bluuebunny/crossref_metadata_2025 huggingface dataset:
Initial Deployment of a New Design One-Trip Straddle System Resolves High Pressure Cross-Flow Problem in Water Injection Well in Algeria
Authors: Addoun M. , Maraf K. , Tighe M. , Bramwell J. , Snaas A.
Published: September 2011

The Ourhoud Field is located in Eastern Algeria and has some 60 producing wells with average production of approximately 600 m3/d/well (3,750 bopd/well). Pressure maintenance and production drive is provided by means of water injection at a total rate of some 55,000 m3/d (345,000 bwpd), and gas injection at 106 mmscfd. One water injection well provided problems to the continued effectiveness of the water injection program, because a thin isolated layer was acting as a thief zone taking some 30% of the injected water. When injection was shut down, the zone would crossflow into the zones above and below it at a rate of some 550 m3/d (3,460 bwpd). In order to correct this problem a straddle system was needed to shut-off this zone, allowing all of the injected water to enter the two desired layers thereby increasing both the volume displaced into these layers and the production rate of surrounding wells.

After a detailed review of available straddle options to shut-off the zone in the 7″ monobore completion, it was decided that a single trip system would provide the best chance of success by reducing the number of well entries required, the installation time, and the likelihood that continued shut-in cross-flow would have an adverse effect on a conventional two-trip straddle installation due to the protracted operation time. The chosen one-trip straddle (to set and retrieve) was a newly designed tool which had a model available in the required 7″ size that had undergone rigorous testing, but had not yet been used in the field. After extensive review of the design and testing of the tool, and evaluation of the risks associated with deploying a new design straddle against the advantages of a single trip installation, it was decided to run the first 7″ one-trip straddle on electric line in the well. In this paper the authors will review the well specifics, the design and operation of the single trip straddle, and the decision making process which resulted in its first installation. They will go on to describe the installation process in detail, and review the positive results achieved by the successful shut-off of the cross-flow situation.
Determination of Optimum N2 Rate for Unloading Gas Wells With Coiled Tubing
Authors: Zhou Y. , Smalley E. , Opel S.
Published: September 2011

Unloading gas wells with nitrogen (N2) is one of the most common applications of coiled tubing (CT). The unique feature of CT unloading, as compared to conventional gas lift, is that the gas injection depth can be changed continuously. Despite the large number of CT unloading jobs performed annually, the fundamental and frequently-asked questions such as optimum N2 rate and optimum gas injection depth as well as CT run into hole (RIH) speed remain. There are no simple and efficient methods that can be used to calculate these design parameters.

Unloading a water-loaded gas well with N2 and CT is a dynamic and transient hydraulic process. Before a gas well is significantly unloaded and the bottomhole pressure (BHP) is reduced significantly below the reservoir pressure, the effect of the reservoir on the unloading process can be neglected. As far as the simulation of multiphase annulus flow is concerned, the liquid phase comes solely from the original liquid that loads the well. This paper presents a simulation study focused on the main factors that affect the hydraulic behavior of the CT unloading process. The optimum N2 pump rate is determined based on the criterion of minimum BHP. Simulation results indicate that as N2 rate increases, the hydrostatic pressure in the annulus and BHP decrease significantly. However, further increase of the N2 rate beyond a certain threshold value would increase the friction pressure loss in the annulus and consequently increase the BHP, especially for gas wells where the CT/tubing or CT/casing clearance is small. It is found that as gas injection depth increases, the minimum achievable bottomhole pressure is decreased. Simulation results also indicate that for smaller wellbores where annular friction loss is a limiting factor, a smaller diameter coiled tubing string may be preferred. The challenges associated with liquid unloading in large and deviated wellbores are also discussed.
Automated Direct Fired N2 Vaporizer
Authors: Pugh T. , Roberts J.
Published: September 2011

This paper describes a Direct Fired Liquid Nitrogen Vaporizer Automation System (LN2 Vaporizer Automation) and the control equipment and techniques associated therein. This system has been developed over the last two years and has proven capable of controlling the discharge temperature of discharged nitrogen gas, across a broad range of rates and pressures in a wide range of ambient conditions, while controlling pollutants from the burner and providing for enhanced safety and reliability.

