bluuebunny/crossref_metadata_2025 huggingface dataset:
New Compounds for Hydrogen Sulfide Scavenging and Iron Sulfide Control
Authors: Aften Carl W. , Roberts Gayla
Published: September 2011

New compounds have demonstrated effective scavenging of hydrogen sulfide with potential for preventing deposition of metal sulfides. These compounds come from a variety of functional families and compete against typical scavenging technology well with respect to molar efficiency, reaction rate, and stability. These inhibitors not only work on existing sulfide but some can also be modified to change the oxidation state of the system to provide a non-scaling scenario.

The presence of hydrogen sulfide is an ever increasing problem in the oilfield, whether the origin is biological or formation dependant. The presence of extremely toxic hydrogen sulfide increases the corrosion rates of many metals and makes necessary the sweetening of produced hydrocarbon. If solubilized metals such as iron, lead or zinc are present in the fluid, the deposition of sulfides may occur as flow restrictive scale on the tubulars, leading to corrosion and/or biofilm augmentation or formation damaging fine particulate in the pay zone.

These single component inhibitors were tested in standard synthetic formation waters which were either sulfide laden and/or metal or sulfide laden. Waters derived were standard unadulterated species at various pHs or were acidified and then spent on carbonate. The rate of sulfide uptake was monitored and the soluble metal ions were determined. Response surfaces were generated for a few key inhibitors and the performance of the inhibitors was compared to standard inhibitors. Stability was also checked to ensure insoluble or reversible scavenging species were measured.

The use of these scavengers for drilling, stimulation, completion, and produced fluids provides the service company and/or operator with a viable treatment for problems incurred when treating sour reservoirs.
An Experimental Study of a New VES Acid System: Considering the Impact of CO2 Solubility
Authors: Gomaa Ahmed M. , Wang Guanqun , Nasr-El-Din Hisham A.
Published: September 2011

Viscoelastic surfactant (VES) based self-diverting acid system has been developed for better matrix treatment of carbonate formations. Literature survey indicates that the highly viscous fluid acts as a temporary barrier to reduce further fluid loss into the wormholes and allows complete stimulation of all treating zones. After acid treatment, the viscous fluid is broken by either formation hydrocarbons or pre-flush fluids. However, recent lab work confirmed that a significant amount of surfactant was retained inside the core even when mutual solvent was used. The present study was conducted to better understand these acid systems and determine factors that impact their viscosity build-up and performance inside the carbonate formations.

A series of coreflood tests were conducted using low and high permeability carbonate cores at different injection rates. Propagation of the acid, surfactant, and reaction products inside the cores was examined in detail. Samples of the core effluent were collected and the concentrations of calcium, surfactant, and acid were measured. Permeability enhancement and location of any precipitation was detected using CT scanner to the core before and after the acid injection. Material balance was conducted to determine the amount of surfactant that retained in the core.

Experimental results show that VES acid was only able to build pressure drop across the core at injection rates less than 1 cm3/min when it was injected inside 80 md permeability cores. However, at injection rates of 1 cm3/min and higher, VES was not able to build any pressure drop across the core when it was injected into 4 md cores. Acid pore volume to breakthrough and amount of VES retained in the core were reduced when low permeability cores were used. Calcium propagated faster than HCl, while surfactant propagated the same rate as HCl. Also, pore volume needed to breakthrough the calcium and the maximum calcium concentrations were independent of the acid injection rate. CT scan confirmed that wormhole branches were observed at the second half of the core. At ambient conditions: viscosity of live VES acid was higher than that of partially neutralized (pH 4.5). At temperatures greater than 140oF, the viscosity of partially neutralized acid was higher than the live acid. G’ of the live VES acid was dominant at ambient temperature, while when temperature increased to 85oF, G"became the dominant characteristics of the live VES acid.
Study of CO2 Effect on Asphaltene Precipitation and Compositional Simulation of Asphaltenic Oil Reservoir
Authors: Choiri M. , Hamouda A. A.
Published: September 2011

At pressures greater than the minimum miscibility pressure (MMP), oil and CO2 are mutually soluble. The dissolved CO2 reduces the viscosity of the oil and causes swelling of the oil phase, hence improving its ability to flow through the reservoir rock. As a mean of reducing emission CO2 is injected into mature reservoir for both sequestration and EOR. In cases where asphaltene is present both processes are affected.

The study here addresses asphaltene precipitation due to pressure, temperature and composition changes during CO2 injection into of asphaltenic oil reservoirs. It is, therefore imperative to identify stability conditions of the asphaltene.

A simple model approach has been developed in this work to determine the asphaltene stability envelope associated with CO2 injection. The model approach is based on Flory-Huggins polymer-solution theory and Hildebrand solubility concept. The model approach is verified by literature data from different crude oil compositions.

