bluuebunny/crossref_metadata_2025 huggingface dataset:
Study of the Effect of Different Factors on Nanoparticle-Stablized CO2 Foam for Mobility Control
Authors: Mo Di , Yu Jianjia , Liu Ning , Lee Robert
Published: October 2012

This paper describes a s eries of nanoparticle-stabilized CO2-foam flow experiments performed at reservoir conditions of 20°C and 1200 psig. The generation of CO2 foam was observed in an online sapphire tube. Pressure drop across the core was measured to estimate the fluid mobility and foam resistance factor. Results from the experiments show that stable CO2 foam was generated when CO2 and nanosilica dispersion flowed through a core sample. CO2 foam can be generated with the nanosilica concentration as low as 100 ppm. With the increase of nanosilica concentration, foam mobility decreased and the foam resistance factor increased. It was also observed that the foam mobility decreased with increasing foam quality from 20% to 60% and then increased as the foam quality increased from 60% to 80%. The effects of flow rate on foam mobility indicated that CO2 foam mobility decreased with the flow rate increasing from 60ml/h to 160ml/h.
Sourceless Neutron-Gamma Density SNGD: A Radioisotope-Free Bulk Density Measurement: Physics Principles, Environmental Effects, and Applications
Authors: Evans Mike , Allioli Frangoise , Cretoiu Valentin , Haranger Fabien , Laporte Nicolas , Mauborgne Marie-Laure , Nicoletti Luisa , Reichel Nicole , Stoller Christian , Tarrius Mathieu , Griffiths Roger
Published: October 2012

For many years there has been a need to find an alternative to the radioisotope-based gamma-gamma density (GGD) measurement. The traditional GGD measurement uses the scattering of 662-keV gamma rays from a 137Cs radioisotopic source to determine formation density. A statistically precise measurement requires a 40-GBq or higher source strength and such a logging source, with a 30.17-year half-life, may pose health, security, and environmental risks.

Pulsed-neutron generators have been used in the industry for several decades in wireline tools and more recently in logging-while-drilling tools. These generators produce 14-MeV neutrons, many of which interact with the nuclei in the formation through inelastic collisions. These inelastic interactions are typically followed by the emission of a variety of high- energy gamma rays. Similar to the case of the GGD measurement, the transport and attenuation of these gamma rays is a strong function of the formation density. However, the gamma-ray source is now distributed over a volume within the formation, where gamma rays have been induced by neutron interactions and the source can no longer be considered to be a point as in the case of a radioisotopic source. In addition, the extent of the induced source region depends on the transport of the fast neutrons from the source to the point of gamma-ray production.

Even though the physics is more complex, it is possible to measure the formation density if the fast neutron transport is taken into account when deriving the density answer. This paper reviews the physics underlying the sourceless neutron-gamma density (SNGD) measurement, explains the various facets of the algorithm used for its computation and details the different environmental effects that may influence the measurement.

The successful application of the method is shown in several log examples.
Use of Brown-Field Experimental Design Methods for Post-Processing Conventional History Match Results
Authors: King Gregory R. , Jones Matthew , Tankersley Terrell , Flodin Eric , Jenkins Steve , Zhumagulova Akmaral , Eaton Wanda , Bateman Phil , Laidlaw Chris , Fitzmorris Robert , Ma Xialin , Dagistanova Kymbat
Published: October 2012

Brown-field Experimental Design (ED) was successfully applied to a super-giant oilfield to generate probabilistic (P10, P50, and P90) models to define the range of field performance and to mitigate the non-uniqueness in reservoir simulation. A recent trend in reservoir simulation has been to apply probabilistic modeling, such as, brown-field ED to develop multiple (P10, P50, and P90) models. Unfortunately, these probabilistic models are also non-unique because multiple input combinations can be used to generate the probabilistic responses observed during ED.

The non-uniqueness of the probabilistic models may impact their usefulness in certain circumstances. For example, if these models are used to develop short-term signposts for long-term reservoir behavior, then the models may be influenced by the selection of reservoir data (e.g., a P10 model with one combination of input may have a different short-term "signature" than an alternate P10 model despite giving comparable P10 recovery). Also, the degree of success of a downside-mitigation (or upside-capture) strategy, and its ranking with other such strategies may be influenced by the input chosen to develop the models.