The key components of the system are:

a. Typical Direct Fired Liquid Nitrogen (LN2) Vaporizer System

b. A Program Logic Controller (PLC) with attached sensors and actuators

c. A Human Machine Interface (HMI) to allow for interaction with the system

The trials and jobs carried out to date are also briefly described in this paper, together with the current perceived strengths and weaknesses of the system.
Development of a Laser Scan Inspection Tool for Coiled Tubing
Authors: Kilambi S. , Tipton S. M.
Published: September 2011

Coiled tubing (CT) is used extensively in oil field applications where it can incur surface defects and imperfections. Fatigue cracks can nucleate prematurely from the surface flaws and reduce fatigue lives significantly. The influence of defects on fatigue life can only be assessed if accurate measurements of the defect geometry are available. Current CT inspection technology is based on magnetic flux leakage (MFL) which is useful in detecting flaws. But, MFL is incapable of quantifying defect geometry information. On the other hand, laser scanning inspection systems can provide direct measurements of the physical characteristics of surface flaws. This technology produces a set of 3D data points that represent a complete surface map of a flaw. Laser scan data have been successfully curve fit using a proven Taubin algebraic fit. With this basis, algorithms for determining critical defect parameters namely, defect depth, width, length, and projected cross-sectional area were developed. The results are within the specified accuracy of the laser scanner. The notch root radius can be estimated by curve fitting the flaw geometry at the root of the notch. The success of obtaining notch root radius depends on density of laser-scan data and absence of shadow effects. A laser scan system with lower incidence of shadow effects will further improve the effectiveness of a laser scanner inspection tool. This technology has tremendous potential as a general purpose inspection tool for oil field piping systems.
Comparison of Tracer Test Result and Analysis of Connectivity Injector and Producer during Pilot Waterflood Kenali Asam Zone P/1050
Authors: Suarsana I Putu , Badril Areza
Published: September 2011

Kenali Asam field, Pertamina EP working area, is located in West Sumatra of Indonesia. The field was discovered by NIAM in 1929. There are 285 wells were drilled which consist of 99 producing wells, 20 injector wells, and 8 dry well wells, and the rest are suspended wells. The reservoirs are layered reservoirs from shallow to deep zone, and 16 production zones. The oil was produced from primary stage to secondary stage. The secondary stage has been started by injecting water since March 1993. The water was injected to specific layer such as B/650, F/730, N/990, and S/1170. The peak production of primary recovery was 13,643 BOPD with water cut 14.4% in September 1954. Peak production of secondary recovery was 2105 BOPD with water cut 50% in October 1994.

Pertamina’s EOR department and Business Unit of Jambi field conducted pilot project to the zone of P/1050 with line drive pattern flood. The line drive pattern consist of 4 injection wells and 4 production wells. The pilot plan purposes are to evaluate the effect injection in that area to increase the energy of the reservoir, to sweep the oil to enhance the oil production. Before the water flood was commencing, chemical tracer was conducted to check the connectivity among the producers and injectors.

The chemical tracer IWT-2000 was injected to the KAS 63 (east area) for amount of 26 liters on November 17, 2007. The chemical tracer will be expected to flow to the monitor wells (KAS 227, KAS-028, KAS-164, KAS-39). Monitor wells are also considered as producer wells. The chemical tracers was detected in the monitor well (KA 39) after four months of injection from KAS 63. The rest of the monitor wells were not detected at all after 284 days of injections. But the connectivity analysis of injection and production showed that gross production, fluid level and bottom hole pressure increased in production wells.

In the west area, the chemical tracer IWT-1700 was injected to the injector KAS-73 in the mouth of 61 liter. The monitors wells, as well production wells, are KAS 35, KAS 38, KAS 243. The chemical tracer was detected in 3 months after injections in KAS 35. But there is no chemical detection in well KAS 38 and KAS 243 after 283 days. But, from the production analysis shows similar phenomena as in the east area. KAS 38 and KAS 243 showed the increment of gross production, pressure, and fluid level in the wellbore.

The waterflood pilot of layer P/1050 in Jambi area already conducted for couple years and the cumulative oil produced is more than 22 MBBO. This paper will described and evaluate the difference respond of fluid injection using chemical tracers and water. In the chemical tracer, it was detected the chemical concentration to evaluate the connectivity. Based on the water injection, it was evaluated the production performance to see the incremental of gross production, pressure and fluid level in the production performance.
Optimization of Completions in Unconventional Reservoirs for Improved Efficiency and Ultimate Recovery
Authors: Snyder D. J. , Seale R. A.
Published: September 2011

Over the last decade, an industry wide shift to unconventional plays has occurred due to advances in technology allowing for the recovery of previously uneconomic reserves. The primary objective of completions in these unconventional reservoirs is to increase the effective surface area of the well to maximize reservoir contact. Horizontal drilling and multi-stage fracturing are two technologies which have accomplished this.

The two main methods of horizontal, multi-stage completions currently used in unconventional reservoirs are cemented liner "plug and perf" and open hole, multi-stage fracturing systems. This paper provides an introduction to unconventional reservoirs, describes the main methods of horizontal, multi-stage completions, and discusses how the choice of method can affect good fracturing practices as well as long-term production. Case study examples are presented from a variety of unconventional reservoirs including shale, tight sandstone and tight carbonate formations.

