permeability (0.001 – 0.01 md). As a consequence, production is severely diminished or even lost.

The present study is the first of its kind in Bolivia as it documents the complete production shut down of a naturally fractured reservoir caused by this phenomenon. A large amount of reserves are stored in gas reservoirs with similar conditions to those observed at the Robore III reservoir, not only in Bolivia but also in the Latin-America region. This peculiarity gives a special significance to this matter. The effect has to be considered in this type of reservoirs when performing reserves estimations, investment decisions or gas production forecasts for contractual matters.

The present study is strongly based on production data from wells BBL-11 and BBL-9D, wellhead and bottomhole pressure information from all completed wells at the reservoir of study and a detailed core analysis report for samples taken form well BBL-11, at depths corresponding to the Robore III reservoir.

After two years of building up pressure, well BBL-11 was opened and its wellhead pressure measured. Pressure was found higher than normal pressure gradient and it was concluded that gas moved into the depleted zone, building pressure up as a result. This well is showing again a steep wellhead pressure and bottomhole pressure decline, as fractures are closing again. Recently drilled well BBL-10 is also showing a steep decline on wellhead pressure. This well is still productive due to reservoir pressure was found to be higher than the normal gradient in this zone and because the fracture network are not yet closing.
Streamlines Simulation of Polymer Slugs Injection in Petroleum Reservoirs
Authors: Vicente B. J. , Priimenko V. I. , Pires A. P.
Published: April 2012

The injection of polymer solutions is an effective method of Enhanced Oil Recovery. However, the continuous injection may be very expensive, and the injection of slugs is an alternative to improve the recovery factor. In this paper, streamlines simulation is used to model the 2D 2-phase oil displacement by polymer slugs, considering adsorption effects.

Streamline simulation can be much faster than conventional finite difference models and its results may be used for slug polymer injection optimization in heterogeneous reservoirs. It decouples the 2D problem into multiple 1D problems along streamlines. The mass transport equations in the streamlines are solved analytically. The continuous polymer injection is a Riemann problem and its solution is self-similar, but in the case of slug injection, there are interactions between waves of different families. We analyze the results for several adsorption isotherms, like Henry and Langmuir.

Analytical solutions are free from numerical diffusion, and allow the choice of greater time steps. The simulations were run in 2D incompressible models without gravity effects. Results obtained were compared with finite difference simulation. The analytical solutions along streamlines allowed the exact modeling of shock and rarefaction waves as well as the interaction between waves of same and different families. Sensitivity analysis was performed regarding the technique adopted for the cell concentration and saturation determination between time steps.
Importance of Distributed Temperature Sensor (DTS) Data for SAGD Reservoir Characterization and History Matching within Ensemble Kalman Filter (EnKF) Framework
Authors: Panwar A. , Trivedi J. J. , Nejadi Siavash
Published: April 2012

Distributed Temperature Sensing (DTS), an optical fiber downhole monitoring technique, provides a continuous and permanent well temperature profile. In SAGD reservoirs, the DTS plays an important role to provide depth- and- time continuous temperature measurement for steam management and production optimization. These temperature observations provide useful information for reservoir characterization and shale detection in SAGD reservoirs. However, use of these massive data for automated SAGD reservoir characterization has not been investigated. The Ensemble Kalman Filter (EnKF), a parameter estimation approach using these real-time temperature observations, provides a highly attractive algorithm for automatic history matching and quantitative reservoir characterization.

Due to its complex geological nature, the shale barrier exhibits as a different facies in Sandstone reservoirs. In such reservoirs, due to non-Gaussian distributions, the traditional EnKF underestimate the uncertainty and fails to obtain a good production data match. We implemented discrete cosine transform (DCT) to parameterize the facies labels with EnKF. Furthermore, to capture geologically meaningful and realistic facies distribution in conjunction with matching observed data, we included fiber-optic sensor temperature data.

Several case studies with different facies distribution and well configurations were conducted. In order to investigate the effect of temperature observations on SAGD reservoir characterization, the number of DTS observations and their locations were varied for each study. The qualities of the history-matched models were assessed by comparing the facies maps, facies distribution, and the Root Mean Square Error (RMSE) of the predicted data mismatch.