For the super-giant Tengiz oilfield, brown-field ED was applied to a conventional history match with the primary objective of creating probabilistic models. Additionally, we developed tools to design multiple deterministic models with specific physical interpretations. With these deterministic models we can identify the signatures for specific reservoir phenomenon, such as, minimum/maximum OOIP, minimum/maximum compartmentalization, minimum/maximum reservoir energy, etc. All models built with these tools yield acceptable visual and quantitative history matches.

In this paper we discuss how brown-field ED was used to post-process a conventional history match. We present a case study for the use of brown-field ED methods and illustrate the proposed approach to mitigate the non-unique nature of reservoir simulation. While the impact non-uniqueness can be mitigated, we also recognized that it can never be completely eliminated.
Integration of 4D Seismic Monitoring Results as History Match Indicators for Reservoir Simulation
Authors: Ali Amna , Verdiére Sophie , Brechet Emmanuelle , Corpel Vincent , Agar Elodie , Cailly Frederic , Billon Olivier
Published: October 2012

4D seismic has been utilised on several fields for improved reservoir monitoring and management. There have been ongoing efforts to incorporate 4D seismic interpretation results as standard monitoring parameters and encouraging results have been achieved for the integration of this data for reservoir dynamic analysis. This paper presents new methodologies and applications for the use of 4D seismic monitoring inferences as history match indicators for different dynamic realisations.

Matching the historical performance of a reservoir is a time-consuming task with a non-unique solution and hence the inherent uncertainty questions the credibility of forecasted results. Experimental design workflows take into account the influence of multiple parameters and their inter-dependency to assess the impact of the uncertainties on business decisions. The history match quality of a range of realisations has generally been assessed in terms of water breakthrough times, pressures, production rates, FPWD (formation pressure while drilling) data and other monitoring measurements such as PLT (production logging tool) data. As 4D seismic acquisition is becoming a standard monitoring technology for many fields, efforts have been devoted to obtain increased benefit from this data for the history matching process and it is now being used to assess the history match quality of a range of dynamic realisations and improve the response surface modelling.

The monitoring parameters obtained from 4D seismic are case-specific. A turbidite water-flood field is considered here and the match of the simulated vs. observed flood-fronts from 4D seismic are used as a new parameter amongst others to assess the history match of multiple simulation runs. The flood-fronts are obtained as 3D geobodies from 4D seismic attribute interpretation. The interpretations are validated with geology and analytical integration with dynamic data. This validation process is considered essential for the effective application of this methodology.

These workflows show promising results of including 4D seismic based history match indicators and hence hold potential to facilitate the geological model update loop as well as 4D seismic assisted/automated history matching approaches.
Hydraulic Pumping Units Proving Very Successful in Deliquifying Gas Wells in East Texas
Authors: Babbitt Jess A. , Vincent Kenny
Published: October 2012

Fueled by triple-digit oil prices, the unbridled level of activity in the liquids-rich shale plays tends to overshadow issues with base gas production, particularly the continuing struggle to remediate liquid loading and return pressure-depleted wells to production. In recent years, Devon Energy has intensified efforts to maximize base gas production through deliquification of its mature East Texas wells. To that end, the operator has realized tremendous success with artificial lift, which is generating an average 50% rate of return and effectively breathing new life into many of its old and struggling wellbores. More specifically, Devon has focused its efforts on the use of Hydraulic Pumping Units (HPU), which have recorded an amazing track record in deliquifying and returning to production low-rate gas wells that no longer respond to plungers, soap or velocity strings.

This paper describes Devon's experience using HPU to deliquify East Texas wells in reservoirs that vary from very low bottomhole pressure with high permeability to higher pressure with very low permeability and everything in between. The targeted wells range in depth from 5,000 ft to 10,000 ft with wellbores between 2 7/8 to 7 in. diameter. All of these well types have been put on pump and responded very favorably.

The authors will review case histories from several divergent East Texas well types to illustrate the efficiency of pumping units in restoring production to these lower fluid rate wells. The discussion will focus on a newly engineered HPU, which comprises a vertical hydraulic cylinder on the wellhead to reciprocate the rods and pump and offers a number of HSE, operational and economic advantages over conventional pumping units. The specific features that make the HPU a very viable and often preferred alternative to conventional pumping units will be detailed, as will the growing pains and subsequent lessons learned in the East Texas deliquification campaign.
A Method for Improving Chemical Product Risk Profiles as Part of Product Development
Authors: McLean T. , Dalrymple E. , Muellner M. , Garcia-Swofford S.
Published: October 2012

A robust chemical product comparative scoring process (CSP) has been developed that facilitates continuous improvement in human and environmental hazard reduction. The method is simple and quick enough to use during development of new products, is adaptable to changing needs and visually communicates the hazard profile improvements of new products.