Operators working in a number of unconventional reservoirs, such as shales and other tight rock formations are experiencing faster than expected production decline rates, resulting in reduced long-term, ultimate recovery. This may be in part due to the abandonment of good fracturing practices with the advent of horizontal, multi-stage fracturing. Issues such as near wellbore conductivity, flowback, and fracture tortuosity, which can have a significant effect on the long-term production of wells, need to be considered when choosing a completion method, particularly for unconventional reservoirs.

Unconventional plays are becoming a significant part of the oil industry today and will become a bigger part in the future. It is important that the reservoirs are completed optimally to achieve maximum recovery. The information provided in this paper is applicable to unconventional resource plays worldwide.
Spoolable Coiled Tubing Spears: Recovering Subsea Wells After Emergency Shutdowns
Authors: Guidry C. , MacDonald A. , Kelbie G.
Published: September 2011

A UK North Sea operator presented a challenging opportunity for the development of a contingency recovery system to be designed for deployment from an intervention vessel. The main requirement of the contingency tool was that it be capable of recovering coiled tubing that is subsequently left in a subsea well after previously operating an emergency shutdown (ESD) system and securing the well.

Typically, when an ESD operation must be performed, requirements demand that the vessel be unlatched from the subsea wellhead within 60 seconds. When the vessel returns, the operator has to recover the coiled tubing that was left in the well. Unlike conventional operations, for this vessel-deployed endeavor, the injector head is located over the moonpool, a large opening in the middle of the vessel that gives the operator subsea access. Unfortunately, the moonpool poses an inherent human risk; thus there exists the desire to limit human interaction in this type of operation.

To reduce the human risk involved, a spoolable spear system that eliminates the need to break out the lubricator/riser multiple times was engineered. The system was designed to enable retrieval of the sheared coiled tubing and recovery of the coiled tubing and connected tools to the work reel without breaking a lubricator/riser connection. Specifically, after a dressing run is completed, the spoolable coiled tubing spear is able to stab into the dressed open end of the coiled tubing and recover the coiled tubing string back through the injector head and back onto the work reel.

With an ever increasing focus on safety, particularly offshore safety, this spoolable spear system presents an opportunity to reduce human intervention in work locations and to significantly reduce the risk of injury. A reliability feature of the contingency system is that all components stressed during operation are to be replaced after each run, making it a one-run system. Multiple sizes of this coiled tubing recovery system have been developed for efficient and effective interventions while encouraging footprint minimization. Field-testing details will be reviewed and discussed during the associated presentation.
Modelling Residual Oil Saturation in Miscible and Immiscible Gas Floods By Use of Alpha-Factors
Authors: Bourgeois Marcel J. , Thibeau Sylvain , Guo Jia
Published: September 2011

For miscible gas flooding, it has been documented that forcing a residual oil saturation Sorm is helpful to make the compositional simulations more realistic. Our recent experience is that this concept can be extended to near-miscible and even immiscible gas floods. For CO2 floods, we have found that preventing this residual oil saturation from being stripped by the gas corrects overestimation of the recovery factor in compositional simulation, even at pressures lower than the miscibility pressure.

This residual oil saturation can be implemented with the use of Alpha-Factors (named also transport coefficients). Their physical meaning will be discussed, and also a way to generate them. Our method is to use an iterative process based on a PVT package, and analytical equations allowing to compute their endpoints are given.

Also some limitations of the approach will be discussed, such as grid size dependence, a weak pressure dependence and a strong dependence on the injected gas composition.
Petro-Elastic Parameters Effects on History Matching Procedures
Authors: Souza R. M. , Santos M. S. , Schiozer D. J.
Published: September 2011

Rock physics models are the quantitative link between the seismic information and reservoir properties. Thus, several authors have been used this link to develop methodologies aiming to integrate seismic derived information and production history matching. Nevertheless, there are significant uncertainties related to petro-elastic parameters definition and its effects on typical history matching results.

This paper evaluates this problem through the application of two history matching procedures. The empirical allowed range of petro-elastic parameters regarding fluid and rock behavior, such as temperature, salinity and porosity, mineral and dry rock modulus, respectively, are combined to define different data sets. Each set defines petro-elastic models to be coupled to a numerical reservoir model providing synthetic impedance distributions.

These sets of impedance are then used in two different integrated history matching techniques. First, each set is combined with production data defining a global objective function to be minimized and provide a new horizontal permeability distribution resulting in an updated model. Secondly, a constrained inversion procedure is applied to convert impedance into saturation and pressure distributions. These maps indicate the optimization regions and the quantitative seismic information to improve the global objective function minimization accuracy aiming to derive a new permeability distribution. Thus, permeability and bottom-hole pressure from the updated reservoir models are compared to evaluate the several combinations of petro-elastic parameters effects.