Use of temperature data in conjunction with production data demonstrated significant improvement in facies detection and reduced uncertainty for SAGD reservoirs. The RMSE of the predicted data is also improved. The results indicate that the assimilation of DTS data from nearby steam chamber location has a significant potential in significant reduction of uncertainty in steam chamber propagation and production forecast.
Can Injection of Low Temperature Air-Solvent LTASI Be a Solution for Heavy Oil Recovery in Deep Naturally Fractured Reservoirs?
Authors: Mayorquin-Ruiz Jose Ramon , Babadagli Tayfun
Published: April 2012

Heterogeneity and depth rule out steam injection and in-situ combustion processes for heavy-oil recovery in deep naturally fractured reservoirs (NFR). Once it is controlled by a proper injection scheme and the consumption of air injected through efficient diffusion into the matrix, low temperature air injection (LTAI) can be an alternative technique for heavy-oil recovery from deep NFRs.

Limited studies on light oils showed that this process was strongly dependent on an oxygen diffusion coefficient and matrix permeability, both of which are typically low. A new approach, i.e., the addition of hydrocarbon solvent gases into air is expected to improve the diffusivity of the gas mixture and to accelerate the oxidation reaction to breakdown asphaltenic molecules effectively. This improves the gravity drainage recovery from the matrix. To study this new idea called low temperature air-solvent injection (LTASI), laboratory tests were performed by immersing heavy-oil saturated cores into air¬ solvent filled reactors to determine the critical parameters on recovery, diffusion coefficient, oxidation kinetics, viscosity reduction, and gravity drainage rate.

It is imperative that enough time is given for the diffusion process before injected air filling to fracture network breakthrough. This implies that huff and puff injection is an option as opposed to the continuous injection of air. A high recovery factor was obtained by soaking a single matrix in an air-solvent chamber at static conditions rather than with air only. The period of pressure stabilization was faster for the air-solvent mixture atmosphere than in 100% solvent. The asphaltene content was lowered more in the air-solvent chamber than in a 100% air case.
The Impact of the Injection Water Chemistry on Oil Recovery from Carbonate Reservoirs
Authors: Yousef Ali A. , Al-Saleh Salah , Al-Jawfi Mohammed
Published: April 2012

Improved/enhanced oil recovery by tuning the ionic composition of the injection water is currently deemed as new emerging recovery method. In the recent years, extensive research on oil/brine/rock systems has shown that injection low salinity brines in sandstone reservoirs has a significant impact on the amount of oil recovered. Although, the potential for carbonates has not been thoroughly investigated, some reported studies have excluded carbonates from this effect.

Based on the research work in the last years, we demonstrated in a previous reports (137634; SPEREE Journal, vol. 14(5), pp. 578-593, SPE 143550, SPE 141082) that substantial oil recovery beyond conventional waterflooding from carbonates can be achieved by optimizing the salinity and ionic composition of field injection brine. Also, research confirmed that the main cause for the substantial increase in oil recovery is wettability alteration of carbonate rock surface.

This paper highlights extensive and a broad range of laboratory studies including wettability, surface chemistry, and zeta potential studies to define the role of water ions in the induced wettability alteration, which is crucial in determining the optimum composition of injection water for future field applications.

The rock surface chemistry studies identified the potential mechanisms for wettability alteration triggered by injecting chemistry-optimized field injection water. The contact angle results confirmed that a sufficient reduction in the ionic strength of field injection water is required to trigger the effect of wettability alteration. Zeta potential measurements successfully addressed the impact of multivalent ions on rock surface charges. All evidence gathered during this research work indicates that interplay of water ions is important factor in this new recovery method.
Thermal Development of Thick Heavy Oil Fields: Phase II Development Options, Challenges and Solutions
Authors: Al-Hinai S. M. , Van Wunnik J. N. , Thum M. , Brissenden S. J. , Mukmin M. , Nofli S. , Rabaani A. , Strauss J. P. , Al-Breiki M.
Published: April 2012

A number of thermal developments are currently in execution in Oman. Two of these are located in South Oman and contain an exceptionally thick column (200m+) of heavy oil (200 to 400,000 cp) in Cambrian reservoirs at a depth of 1050 m below surface, underlain by a moderately strong aquifer. One of the fields has been in production for 20 years, the main production mechanisms are pressure depletion and natural ingress of aquifer water, while the other field has only produced a small amount by cyclic steam stimulation (CSS) trials due to the high viscosity of its heavy oil. For the next phase of development a vertical well pattern re-development is planned which will increase the ultimate recovery significantly, through a combination of cold production, CSS and steam flooding.