In addition a simulation work, by compositional simulator, is done to map the asphaltene deposition within a reservoir, which that confirmed our previous study where it is demonstrated the dependence of asphaltene precipitation on the magnitude of the pressure drop within the production area of the reservoir.
Optimized HP/HT Acid Blends and Associative Polymer Diversion Proven to be Successful in Acid Fracturing a Multilayered Reservoir: A Case History from South Ghawar Gas Field in Saudi Arabia
Authors: Solares J. R. , Al-Asiri Khalid , Franco Carlos , Vielma Jose , Izquierdo Guillermo
Published: September 2011

Acid fracturing has been extensively used as a well proven method to stimulate carbonate formations in the Ghawar field. The unique reservoir characteristics found in all the wells producing from carbonate reservoirs in the field make acid fracturing stimulation operations highly dependent on fracture stimulation capability to connect multilayered zones, adequate fluid efficiency (effective leakoff control), fluid properties to generate proper fracture geometry with high-pressure/high temperature environments, and engineering work to design an economical but successful stimulation treatment.

This paper discusses a case study for a gas well in a carbonate reservoir in Saudi Arabia where an effective diversion technique with associative polymers and new optimized acid formulations was successfully performed. The treatment included a delayed borate crosslinked fluid used as a pad to create and extend the hydraulic fracture, and two 26% hydrochloric (HCl) acid blends (one emulsified and the other gelled) to efficiently penetrate and etch the surface rock. Also, proper diversion stages were included to ensure full stimulation zonal coverage, and rigorous engineering efforts to ensure that an economical but successful acid fracturing stimulation treatment could be performed.

Both the emulsified and gelled 26% HCl acid blends used were extensively tested for corrosion at a temperature of 275 °F. Additionally, emulsion stability tests were carried out on the mixtures to ensure retardation properties at bottom-hole conditions, and achieved a longer acid fractured etched length with optimum conductivity. Based on lab results, a new optimized emulsified acid formulation was finally designed and implemented.

The paper also summarizes the main results obtained when the previous optimized acid stimulation system was carried out in a highly deviated well. The final gas production results exceeded expectations, thereby confirming the effectiviness of a special acid blend for stimulation of carbonate formations.
Determining Microbial Activities in Samples from the Shale Gas Field Compromising Water Reuse and Disposal
Authors: Agrawal A. , Chatterjee I. , Voordouw G. , Lomans B. P. , Kuijvenhoven C. , Henderson J.
Published: September 2011

Gas production from subsurface shales requires fracture technologies in which fracturing fluid, consisting of guar gum-suspended sand, is forced into the fractures to "prop" them open. The guar gum is easily degraded by bacteria both downhole and at the surface, compromising water reuse or disposal. Samples from the Pinedale shale gas field had high activity of mesophilic acid-producing bacteria (APB), converting guar gum to sugars and then to acetic and propionic acids and of heterotrophic nitrate-reducing bacteria (hNRB), using sugars or acids from guar gum as electron donor for nitrate reduction. Activity of sulfate-reducing bacteria (SRB) was considerably lower with guar gum, reflecting a low initial population size of SRB using the organic acids produced by APB for reduction of sulfate to sulfide. The low concentrations of sulfate in the samples (0–0.4 mM; 0–40 ppm) may be the root cause for this low SRB activity. Indeed, most probable numbers (MPNs) of SRB, determined on standard lactate-sulfate medium were 10- to 100-fold lower than those for APB, determined on standard phenol red-glucose medium. Interestingly, lactate-utilizing SRB appeared to be able to grow in APB medium, indicating that some SRB can also maintain themselves by fermentative metabolism, when sulfate is absent.

Culture independent surveys of community composition confirmed that the microbial community at Pinedale samples was dominated by classes of fermentative bacteria (APB). Overall, we conclude that monitoring of the MPN of glucose-fermenting APB most accurately reflects microbial activity and associated biofouling at Pinedale. The success of biocide treatment to reduce microbial activity and associated biofouling is, therefore, also more accurately determined with the APB assay than with that for lactate-utilizing SRB.
Rheology of a New Sulfonic Associative Polymer in Porous Media
Authors: Seright R. S. , Fan Tianguang , Wavrik Kathryn , Wan Hao , Gaillard Nicolas , Favéro Cédrick
Published: September 2011

For hydrophobic associative polymers, incorporating a small fraction of hydrophobic monomer into an HP AM polymer can promote intermolecular associations and thereby enhance viscosities and resistance factors. In this paper, we investigate the behavior of a new associative polymer in porous media. The tetra-polymer has low hydrophobic monomer content and a molecular weight (Mw) of 12–17 million g/mol. Total anionic content is 15–25 mol%, including a few percent of a sulfonic monomer. This polymer is compared with a conventional HPAM with 18–20 million g/mol Mw and 35–40% anionic content. Rheological properties (viscosity versus concentration and shear rate, elastic and loss moduli versus frequency) were similar for the two polymers (in a 2.52% TDS brine at 25°C). For both polymers in cores with permeabilities from 300–13,000 md, no face plugging or internal filter cake formation was observed, and resistance factors correlated well using the capillary bundle parameter. For the HPAM polymer in these cores, low-flux resistance factors were consistent with low-shear-rate viscosities. In contrast, over the same permeability range, the associative polymer provided low-flux resistance factors that were 2–3 times the values expected from viscosities. Moderate shear degradation did not eliminate this effect—nor did flow through a few feet of porous rock. Propagation experiments in long cores (up to 157 cm) suggest that the unexpectedly high resistance factors could propagate deep into a reservoir—thereby providing enhanced displacement compared with conventional HPAM polymers. Compared with HPAM, the new polymer shows a significantly higher level of shear thinning at low fluxes and a lower degree of shear thickening at high fluxes.
Scale Formation Prevention During ASP Flooding
Authors: Karazincir O. , Thach S. , Wei W. , Prukop G. , Malik T. , Dwarakanath V.
Published: September 2011