The major goals of this paper were to quantify the petro-elastic parameters definition effects on history matching procedures, indicating which of them is more sensitive to their variations. Furthermore, it was possible to assess their individual impact in the history matching results and highlight the importance of a careful definition of these parameters and its coherent integration with fluid flow models. This approach also contributes to quantitative integration aspects of oil reservoir development and management.
New Approach for Successful Sidetracking of a Cement Plug in Salt and Subsalt Wells at High Inclinations Using Rotary Steerable Tools and Reamers
Authors: Chamat E.. , Leavitt T..
Published: September 2011

Drilling for hydrocarbon deposits beneath the salt canopy in the Gulf of Mexico (GOM) has become common in deepwater; however, such drilling is made more difficult because of geological events that can cause difficulties in the drilling process, leading to expensive sidetracks or unwanted extra casing operations. To make operations economically feasible and to accomplish demanding rig utilization schedules, wells are planned to be drilled using one bottomhole assembly (BHA) from casing to casing at optimized rates of penetration (ROP), accurately placing the well while minimizing drilling and geological risks. Sediment inclusions, salt creep, rubble zones, narrow mud-weight windows along with well control events and mud losses, wellbore stability events and thin tar zones are some of those geological events found when drilling through salt and subsalt. Rotary steerable systems (RSS), reamers and synthetic oil-base muds have provided solutions to most of these challenges.

This paper presents case histories of two deepwater wells drilled in the GOM. The first case, describes how, after having drilled through a long salt interval, tar was unexpectedly penetrated, requiring sidetracking in two different bypasses at high inclinations. Previous experiences of the operator and the industry indicated that tar cannot be detected in seismic data or accurately correlated from well to well because its short extension, and its presence could prevent reaching programmed total depths. Because of the inability to drill through the few sequences of tar intervals, it was required to sidetrack the well on two different occasions at high inclinations to reach the planned borehole total depth with the planned casing program.

The second case presents the history of the deepest sidetrack performed in the GOM. This well was sidetracked for geological resons, subsalt at 28,822 ft measured Depth (MD), off of a cement plug.

A push-the-bit RSS (and a reamer in the first case history) was used to sidetrack off cement plugs in both cases. Both cases were planned to sidetrack on the low side; however, this practice commonly used for downhole motors, proved ineffective in both wells. Both cases indicated that good cement was placed in the lower side of the hole, and so a setting to the right of the high side of the toolface was used successfully to deflect the wellbore. The technique, difficulties, and best practices resulting from drilling these high inclination sidetracks are addressed in this paper.
Increased Success Rates for Squeeze-Cementing Using a Surfactant Soak -The Vital Role of Surfactant Concentration
Authors: Erwin Erwin , Dewanto Christianto Widi
Published: September 2011

Historically, in the Melibur oil field in Sumatra, Indonesia, typically more than two squeeze-cement jobs are required before cement isolation is achieved. Eventhough the goal for water-zone shut-off is eventually achieved, we tie-up staff and equipment an the cost per water-shut-off is high.

This circumtance challenged us to try a different squeeze cementing technique in order to achieve water-shut-off after one squeeze cementing job.

We considered various different approaches, such as modifying the cement recipe, injecting water-conformance chemicals and a surfactant soak.

Fluid-compatibility tests were performed, where various chemicals were added to a mixture of formation oil and water, to see which chemicals were most effective to de-emulsify the oil-water mixture. The idea was that cement would better bond with the formation water if it were separated from the formation oil.

Knowing the wetting characteristics of the reservoir rock is a must before deciding to use surfactant. The chosen surfactant must be water-wet and be non-damaging to the formation. We found an anionic surfactant was best for our formation.

Next came the hardest part, deciding the concentration of surfactant. In the lab, we increased the surfactant concentration gradually from 0.5% to 4% to see the effect on the cement bond. We found that if the surfactant concentration was too high, then the setting of the cement was retarded, and the additional waiting time was unacceptable for the field operation. We found that a 3 % surfactant with a 12-hour soak in the reservoir was best.

An additional benefit of the surfactant was it changed the oil-wet rock into water-wet rock, and thereby mobilized oil that was trapped near the rock surface. This made it easier for cement to bond with the formation.

This surfactant soak technique has been performed on seven wells to date. The first well required two squeeze-cement jobs to isolate the water, and the remaining six wells required one squeeze-cementing job. The failure in the first well was thought to be due to the incomplete mixing of the surfactant in our homemade batch mixer. After the first job, the batch mixer was modified with a more powerful hydraulic motor and a different agitator blade.

This technique is considered a big success, and is now standard practice in the Melibur oil field. This project demonstrates that old problems can be solved cheaply and effectively if we turn out thinking upside down.
Real-time Mineralogy, Lithology, and Chemostratigraphy While Drilling using Portable Energy-Dispersive X-ray Fluorescence
Authors: Marsala Alberto F. , Loermans Ton , Shen Shouwen , Scheibe Christian , Zereik Rachad
Published: September 2011

Our objective is to obtain — while drilling, in real time — a complete petrophysical characterization from drill cuttings and the return mud-stream. Currently such rock and fluid direct characterization is achievable only, with significant time delay and at a considerable cost, from measurements on cores. The approach is to integrate the direct measurements on cuttings with the Logging While Drilling (LWD) practices and tools, to support drilling, geosteering and formation evaluation.