The thickness of these reservoirs is unusually large for steamflooding and this poses both opportunities and challenges. There are no direct analogues and the industry practices of managing a steamflood in this specific setting is yet to be verified. Phase I deliberately addresses only the upper parts of the reservoirs while significant volumes are still to be matured in a future Phase II development. Following some higher level screening work of recovery mechanisms, the realistic development options for Phase II are innovative application of further steam flooding. Subsurface uncertainties are actively managed by different means; among them are the steam injection trials and steam pilot. The full field developments planned to start-up with Phase I in 2012 followed by Phase II in 2017.

The paper will provide an overview of the proposed Phase II thermal development and specifically the innovative way development challenges are addressed. The integrated modeling work that yielded a better design of well completion strategies will be discussed. Additional topics addressed include minimising additional gas requirements through application of co-generation of electricity and steam (COGEN), water management and overall integrated project management.
Challenges and Risk Management Strategy for Enhanced Oil Recovery Projects in Carbonate Reservoirs of a Giant Field in Middle East
Authors: Choudhary Muhammad A. , Wani Mohamad R. , Al-Mahmeed Ali , Al-Rashidi Hussain
Published: April 2012

Late Cretaceous – Early Tertiary carbonate reservoirs of the giant Wafra Field, located in the Kuwait - Saudi Arabia Divided Zone, hold huge resource of heavy oil in 3 reservoirs, namely 1st Eocene, 2nd Eocene, and Maastrichtian. More than 50 years of primary production from these high porosity, moderate permeability carbonates has recovered less than 5% of this volume and the ultimate recovery is not expected to exceed 10%. Low primary recovery is attributed to oil gravity, viscosity and drive mechanism. Suitable EOR technology is needed to unlock these huge resources. In absence of any commercial analogs, application of EOR technology carries enormous risks in terms of technical viability, reserves recovery and resources commitment. Proper understanding of the reservoir and optimization of EOR technology are essential to mitigate these risks to a manageable level.

This paper will discuss the process used to meet various challenges and mitigate risks of EOR application in 1st and 2nd Eocene reservoirs through exhaustive screening studies, pilot projects and testing innovative technologies. Detailed screening study suggested the suitability of steamflood for 1st Eocene and both waterflood and steamflood for the deeper 2nd Eocene reservoir. Both projects have serious challenges due to reservoir nature, uncertainty in reservoir characterization, non-availability of fresh water, lack of proven technology for processing produced water for steam generation, disposal of excess produced water, fuel for steam generation, and safe environment for workers, public and wild life. These challenges make the EOR projects very high risk ventures. These risks are being managed through extensive G&G and simulation studies, exhaustive screening work and properly designed pilot projects. Five pilot projects are under implementation to resolve the number of uncertainties and manage associated risks in the high reward EOR process for these reservoirs.

This paper will share the strategy, work flow, uncertainty management and risk mitigation plan for these pilot projects and innovative technology being tested to manage challenges in full field application of EOR in carbonate reservoirs. Sharing of processes and innovative technology with industry will lead to success in mitigation of risks in EOR projects in carbonate reservoirs.
Numerical Simulation of Surfactant-Polymer Coreflooding Experiments for Carbonates
Authors: AlSofi Abdulkareem M , Liu Jim S , Han Ming
Published: April 2012