The purpose of this work was to identify complexing agents and commercial scale inhibitors that can prevent scale formation in field brine during an ASP flood. The original field brine has near 1,000 ppm Ca++/Mg++ and 450 ppm HCO3− at pH 6 (Scale index, SI=0 at reservoir conditions). During ASP flooding, when the pH is increased to above 9, CaCO3 and MgCO3 scale occurs (SI=2.36). In order to prevent scaling during an ASP flood, divalent cations can be captured by addition of agents that form water-soluble complexes with metal ions in brine. With this purpose, six organic and two inorganic complexing agents as well as six different commercially available complexing agent brands have been tested. A working formulation with 11,000 ppm of an organic complexing agent was developed that can prevent scale formation up to pH values 10.5. The scale prevention capacity of four different commercial scale inhibitors were also tested alone and in combination with the mentioned complexing agents. Addition of 200 to 500 ppm of phosphonate or polyvinyl sulfonate based scale inhibitor helps drop the complexing agent concentration needed to prevent scale formation down to 5,500 ppm at pH values of 10.3 or less.
Minimizing Scale Precipitation in Carbonate Cores Caused by Alkalis in ASP Flooding in High Salinity/High Temperature Applications
Authors: Bataweel M. A. , Nasr-El-Din H. A.
Published: September 2011

Using an inorganic alkali in alkaline/surfactant/polymer (ASP) flooding resulted in scale precipitation when multivalent cations exist in mixing and/or formation brine in some extended field studies. This issue can be critical in the un-swept zones, which are the major target for EOR process, where formation brines can have high concentrations of Ca2+ and Mg2+. Any precipitation can result in plugging the pores in the target zone and loss of injectivity.

Several alkalis were evaluated to assess their scaling potential in high salinity formation brines and seawater as mixing brine at high temperatures. Four alkalis were evaluated; three inorganic alkalis sodium hydroxide, sodium carbonate, and sodium metaborate, and one organic alkali.

Eliminating the need to soften the mixing brine will result in expanding the ASP application to more challenging applications and will reduce the softening cost for the mixing water. Preventing precipitation of scale when chemical slug enters the unswept zones will result in improving the efficiency of the ASP flood, reduces chemical consumption and prevent scale precipitation that can cause formation damage and operational problems in the producers.
Split-Fluid Method Improves Fracturing Operational Efficiency
Authors: Mandarich Matthew , Neal Greg
Published: September 2011

Split-fluid fracturing uses two fluid streams, (1) a highly concentrated slurry and (2) a clean fluid, sent to separate groups of high-pressure pumps, which is an alternative to the traditional method of supplying a lower-concentration slurry to all highpressure pumps. Reducing the number of high-pressure pumps exposed to abrasive slurries extends pump and manifoldequipment life. Centrifugal pumps at the fracturing-fluid supply send water to the blender and also boost the clean fluid highpressure pumps directly. Chemical additives, such as friction reducers, can be added to the clean fluid. The highly concentrated slurry and the clean fluid are mixed together in the high-pressure manifold. The resulting fluid-proppant concentration is monitored by a high-pressure densometer. Updated blender operating software combines input from flow meters monitoring the two fluid streams to determine a real-time combined fluid rate. Chemical additive and proppant rates are adjusted by the blender software so that the combined fluid meets the fracturing job-design specifications. Field trials were conducted to determine the effectiveness of this method along with variations to the method, such as mounting the clean fluid-supply boost pumps onto the high-pressure manifold trailer.

This method has been successful in waterfrac market areas using low proppant concentrations (0.5-lbm/gal concentration on the majority of jobs), high water volumes (more than 3,000 barrels), and high-rate (more than 50 bbl/min) fracturing treatments.

Maintenance costs were dramatically reduced while fracturing treatments were delivered to the operator as designed with increased reliability of pumping equipment and no lost time.

Fracturing equipment service operators and well operators both benefited from reduced operational costs and the increased reliability of the pumping equipment. Additionally, reducing the amount of back-up fracturing equipment required helped reduce the equipment footprint on location.
Structural Integrity and Life Extension of Offshore Installations by Ultrasonic Peening
Authors: Martinez Luis Lopez
Published: September 2011

Extensive life extension studies for a FPSO installation have been carried out. High stressed welds showed too short fatigue lives in as-welded condition. Ultrasonic peening has been selected to extend the fatigue lives of the concerned weld details. The aim with the ultrasonic peening treatment was to avoid any further weld repair and by that contribute to the structural integrity of the installation during its remaining service life.