In this framework, it is key to accurately characterize drilling cuttings from a mineralogical and lithological point of view. This characterization can be achieved performing an elemental analysis, by means of Energy-Dispersive X-ray Fluorescence (ED-XRF), in real time, with a portable instrument capable for use at the rig-site, integrated inside the mud logging operations.

The portable X-ray Fluorescence (XRF), coupled with a methodology that enables to convert the elementary analysis into a mineralogical composition, produces a characterization comparable to what can be obtained by full scale X-ray Diffraction (XRD) laboratory equipment. An experimental set up was deployed, to assess the ability to model the mineralogy from geochemically analyses of a set of rock samples.

After portable ED-XRF geochemical analyses, further lab-based analyses were carried out on the same samples: laboratory Wavelength-Dispersive XRF (WD-XRF) and ED-XRF in state of the art facilities. The geochemical data from the portable ED-XRF were compared to the lab-based XRF results (both WD-XRF and ED-XRF) and showed good agreement, particularly between the two ED-XRF instruments. As a final result, the modeled mineralogy from geochemical whole-rock data showed good agreement with the mineralogy determined from XRD analyses. Finally, a first field geochemical monitoring, by portable ED-XRF while drilling, was then successfully executed in Saudi Arabia.
The Use of Seismic Attributes for Depth Conversion and Property Distributions, E-M Field, Offshore South Africa
Authors: Corbett C. , Frewin J. , Kgogo T. , Dubost F. , Navarro R. , Tyler E. , Portet M.
Published: September 2011

The E-M field is a gas reservoir that has been under production for nearly a decade. This paper presents the effort of the team to revise and improve the sub-surface model to delineate new drilling targets. Closure of the field to the east was uncertain, but critical to the field development plan. Inversion of the seismic data created an absolute acoustic impedance cube and a derived effective porosity cube. Attributes were extracted from each of the various seismic data, using direct and interval extractions following the interpreted surfaces. Careful inspection of the seismic amplitude in cross section revealed a flat spot, indicating a potential fluid contact. This feature was confirmed in several of the extracted attributes which were then used to constrain an iterative depth conversion. Fault interpretations in time were then adjusted to match the new depth horizons creating enechelon faults in a fashion analogous to surface outcrops observed in the Cape Town region.

Uncertainty also exists with respect to the vertical isolation of the reservoirs. Log responses record a thin shale, below seismic vertical resolution, in all of the drilled wells. However, the areal extent of the shale is unknown, and vertical communication is a possibility. Stochastic representations of the potential shale extents were introduced into the dynamic fluid-flow simulation, and fed through an experimental design to test the impact on vertical connectivity. Using a proxy model from these results a Monte-Carlo simulation provided a probability distribution for the production response.

The methods presented here are applicable to fields wherever sharp acoustic impedance contrasts exist between fluid types, particularly in gas reservoirs or reservoirs with an existing gas cap. Seismic attributes have refined the depth conversion for the E-M field, and the resulting geomodel provides new drilling targets for the operator.
Is It Sufficient to Calculate Gas Viscosities?
Authors: Potsch K. , Gumpenberger T.
Published: September 2011

For many years it has been customary to calculate gas viscosities from their composition. The argument for it is that a great number of publications on that topic is available. Measurements in the past though were conducted with the light ends of the hydrocarbon spectrum. The theory suggests that the principle of corresponding states is valid which is acceptable if the components are not interacting with each other. This assumption may be not fulfilled for rich gas condensates, associated gases from light oils, gases from HPHT wells and gases with large amounts of sour components. This work investigates the principle of corresponding states and the calculation of the viscosity with an equation of state using literature data of the dynamic viscosity and the gas density. In conjunction with the experimentally determined density, one can easily calculate the kinematic viscosity. This procedure can yield some insight into how the transport property, the viscosity, can be better understood. The data analysis reveals that the kinematic viscosity follows different laws in the gas and the liquid phase. The results are compared with the tabulated values found in the literature and ourown measurements with a falling body apparatus.
CO2 Injection Efficiency, Synthesis of Conceptual Chalk Model: Incremental Oil Recovery and CO2 Storage Potential
Authors: Vuillaume J.. , Akervoll I.. , Bergmo P..
Published: September 2011

Enhanced Oil Recovery (EOR) using CO2 as injection gas after water injection is a method to increase the oil recovery efficiency compared to only using the water injection process. In addition, it also constitutes a storage method in an oil reservoir. CO2-EOR can help to reduce CO2 emissions regionally and simultaneously improve the security of energy supplies.