Surfactant/polymer (SP) flooding is of particular interest in recent years due to its synergetic effects of interfacial tension reduction and mobility control with minimal side effects. This work focuses on constructing an SP simulation model using laboratory data and validating it by matching coreflooding results. A series of SP coreflooding experiments were performed in carbonate cores under reservoir conditions. Chemical injection was implemented in tertiary mode with varying slug sizes and concentrations. The coreflooding results show significant oil recovery potential for SP formulations under the conditions investigated. The base SP flood resulted in 23.4% incremental recovery after waterflooding with the polymer and surfactant contributions being about the same. The results also demonstrate the effects of surfactant slug-size and concentration on the recovery performance. Using UTCHEM the input parameters, necessary to predict incremental recoveries, were investigated. A general SP simulation model was initiated, in which: polymer viscosity dependence on concentration and salinity were established in the laboratory; surfactant phase behavior parameters were generated from test-tube results; and oil desaturation was based on additional coreflooding. After matching water and polymer flooding results, the surfactant simulation model was tuned through history matching the performance of a series of SP corefloods. A subsequent sensitivity analysis establishes the confidence level of the input parameters. The sensitivity analysis also highlights the significance of IFT reduction. Finally, we numerically investigated the optimum chemical formulation. Optimization runs were performed under a fixed chemical consumption condition. The results support the optimality of previously selected slug sizes while suggesting the potential benefit of increasing the polymer: surfactant concentration ratio. In summary, this work provides a predictive SP simulation model that can be used to upscale laboratory results to field-scale predictions.
Viscosifying Surfactant Technology for Chemical EOR: A Reservoir Case
Authors: Degré G. , Morvan M. , Beaumont J. , Colin A. , Dupuis G. , Zaitoun A. , Al-Maamari R. S. , Al-Hashmi A. R. , Al-Sharji H. H.
Published: April 2012

Recent publications indicate that the injection of polymer solutions at concentrations larger than those conventionally used in polymer flooding can result in higher recovery at field scale. Typically, oil recovery more than 20% OOIP compared to waterflooding using these polymer solutions has been reported (Wang et al; 2011). However, injectivity issues have to be considered when injecting such concentrated polymer solutions. This study describes an alternative approach based on surfactant-based solutions. The technology has been developed to match the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity) without any injectivity limitations even when considering very viscous surfactant solutions (i.e. up to 1000 cps) and low permeability cores.

Average first normal stress difference measurements have been used to compare the elastic properties of surfactant and high-molecular-weight polymer solutions. The degree of non-linearity in the mechanical properties for both solutions has been expressed by Weissenberg number. The surfactant solution has much higher Weissenberg number than the polymer solution at a shear rate corresponding to the fluid propagation in the reservoir, which indicates higher elasiticily of these surfactant solutions.

The potential of this surfactant-based technology is illustrated through a specific reservoir case involving heavy oil. A series of coreflood experiments has been performed in reservoir cores at reservoir conditions. The surfactant slug can be combined with a conventional low-concentration polymer flooding to further improve the process. Reduction in residual oil saturation in the range of 10 to 15% has been obtained. Complementary simulation study giving rise to economic analysis have been performed.
The Integration of Miscible Gas Injection in Oil Reservoirs with the Development of a Sour Gas Condensate Field
Authors: Vissers J. M. , Alkindi Abdullah , Hassan A
Published: April 2012

This paper describes the integration of the development of a number of oil reservoirs by means of miscible gas injection with the development of a gas condensate field.

Around the year 2000 a number of oil reservoirs were discovered in south Oman. Material Balance calculations and early performance data confirmed the geological predictions that little or no aquifer support was to be expected from those reservoirs. Recovery factors based on primary depletion are limited to about 10%, and to boost recovery miscible gas injection (MGI) was identified as the most promising technique.

The gas needed for such miscible gas flood was found in the presence of a gas condensate field located nearby. The gas contains about 15% CO2 and 3% H2S and is considered a sour gas development. Originally the gas-condensate field was scheduled for stand-alone development, with gas sweetening and re-injection of the waste stream, containing about 70% CO2 and 30% H2S, to maximize condensate recovery. The integration of the gas and oil development offered an additional sink for the waste gas, as this could now be used for MGI.

To optimize the development, in terms of maximizing the Ultimate Recovery, a fully compositional model, integrating the 3D subsurface modeling and surface network, was constructed. The model was used to determine the best strategy for the MGI development of the portfolio of oil reservoirs, assess the impact of sour gas injection in those oil fields on existing production facilities, and select the optimum gas offtake from the gas field.