Fatigue life extension has been achieved by the application of ultrasonic peening to high stressed areas on the pallet stool- and on longitudinal-weld details on the ballast tanks on a FPSO installation.

The fatigue lives for the treated welds were extended to twenty years which is the targeted service life for the installation.

Quality Assurance and Quality Control were covered by Ultrasonic Peening Procedure Specification, applied for every treated weld. It ensures that the treatment is exactly reproduced to achieve the expected life extension.

Despite the variable weld quality encountered on the pallet stool welds the treatment was carried out at perfection and it showed to be relatively easy and straight forward application even in locations of difficult access.

The economical benefits due to reduced maintenance as a result of the ultrasonic peening treatment include:
Implementing a Novel Method for Injection Efficiency Optimization in Water Flooding Process: Case Study
Authors: Bostan Mashaallah , Kharrat Riyaz , Ghorbani Davood
Published: September 2011

The work has used a novel method for injection efficiency optimization following water flooding management in one of the Iranian under saturated oil reservoir. This reservoir is located at south west of Iran with 10km2 area, oil gravity 34° API, oil formation volume factor 1.45 bbl/STB, gas oil ratio 865 SCF/STB and initial pressure of 3200 psi.

This method is on the basis of individual streamline simulation ability, to describe Well Allocation Factor for injection and production wells. On the other hand, by using streamline simulation we can identify: 1) distribution of injected water to associated producers, 2) water loss to the aquifer, 3) percentage of oil produced due to each supporting injector, and 4) amount of water cut attributable to each supporting injector. Since the Well Allocation Factor provides the amount fluid attributed to each injector-producer pair, it is possible to define injection efficiency. The optimization of injection efficiency is based on increasing the injection rates in efficient injectors and decreasing them in inefficient injectors. In this study, therefore, we have used streamline simulation for injection efficiency optimization with the aim of increasing oil recovery. The current study includes 2 parts. Firstly, we identify wells injection rates based on mathematical relationships and secondly we increase injection efficiency and oil recovery by decreasing water loss to the aquifer. By using this method and with the same amount of injected water, in the first and second part injection efficiency increased from 46% to 53% and 53% to about 55% in a three years simulation respectively. At the end, it was revealed that this method is suitable to identify and optimize injection rates, reduction water loss to the aquifer and subsequently an increase in oil recovery.
Openhole Versus Cemented Completions for Horizontal Wells with Transverse Fractures: an Analytical Comparison
Authors: Augustine Jody R.
Published: September 2011

Horizontal wells that are to be stimulated with transverse fractures are usually completed either openhole with annular isolation packers or cemented. Fluid communication is established by perforating or using stimulation sleeves. The industry continues to grapple with several issues regarding these completions, such as what the optimum number of fractured intervals is, and which approach (openhole versus cemented) provides the best hydrocarbon production.

Analysis was performed to create a simple method for determining the production impacts of increasing the number of fractured intervals in a horizontal well. The intent was to create something similar to the McGuire-Sikora curves (method of determining the production impacts of fracturing vertical wells) for horizontal wells with transverse fractures. Using the McGuire-Sikora curves allows for a quick assessment of productivity gains associated with fracture stimulating a vertical well.

Analysis was performed using a two-dimensional reservoir simulator using a steady-state edge drive. A methodology was developed, and is described, for including the effects of vertical to horizontal permeability ratios in a two-dimensional simulator.

Analytical results showed productivity-index ratios as a function of relative conductivity for different fracture geometries. The resulting curves were used to estimate production gains of fracture stimulation compared to the openhole, unstimulated case. The variables included in the analysis were reservoir permeability, vertical to horizontal permeability ratio, reservoir thickness, reservoir length, fracture half-length, fracture width, fracture permeability, fracture spacing along the horizontal, and openhole and cemented completions.

In this paper, comparisons are made to published works that use production data and microseismic data to compare openhole and cemented completions. The analysis presented should help fuel the industry debate of whether cemented completions are an overused solution.
The Hydraulic Effect of Tool-Joint on Annular Pressure Loss
Authors: Enfis Majed , Ahmed Ramadan , Saasen Arild
Published: September 2011

For a successful drilling operation, downhole pressure or equivalent circulating density (ECD) control is very critical. Conventional drilling techniques require maintaining the bottomhole pressure between pore and fracture pressures. Specially, in deepwater wells, the margin between these pressures is very narrow. As a result, the bottomhole pressure and ECD must be predicted accurately and maintained within the narrow margin to avoid kicks and circulation losses. In the past years, a number of wellbore hydraulic studies have been conducted to predict the annular pressure losses. The effects of drillpipe rotation speed, borehole geometry, and pipe eccentricity on annular pressure loss have been investigated earlier. However, very limited studies have been carried to investigate the effect of tool-joint on the hydraulics. The presence of a tool-joint changes the annulus geometry between the drillpipe and casing/hole resulting in strong turbulence and fluid acceleration that generate additional viscous dissipation and pressure losses.