The purpose of the present paper is:

- To describe the base case simulations of continuous CO2 injection and CO2 Water-Alternating-Gas (CO2 WAG) injection in the North Sea "conceptual" chalk model. - To give quantitative results on EOR and CO2 storage capacity of the North Sea "generic" chalk model for the continuous CO2 injection and WAG-CO2 injection scenario.

Base case simulations of CO2 injection have been described using the North Sea anticline sector-type model as geometry. SINTEF's oil field database was used. Then conceptual reservoir properties were calculated. Porosity and permeability were computed based on the same methods as used previously for average and standard deviation to populate the conceptual model. Finally a stochastic model based on a Probability Distribution Function of porosity and permeability was used. A conceptual "chalk oil composition" was derived from the Syd-Arne oil field (DK) by an oil composition change in order to match the viscosity and density of conceptual oil. A general development strategy which consists of one producer (P1) and one injector (I1) has been applied.

Numerical simulation using a commercial compositional reservoir simulator was performed a Finite Difference Method. In addition, the dual permeability module was used in order to simulate fractures and matrix permeability flow. Molecular diffusion of CO2 (gas) into oil, oil into gas and CO2 into water was used. Gravity drainage, capillary forces and molecular diffusion are considered as the main factors to influence the oil recovery efficiency.

Results are compared for three cases:

-- Water flooding, continuous CO2 injection and CO2-WAG injection: - Field Oil Production Rate and Field Oil Production Total per pore volume injected - CO2 volume stored per pore volume injected

In all the reservoir model cases under investigation with CO2 continuous injection and WAG-CO2 injection, CO2 injection is found to increase the hydrocarbon recovery by 12% to 13.2% recovery after injection of 1.4 Hydrocarbon Pore Volume compared with a base case scenario which is water injection. After 90 years of injection, from 1.35 to 2.95 millions tonnes CO2 were stored for the WAG-CO2 and CO2 injection case respectively.
New Recovery Method for Carbonate Reservoirs through Tuning the Injection Water Salinity: Smart WaterFlooding
Authors: Yousef Ali A. , Al-Saleh Salah , Al-Jawfi Mohammed
Published: September 2011

Water flooding is the most widely applied method for recovering oil from reservoirs. The salinity and ion composition of the injection water in the past have not been considered as a key parameter in oil recovery from water-flooded reservoirs. In recent years, evidence — from laboratory studies verified by some field tests mainly targeting sandstones — has shown that injecting low salinity water has a significant impact on oil recovery. The potential for carbonates has not been thoroughly investigated where some of the reported studies have excluded carbonates from this effect.

Saudi Aramco, through its upstream research arm (the Advanced Research Center) has initiated a research program tagged "Smart WaterFlood" to explore the potential of increasing oil recovery by tuning the injection water properties. Based on the research work for the last three years, we present in this paper the results of reservoir condition laboratory coreflooding studies, conducted using composite rock samples from a carbonate reservoir, to investigate the impact of salinity and ionic composition on oil recovery. Also, we report a broad range of laboratory studies addressing oil recovery mechanisms.

The experimental results revealed that substantial tertiary oil recovery beyond conventional waterflooding can be achieved by altering the salinity and ionic content of field injection water. The new trend is distinct from what have been addressed in previous reported studies on topics of low salinity waterflooding for sandstones, or seawater injection into high temperature chalk reservoirs. Laboratory studies have also shown that altering the salinity and ionic content of the injection water has a significant impact on the wettability of the rock surface. The results, observations, and interpretations addressed in this study provided compelling evidence to suggest that the key mechanisms for substantial oil recovery by altering salinity of field injection brine is wettability alteration.
Measuring Partitioning Coefficients for Gas Tracer Mass Balance and Gas Injection Allocation
Authors: Cubillos H. , Torgersen H. , Chatzichristos C. , Rodriguez R.
Published: September 2011

An interwell gas tracer test provides very useful information not only to improve reservoir description but also to characterize flow dynamics.

Approaches to tracer application can range from conventional qualitative interpretation to quantitative analysis including numerical simulation. Our aim is to optimize miscible gas injection efficiency by correct calculation of gas injection allocation based on mass balance of the injected tracer (how much of an injected tracer is produced in the various production wells). Since perfluorocarbon gas tracers are partitioning tracers, and the capillary tube sampling technique only allows measurement of tracer concentration in the gas phase, knowledge of the partitioning coefficient (Kd) of the gas tracers at sampling conditions (wellhead pressure and temperature) is required. We successfully developed and implemented experimental design, equipment set up and procedures to measure a set of consistent Kd values for the oil and the gas mix for all commercial available gas tracers.

Subsequently, we integrated the Kd values with tracer and production data and estimated the correct recovery of the gas tracers. The next step was to estimate the gas injection allocation to optimize gas injection patterns and to provide input for improving the simulation history match.