The integrated modeling enabled the selection of a development concept that maximizes the UR of the Oil and Gas fields, ensures the Gas sales commitments, while making maximum use of the existing facilities, thereby maximizing the monetary value of the project.
1D Asphaltene Deposition Simulator for Reservoir Fluids Undergoing Gas Injection
Authors: Pedersen Karen Schou , Shaikh Jawad Azeem , Rasmussen Claus P.
Published: April 2012

CO2 and hydrocarbon gas injection are interesting Enhanced Oil Recovery (EOR) techniques for oil reservoirs. Gas injection may initiate asphaltene precipitation in a reservoir. 1D compositional CO2 gas injection simulations have been conducted to find out where asphaltenes will precipitate and deposit. It was found that asphaltenes will precipitate in the transition zone between injection gas and oil. This transition zone will move forward continuously and no accumulation of asphaltene deposit will take place. Though deposited asphaltenes locally will plug reservoir pores and decrease permeability, this is unlikely to affect the oil recovery. The mobility of the gas and oil phases is high in the gas-oil transition zone where asphaltenes precipitate, and those high mobile phases will manage to bypass a small volume fraction of deposited asphaltenes. With an asphaltene phase present in addition to gas and oil the classical definition of a miscible gas drive cannot be fulfilled. Miscibility can however develop between an injection gas and an oil phase, which through contact with gas has been stripped for asphaltene components.
Single Well Chemical Tracer Tests - Fast and Accurate Simulations
Authors: Huseby Olaf , Sagen Jan , Dugstad Øyvind
Published: April 2012

In EOR-operations, the single-well chemical tracer test (SWCTT) has been proven as a secure and stable methodology for measuring oil saturation prior to and after application of EOR-measures. SWCTTs can be used to measure residual oil saturation in a near-well region up to about 10 m from the wellbore, and has been used in several hundred studies, in particular in the US. Current simulation of SWCTT requires a reactive transport modelling tool that allows for a hydrolysis reaction involving four chemical compounds, in addition to other chemical tracers used in specific tests. Today compositional reservoir simulators are usually applied to simulate SWCTTs.

In this paper we show that the SWCTT modelling can be made much simpler, without compromising a correct description of the reactive transport process. The formulation of the solution exploits the fundamental assumption that tracers do not affect the phase transport. A fast post-processing tracer simulation technique is introduced to solve single well tracer transport in real-life reservoir cases. The partitioning and reactions of the tracer components is solved fully coupled with the tracer transport, and partitioning between phases is described by a convenient formulation and the ester hydrolysis reaction is modelled in an efficient manner. The post-processing is based on previously solved reservoir simulation runs and gives significant savings in CPU-time.

Using an experimental case and one field case, we demonstrate the practical improvement achieved by the new method, and investigate effects of numerical smearing. Our main conclusion is that the formulation is important to enhance correct evaluation of SWCTT results.
Wettability and Oil Recovery by Low Salinity Injection
Authors: Shiran Behruz Shaker , Skauge Arne
Published: April 2012

Low salinity has been studied extensively, but still the mechanisms for improved oil recovery by lowering brine salinity are unsolved. The target of this paper was to address this problem and make systematic studies that can give insight to the key mechanisms. Given the variety of conditions under which increased recovery by low salinity brine injection may or may not be observed, it is likely that more than one mechanism is contributing to the observed oil recovery. The mechanisms most claimed to be the reason for improved oil recovery are shift in wettability, multi-component ion exchange, and dissolution/fines migration.

In this paper, we have studied low salinity waterflood by systematic changing the rock wettability. The wettability is changed by varying aging with crude oil at elevated temperature. We are investigating how aging time effect affects core analysis properties like; spontaneous imbibition, Amott-Harvey and USBM wettability oil and water indices. The wetting properties were also cross-checked by NMR.

The detailed core analysis is the background for study of oil recovery by seawater injection and subsequent lowering of salinity. In addition to detecting trends of initial wetting and the potential for low salinity, all mechanisms for low salinity recovery are discussed. It is expected from the literature that the clay content in Berea cores favors oil recovery by low salinity waterflooding, however the more oil wet character of the Bentheimer cores in this study, seems more important for improved oil recovery by low salinity waterflood.