This article presents the results of theoretical and experimental studies conducted to examine the hydraulic effects of rotating and non-rotating tool-joints. Two different tool-joint geometries were considered in the investigation. Tests were performed with water based fluids that have different rheological properties under both laminar and turbulent flow conditions. Results show substantial increase in pressure loss gradient around the tool-joints. The increase in pressure loss depends on fluid properties and flow geometries. The rotation of the pipe tends to slightly affect the pressure loss. Using dimensional analysis in conjunction with theoretical methods, new theoretical and semi-empirical models have been developed to account for the contribution of tool-joints to the total annular pressure loss. Models predictions show good agreement with previously reported laboratory experiments. The new models are very useful to predict downhole pressure in deepwater and extended reach wells where accuracy in hydraulic calculations is very important.
Stay in the "Box": A Consistent Method for Configuring (Loading) Reciprocating Compressors to Optimize Performance
Authors: Harms Larry K. , Garza Manuel A.
Published: September 2011

Reciprocating compressors are a vital element in the production of onshore natural gas and oil but there is no accepted method for configuring compressors consistently to optimize performance. Most configurations (setting the compressor’s allowable operating range, load and capacity) are done based on an undocumented method unique to the individual doing the configuration, using inconsistent data and parameters with multiple and varying safety factors. This reduces the compressor’s effectiveness and in the end limits production. A structured method that relies on constructing and staying in an operating diagram "box" using set parameters and data has been developed to enhance compression effectiveness. This method helps achieve a common understanding among operations, maintenance and engineering personnel and consistently configures reciprocating compressors for optimized performance, increased reliability and safe operation. The method is explained and the results of implementing the method in a major onshore gas field are discussed.
Managed Pressure Drilling Enables Drilling Beyond the Conventional Limit on an HP/HT Deepwater Well
Authors: Kernche F. , Hannegan D. , Sammat E. , Arnone M.
Published: September 2011

This paper describes the successful application of Managed Pressure Drilling on a HPHT well drilled offshore. Wells in located in the field where this particular paper was focused and other offset wells in the area had faced many problems including inadequate mud management due to depleted or over pressured zones, influxes, mud losses and differential sticking. This well was a High Pressure and High Temperature (HPHT) well drilled in the area using the MFCS MPD system, closed loop method of accurately monitoring and controlling flow and pressure which can significantly reduce NPT.

Extensive engineering, training and development of procedures were carried out prior to spud. MPD was utilized to drill two hole sections. Specific MPD techniques were developed to handle the drilling operations. The resulting benefits associated with MPD led to improvements in drilling performance, and eliminated many of the traditional problems faced on other HPHT wells in the area. MPD has now become an integral part of the well operating philosophy and has established new standards for drilling wells of this type.

The MPD system was used from the start drilling of the 12 ¼" section to end of drilling 8 ½" section. One of the main benefits of using the MPD system was the ability to control the pressure dynamically when drilling through abnormally pressure layers by manipulation of surface back pressure instead of mud weight changes to maintain drilling progress. This facilitates rapid and safe rising of bottomhole pressure to control influxes and their subsequent bleed down. The utilization of this system on this well helped drilling to target depth while effectively handling influxes with significant time saving. The system was used for the first time to facilitate fishing operation by using a lighter mud weigh and manipulate the proper surface back pressure. The planning, development and execution phases of the MPD project are detailed in this technical paper.
Optimizing Horizontal Stimulation Design Utilizing Reservoir Characterization from Decline Curve Analysis
Authors: Gonzales Veronica M. , Callard Jeff
Published: September 2011

Existing flow models aid in the identification of key variables, such as original hydrocarbons in place and the productivity index, from examining various flow regimes from production decline data. In addition, specialized plots and well configuration information can infer additional reservoir characterization such as system permeability and fracture half length. Reservoir system permeability is crucial in designing multi-stage completions in order to prevent premature stage competition. Fracture half length determination provides a basis for designing lateral spacing.

Determination of the duration of the linear flow period toggles performance prediction thus providing a performance model that can be coupled with economics to optimize number of stages in horizontal wells. This system permeability also allows fracture half length to be calculated during the linear flow period from the production data.

Studies within various reservoirs have provided a methodology for analyzing and establishing infinite acting versus boundary dominated flow patterns including single phase gas, dissolved gas drive and retrograde condensate reservoirs.