Our approach is a further step in quantitative analysis of tracer data and can be applied to provide valuable information to optimize gas injection and oil production.
Towards an Integrated Workflow for Structural Reservoir Model Updating and History Matching
Authors: Leeuwenburgh O. , Peters E. , Wilschut F.
Published: September 2011

A history matching workflow, as typically used for updating of petrophysical reservoir model properties, is modified to include structural parameters including the top reservoir and several fault properties: position, slope, throw and transmissibility. A simple 2D synthetic oil reservoir produced by waterflooding is used to demonstrate issues related to observability and identifiability of structural uncertainties. A series of history matching experiments are performed that demonstrate the potential for estimation of uncertain structural parameter values. The experiments are performed with ensemble-based assisted history matching schemes that allow for the proper characterization of prior uncertainties, and in principle enable the updating of both model parameters and the dynamic states such as pressures and saturations. The results show that the approach works well when individual structural parameters are estimated and suggest further scope for building a fully integrated workflow that includes the improved construction of geo-models into the history matching loop.
Pre-Combustion Capture of CO2 from Synthesis Gas Mixture CO2/H2 Using Hydrate Formation
Authors: Gholinezhad J. , Chapoy A. , Haghighi H. , Tohidi B.
Published: September 2011

CO2 capture from CO2/H2 gas mixture is an attractive approach for reducing greenhouse gas emissions. This mixture is associated with power generation processes in power plants and typically contains 40% CO2 and 60% H2. A novel method for capturing CO2 from the above gas mixture is to use gas hydrate formation. This process is based on selective partition of CO2 between hydrate phase and gas phase. Due to their larger diameters, CO2 molecules have higher tendency to go into hydrate clathrates than H2 molecules, which ultimately results in a gas rich in carbon dioxide.

This study demonstrates the concept and presents the results of our experimental investigation for CO2/H2 separation by hydrate formation process. Since hydrate formation from water and gas requires high pressures, tetrabutylammonium bromide (TBAB) is added to the system to reduce the equilibrium pressure. TBAB forms semi-clathrates that can encage small gas molecules. The results shows that in one stage of gas hydrate formation and dissociation, CO2 can be enriched from 40% to 88%. In addition, the concentration of CO2 in equilibrium gas phase is reduced from 40% to 18%. While separation efficiency is comparable with the process without any additive, the presence of TBAB improves the operating conditions significantly. In addition, CO2 could be enriched to 98% by two stages of hydrate formation.
Contribution of the Gravel Mesh Size in Screen Damage on a Gravel Pack System
Authors: Villarroel F. M. , Braga A. M. , Camerini M. G. , Simoes T. B. , Bloch M.
Published: September 2011

The performance of a gravel pack sand control system is analyzed considering the potential screen damage associated to the gravel mesh size, which is the key-parameter for designing efficient gravel pack systems. Indeed, the largest mesh size able to reduce solid production while keeping the head loss as minimal as possible, would always appear to be the logical choice. However, screen integrity should also be considered whenever choosing the gravel mesh size, and experimental results presented in this paper show that the larger the mesh size, higher is the chance of localized damage appearing on the screen of the gravel-pack system.

Experimental tests with gravel pack prototypes were run in a large poliaxial frame, using two of the most common gravel sizes: 16/20 and 20/40 mesh. The system was set on artificial cubic rock samples of 11.8 in side, with a centered hole of 2.4 in diameter. The cubical samples were submitted to a triaxial stress field reaching the ratio SMAX/Smin equal to 1.6.

Visible localized damage in the screen’s outer surface was observed when testing the larger gravel agent (16/20 mesh), as compared to the smaller 20/40 mesh. The experimental observation was explained by contact stress effect, indicating that larger particle sizes are more prone to damage the screen, while the stresses transferred by smaller particles are more uniform. On the long run, the contact stress effect can result in erosion and, in some cases, screen collapse. A simple, qualitative, analytical model is employed to corroborate the mechanical effects observed in the experimental test.

Whenever designing gravel pack systems for deepwater wells, one should consider long term operation, avoiding complex and expensive workover operations. Thus, a more conservative design criterion is recommended to improve the gravel pack operational life, including the analysis of possible contact stress effects.
Assessment of Rate-Dependent Skin Factors in Gas Condensate and Volatile Oil Wells
Authors: Gringarten A. C. , Ogunrewo O. , Uxukbayev G.
Published: September 2011

Well testing in gas-condensate and volatile oil reservoirs with flowing bottomhole pressure below the saturation pressure creates multiphase flow in the reservoir, resulting in relative permeability reduction and a rate-dependent skin factor. In lean gas condensate reservoirs, the wellbore skin effect calculated using single-phase pseudo-pressures has often been found to be constant or even to decrease with increasing gas rates, instead of increasing as in dry gas reservoirs. This behaviour has been tentatively attributed to capillary number effects compensating for condensate blockage and inertia effects, but no detailed study of this behaviour has appeared in the literature to-date.