The application of this study is to demonstrate the work flow in characterizing reservoir and fracture parameters and utilize this information to optimize economic recovery.
Interwell Water Tracer Pilots in North Kuwait Fields, A Valuable Opportunity to Understand Fluid Movement within a Waterflooded Reservoir
Authors: Al-Ajmi Moudi , Pathak Ashok , Al-Otaibi Basel , Al-Mufarej Mishal , Ashkanani Fatma , Abdullah Waleed , El-Doushy Ahmad , Al-Hamer Mohamad , Al-Anzi Ealian
Published: September 2011

Front-tracking and monitoring of pattern water-flooding are crucial reservoir management activities in the Mauddud (MA) carbonate reservoir. This depletion drive reservoir has been on water flooding since 2000. To help understand the complex water movement that has been observed following implementation of the water floods, it is essential that water tracers be employed in MA injection wells. The use of tracer technology is becoming increasingly important to the petroleum industry and it has proven to be an efficient tool to investigate reservoir flow performance and reservoir properties that are controlling fluid displacement processes. Inter-well tracer has proven to be successful in identifying direct communication between the injection and production wells, flow patterns within the reservoir, thief zones, swept pore volume, reservoir layering, and flood performance. Tracer studies have also been used to complement the information provided by other reservoir characterization methods such as pulse and interference testing.

Water tracers were employed in MA since 2007 at a pilot level, which is gradually expanding to full-scale implementation. Monitoring tracer breakthough information have provided invaluable information concerning the influence of faulting and stratigraphy on fluid migration within the reservoir which has been used to guide calibration/updating MA model and planning more tracer projects. The tracer data have been used to reduce the uncertainty attributed to well-to-well communications, and vertical and horizontal flow barriers.

The study presented in this paper includes two injection wells which have been on waterflood since 2000. Different water tracers were injected in this field since 2007. Produced water samples were collected for tracer detection. This paper includes discussions on the implementation of tracers in a carbonate reservoir presenting detailed analysis and interpretation of the results.
On Application of Non-Cubic EoS to Compositional Reservoir Simulation
Authors: Yan Wei , Michael L. Michelsen , Erling H. Stenby
Published: September 2011

Compositional reservoir simulation uses almost exclusively cubic equations of state (EoS) such as the SRK EoS and the PR EoS. This is in contrast with process simulation in the downstream industry where more recent and advanced thermodynamic models are quickly adopted. Many of these models are non-cubic EoS, such as the PC-SAFT EoS. A major reason for the use of the conventional cubic EoS in reservoir simulation is the concern over computation time. Flash computation is the most time consuming part in compositional reservoir simulation, and the extra complexity of the non-cubic EoS may significantly increase the time consumption. In addition to this, the non-cubic EoS also needs a C7+ characterization. The main advantage of the non-cubic EoS is that it provides for a more accurate descrition of fluid properties, and it is therefore of interest to investigate the computational aspects of using such models.

In this work we test the feasibility of applying a non-cubic EoS to reservoir simulation, using a slimtube simulator to simulate multicomponent gas injection using both the traditional SRK EoS and the non-cubic PC-SAFT EoS. Computation times for both models were compared. In addition, C7+ characterization for PC-SAFT and the performance of PC-SAFT in PVT modeling are also addressed.
Analysis of Field Responses to Low-Salinity Waterflooding in Secondary and Tertiary Mode in Syria
Authors: Mahani H. , Sorop T. G. , Ligthelm D. , Brooks A. D. , Vledder P. , Mozahem F. , Ali Y.
Published: September 2011

Low-salinity water injection is an emerging IOR/EOR technique, applicable to mixed-to-oil-wet sandstone reservoirs. This paper describes the field response for two large fields: Omar (secondary flood) and Sijan (tertiary flood). The data were analyzed using analytical and numerical modelling tools. This included evaluation of scaling numbers, mixing and dispersion and calibration. Insight was obtained on relevant drive mechanisms.

The responses to low-salinity flooding differ for the two fields: In Omar, a dual-step water-cut development was observed, which is characteristic for a change in wetting state. Our interpretation is that in this field, viscous forces provide the dominant drive mechanism, which is favorable to low-salinity flooding. We were able to history match the low-salinity response using a simple conceptual model.In Sijan, the low-salinity flood appears to be still immature and breakthrough of low-salinity water has not (yet) been observed. The reasons for the muted response thus far are explored, including a rather strong buoyancy effect caused by the higher permeability of the block, and the significant effect of injectant mixing with the highly saline aquifer.

A proposal is made for a workflow on how to apply this analysis to future low-salinity flooding implementation in field cases.
Practical Aspects of Gas Material Balance: Theory and Application
Authors: Diamond Phil , Ovens Jonathan
Published: September 2011

Gas material balance is often considered one of the more elementary areas of Reservoir Engineering. However, the simplicity of the straight line p/Z plot is often masked by many geological realities: partially sealing faults, aquifer influx, heterogeneity and low permeability. The purpose of this paper is to present a more realistic but still practical theory of gas material balance.

The paper begins by reviewing the underlying theory behind gas material balance and shows how an average reservoir pressure can be calculated that accounts for flux between reservoir compartments and by using this average reservoir pressure, water influx volumes can be estimated in compartmentalised reservoirs. The technique is applied to three real field cases; in the first case water influx was suspected but using this analysis it was possible to show, convincingly, that there was no water influx and previous deviations from a straight line p/Z trend were due to partially sealing faults. In the second case, the field clearly did suffer from aquifer influx and we show how this technique was used to estimate the invaded volumes and the material balance analysis was validated by core flood results.

Finally, we show a case where the material balance technique has been linked to an uncertainty analysis. For each GIIP estimate, a corresponding water influx volume was calculated, which in turn was converted to an equivalent displacement of the gas-water contact (GWC) depth. We show how the "most likely" GIIP and water influx estimates for the field were validated by production and log data from two wells within the field.
CO2 EOR Production Properties of Chalk
Authors: Olsen D.
Published: September 2011

The production properties of chalk from the Tor and Ekofisk Formations of a Danish North Sea oil reservoir were compared in two core flooding experiments at the conditions of the reservoir. Both experiments started with a water-flooding, and then continued with a CO2-flooding.

The Tor core sample was saturated with live oil to So=85.0 %, while the Ekofisk sample was saturated to So=63.7 %, the difference reflecting a difference in capillary pressure. The remainder of the pore space contained formation water. The water-flooding resulted in Sorw=25.3 % for the Tor chalk, and Sorw=37.7 % for the Ekofisk chalk. The difference in Sorw reflects different production properties during water-flooding of the Tor chalk and the Ekofisk chalk. After changing the flooding agent to CO2, the oil production resumed in both experiments, and resulted in SorCO2=5.8 % for the Tor chalk and SorCO2=4.6 % for the Ekofisk chalk. The Tor chalk produced 70.2 %OOIP during the water-flooding and 23.0 %OOIP during the CO2-flooding. In contrast, the

Ekofisk chalk produced 40.8 % OOIP during the water-flooding and 52.1 % OOIP during the CO2-flooding.

The inferior production properties during water-flooding for the Ekofisk chalk did not result in similar poor production properties during the CO2-flooding. The Tor chalk and the Ekofisk chalk showed production profiles that were very similar in the later part of the CO2-flooding, but differed in the early part, where the Tor chalk produced water, while the Ekofisk chalk produced oil. It is concluded that the Tor chalk and the Ekofisk chalk had different production properties in the water-flooding, but similar production properties in the CO2-flooding. Because the water-flooding left much more oil in the Ekofisk chalk, the CO2-flooding could recover a much larger oil volume from this rock.

Neither the Tor sample nor the Ekofisk sample showed evidence of dissolution after the experiments. Both samples remained within the elastic regime all through the experiments.

A significant potential for CO2 EOR may be present in Ekofisk chalk that is non-economic for water-flooding.
Experimental and Numerical Evaluation of Carbonated Water Injection (CWI) for Improved Oil Recovery and CO2 Storage
Authors: Kechut Nor Idah , Sohrabi Mehran , Jamiolahmady Mahmoud
Published: September 2011

One of the well-known problems in CO2 enhanced oil recovery (EOR) processes is the poor sweep efficiency due to the high viscosity contrast between CO2 and the reservoir resident fluids (oil and brine). CO2-augmented waterflooding or carbonated water injection (CWI) could lessen this problem. As CO2 is dissolved in and transported by the flood water, CO2 is more evenly distributed within the reservoir thus improves the sweep efficiency. This is beneficial to watered-out oil reservoirs where high water saturations could adversely affect the performance of the conventional CO2 injections. CWI also provides a very safe method for storing large quantities of CO2 as a dissolved phase in oil reservoirs.

This paper presents the results of our experimental and numerical investigations on the oil recovery and CO2 storage benefits of CWI in secondary and tertiary recovery modes through a series of coreflood experiments and detailed compositional simulation. The experiments were performed in a water-wet Clashach core with decane as well as restored North Sea reservoir core with stock tank crude oil and seawater at reservoir conditions. The experimental results demonstrate that CWI in both secondary and tertiary recovery modes can improve the oil recovery above the plain waterflooding. 45-51% of the injected CO2 was stored in the core at the end of the coreflood tests indicating the high potential of CWI not only for EOR but also as a CO2 storage injection strategy. Results of the corefloods were used to assess the capabilities and limitations of a commercial compositional flow simulator in modelling the CWI process. The simulation results show that diffusion should be taken into account to properly model the CWI process at the core scale. Using the commercially available reservoir simulators with the instantaneous equilibrium and complete mixing assumptions would lead to inaccurate evaluation of CWI process at this scale of interest.
Compensated Neutron-Gamma Density for Formation Evaluation, Continuing Field Tests Demonstrate Improvements and New Features
Authors: Reichel Nicole J. , Prabawa Hendrayadi , Mpanzu Antonio , Crowe John
Published: September 2011

Compensated neutron-gamma density (NGD) is a nuclear density measurement that can be made without a chemical gamma ray source. The measurement uses fast neutrons from an electronic pulsed neutron generator (PNG). These fast neutrons penetrate the formation and collide with and excite atomic nuclei. The nuclei rapidly return to their original energy state and emit gamma rays, some of which are scattered back to the detectors. The count rate of detected gamma rays, compensated for fast neutron transport effects, depends on formation electron density.