This paper investigates wellbore skin behaviours in lean and rich gas condensate reservoirs and in volatile oil reservoirs by using compositional simulation with capillary numbers and non-Darcy flow to generate well test data. It is shown that below saturation pressure, gas condensate well test analyses with single-phase pseudo-pressures and volatile oil well test analyses with pressures do not correctly estimate the rate-independent wellbore skin effects and the non-Darcy flow coefficients, whereas analyses with two-phase pseudo-pressure do, provided that non-Darcy and capillary number effects are included in the two-phase pseudo-pressure calculations. In gas condensate reservoirs below the dew point pressure, the rate independent skin factor and the non-Darcy flow coefficient calculated with two-phase pseudo-pressures are identical to the corresponding values calculated above the dew point pressure with single-phase pseudo-pressures. These simulation results are applied to actual field data.
Quantitative Analysis Involving Scaling Procedures for Integration between History Matching and 4D Seismic
Authors: Avansi G. D. , Schiozer D. J.
Published: September 2011

Time-lapse seismic has been providing valuable information on identifying fluid movements, to locate bypassed oil and well placement optimization to reduce uncertainties in reservoir development and production management. Most of these are made through a qualitative approach, which limits seismic data integration in reservoir simulation studies due to different scales. In order to overcome this and to develop new data integration techniques, many studies involving these processes have the assumption that both frameworks are in the same scale. Nonetheless, the quantification of lost information in the scaling procedures needs to be evaluated and quantitative seismic data integration into the simulator should improve the mitigation of these problems improving the knowledge about the representativeness of the scaled data.

In this context, it is presented a technique regarding scale issues relating time-lapse seismic data and simulation models aiming to quantify the information lost due to scaling problems and how these troubles affect the history matching.

This paper describes a methodology involving seismic attributes and reservoir simulation. The lost information due to scaling procedures is evaluated through comparison between flux model properties and seismic attributes, at each respective framework. This technique allows reliability improvement of reservoir parameters from seismic attributes regarding the loss of information due to scaling procedures and history matching.

It has been shown that it is possible to match the history production in order to improve the process considering the scaling issues between the seismic and simulation scale, increasing model quality and reliability on results through a quantitatively analysis involving scaling procedures between 4D seismic data and reservoir simulation integrated studies.

The main contributions of this technique are the integration procedures regarding scaling issues between seismic data, reservoir simulation models and history matching procedure by time-lapse seismic attributes.
A Method for Full-Range Young's Modulus Correction
Authors: Canady Wyatt
Published: September 2011

Deriving rock moduli from acoustic velocities is the most common method for evaluating formation mechanical strength in the petroleum industry. While common, the accuracy of the method is hindered by the difficulty correcting the moduli, as measured by the acoustic logging tool to values representative of the actual moduli of the rock.

Analysts generally rely on simple empirical equations to provide the estimates for the corrections that must be made. These empirical equations are usually derived from wireline logs or from core analysis of samples taken from the formation of interest. The usefulness and accuracy of this method of modulus correction is hampered by the fact that the dynamic-to-static conversions are strongly non-linear. The method is also hampered by the rather narrow range of values available in a particular empirical function.

This paper presents an empirical method featuring a simple, single equation that provides estimates of static Young's modulus across the whole-range stresses and rock strengths that might be encountered in a reservoir.
Reservoir Fluid Characterization and Application for Simulation Study
Authors: Singh Kameshwar , Mantatzis Konstantinos , Whitson Curtis H. , Benjemia Radhia
Published: September 2011

The paper presents a methodology to develop and apply an equation-of-state (EOS) multi-fluid model for a field in Tunisia. The EOS model was developed by matching measured PVT data for a near-critical oil sample. The fluid characterization was used to estimate contamination level in oil-based-mud contaminated MDT samples, calculate decontaminated sample composition, estimate zone composition based on clean-up test measured oil-gas ratio, estimate fluid composition of some layers where samples were not available, and study the effect of gas condensate blockage and capillary number on simulated well performance.

In this field, reservoir fluids range from lean gas condensate to rich gas condensate and volatile oil. Clean up tests were conducted for all four zones encountered in the well, and oil-gas ratios were measured. During the clean up test of one zone, a near critical oil sample was collected and standard PVT experiments were conducted. Oil based mud (OBM) contaminated MDT samples were collected from six of the nine non-communicating layers, with OBM contamination levels between 20–65 wt% STO.

An EOS model was developed after matching measured PVT data on the near-critical oil sample. The MDT samples were decontaminated using measured mud composition. The calculated decontaminated "clean" sample compositions were used in a reservoir simulation model to initialize the layer from which the MDT sample was taken.

The developed EOS model was also used to estimate the fluid composition of different zones and layers without fluid samples. The zone fluid compositions were calculated based on measured test OGR. The EOS model, zone fluid compositions, decontaminated MDT samples, and layer mobilities were used to estimate fluid composition of the layers without samples.

This paper provides a methodology that can be used in any other field.