This new measurement is desirable where operating with a chemical source is prohibited or the risk of loosing the drill string in hole is high. The NGD measurement was first deployed on logging-while-drilling (LWD) equipment to minimize the impact of stuck-pipe events and to provide a density measurement with greater depth of investigation into the formation. The first implementation of the measurement used a ruggedized PNG as a source and a single detector, but the single detector configuration rendered the measurement sensitive to standoff. A caliper input was required to correct this effect, but introduced additional uncertainty. The measurement evolved to a standoff-compensated density using two detectors at different spacings from the PNG. The two detector responses are processed by means of a spine-and-ribs algorithm to correct for borehole effects, much like traditional cesium-based density measurements. This compensated NGD measurement provides standoff- compensated formation bulk density for formation evaluation, without using a chemical source.

The compensated NGD algorithm has been tested on various field datasets. The results are compared against an earlier uncompensated NGD algorithm and traditional gamma-gamma density (GGD) measurements. This paper provides an overview of the current compensated algorithm's advantages and highlights limitations that are currently being addressed through ongoing development.
A Sensitivity Study on CO2 Storage in Saline Aquifers
Authors: Pickup G. E. , Jin M. , Olden P. , Mackay E. J. , Sohrabi M.
Published: September 2011

It is recognised that saline aquifers have the potential to store large quantities of anthropogenic CO2. However, there is much uncertainty in aquifer properties which needs to be evaluated to ensure the safety of CO2 storage.

In the CASSEM Project (CO2 Aquifer Storage Site Evaluation and Monitoring), we have studied CO2 storage in two hypothetical near-shore UK sites. The work was undertaken in three phases (or levels), starting with existing data and simple models and moving on to more complex models as more data became available. The sites had contrasting structures: Site A consisted of simple layers, while Site B was more complex with anticlines and synclines.

Here we focus on the models in Levels 2 and 3. In Level 2, we had geological models, but no laboratory data, so typical values for properties such as relative permeabilities were assumed. In Level 3, the results of laboratory measurements were incorporated in simulations. We modified the Level 2 models in stages, changing one parameter at a time, so that we could evaluate its effect on pressure build-up at the wells, CO2 migration, dissolution and residual trapping. Thus the study formed a valuable sensitivity assessment.

In the models for both sites, the most significant difference between the Level 2 and Level 3 results was the use of the relative permeabilities which had been measured in the laboratory. In the Site B model, where there was more uncertainty in petrophysical properties, a reassessment of the absolute permeability, which led to lowering the average value by a factor of four, also had a large effect. We also assessed multiple realisations of the geostatistical model, and found these had little effect in Model A, but had a large effect for Model B due to pressure building up to the limit for rock failure in wells in low permeability regions.
The Effects of Dynamic Loading on the Sand Management and Permeability of Shape Memory Polymer and Gravel Packs for Sand Management Applications
Authors: Carrejo N.. , Horner D. N. , Johnson S. H
Published: September 2011

Shape memory polymer (SMP) foam is being studied for use in downhole sand-management applications. The process involves machining the shape memory polymer into the desired final geometric shape profile. The shape profile is altered to the desired run-in profile. For reactive sand-management applications, the initial profile is a tubular shape with a diameter greater than the anticipated openhole diameter. The geometric shape is then altered to achieve the desired run-in diameter. When deployed downhole, the shape memory polymer must have good filtration characteristics and adequate permeability to provide efficient sand control without affecting well productivity. Foam permeability should be a minimum of 25 times greater than the formation permeability to minimize wellbore productivity risks. Filtration characteristics should prevent formation sand movement and have a minimal plugging risk.

During oil and gas production, the shape memory polymer provides an initial, minimal contact pressure to help stabilize the borehole. In the scenario of a collapsing wellbore, a dynamic strain test is needed to characterize the resulting effects on the permeability and filtration properties of this shape memory polymer. This paper discusses the development of a filtration test during dynamic loading, and presents the filtration results of shape memory polymer materials and conventional gravel pack techniques during dynamic strain loading.
Use of Zeta Potential to Maximize Sand Free Rate: A New Approach on Sand Control
Authors: Mendez Alfredo , Johnson Dan , Kakadjian Sarkis
Published: September 2011

There are several active and passive methods for controlling the production of formation sand. The main objective is to produce at the maximum sand-free rate without compromising the well’s hydrocarbon production and longevity of the completion system placed. This paper presents a new chemical method and the latest case histories from offshore reservoirs. The new method changes the zeta potential of solid surfaces, thus strengthening attraction between the particles to optimally align proppant, sand particles, fines, or coal fines. Laboratory tests are presented, showing the mechanism of zeta potential and lab tests performed on unconsolidated cores by internal and independent labs. Core flood tests consisted of measuring the permeability before and after the treatment and the formation sand retention. More than 100 jobs have been treated with this chemical solution, with positive and promising results. Operational procedures and recommendations are presented on several wells treated.