The CSP is used during product development. Human and environmental hazard profiles of developmental products are compared to current products used for similar purposes. Since the CSP requires little additional time, it allows hazard profiles to be determined during project development and identifies areas of potential improvement to the hazard profile. The CSP uses specified categories of concern for which public databases exist. For substances that have no database information, US EPA computer models are used. Using the CSP method, hazard profiles of formulations may be improved during the development phase of the project and the results are reported in a visual, qualitative, comparative format.

The CSP has been used to improve the human and environmental hazard profiles of several types of chemical products. This paper will outline how the CSP is used for hazard profile improvement as a part of a development project, reducing delays due to testing or reformulating. The unique visual presentation format of the CSP allows hazard profile improvements over existing products to be easily identified by, and communicated to customers and other concerned parties. The CSP yields the most valid comparisons when data is available for the existing and proposed substances. Computer models are effective if used by personnel trained to use them. The process must include communication with (and validation by) regulatory and toxicology specialists.
Universal Breakers with Broad Polymer Specificity for Use in Alkaline, High-Temperature Fracturing Fluids
Authors: Gunawan S. , Armstrong C. D. , Qu Q.
Published: October 2012

Increased interest in minimizing environmental risk from chemicals has sparked the innovation of new universal breakers for use in high-temperature fracturing fluids. Enzymes have been used for many years in fracturing applications with great success, but their use could be limited due to polymer specificity and thermal stability.

A novel type of breaker system, derived from biological sources and displaying catalytic, polymer degrading activity similar to that of enzymes, was obtained and tested for its ability to reduce the viscosity and molecular weight of polymers used in hydraulic fracturing applications. The universal breakers (UB) are miscible, catalytic, renewable, biodegradable and are not polymer-specific. Additionally, these breakers do not display the thermal denaturation limitations of enzyme breakers, and can thus be used over a much wider temperature range.

Three novel universal breakers were tested for their ability to break the viscosity of various oilfield polymers (guar, carboxymethyl guar, and xanthan) at temperatures of 175, 200, and 225 °F. UB-1 and UB-3 showed rapid catalytic activity at 175, 200, and 225 °F, and reduction in viscosity. UB-2 was more effective at temperatures equal to and greater than 200 °F. Additionally, all UB breakers showed activity against xanthan, with UB-1 and UB-3 being the most effective.

This paper will describe the testing program for the viscosity-reducing ability of three novel universal breakers against both linear and crosslinked high-yield guar, guar, carboxymethyl guar, and xanthan in alkaline and high-temperature conditions. Comparisons of the UB breakers to conventional polymer-specific enzymes and oxidative breaker systems will be discussed. Finally, this paper will include recommendations for field applications, including economic impacts on fracturing fluid systems.
Dynamic Delumping of Reservoir Simulation
Authors: Kuntadi Arif , Whitson Curtis H. , Hoda Mohammad Faizul
Published: October 2012

Integrated modeling is becoming a necessary tool in the petroleum industry to manage the value chain of different models. Reservoir models commonly utilize a simple fluid model to reduce computational time. However, the downstream models often require a more detailed EOS fluid model to perform surface-process facility modeling. This paper presents a dynamic delumping method to generate detailed compositional streams from either black-oil or compositional (lumped-EOS) reservoir simulations, performed as a simple post-processing step.

A set of phase-specific, pressure-dependent split factors are used to perform dynamic delumping. The split factors are generated from simulated depletion PVT experiments using a detailed-EOS model. Delumping is performed phase-wise at the well-connection level, for each time step of the reservoir simulator. For gas injection processes, the amount of injection gas is estimated from stream information and, accordingly, removed from the stream before applying the phase-specific pressure- dependent split factors. Different split factor sets are used when the reservoir model has multiple PVT regions.

We have run many reservoir simulation cases using different production mechanisms and reservoir fluids. Compared with detailed-EOS simulations, the proposed method gives near-exact results for depletion, and excellent agreement in gas injection cases. Dynamic delumping also works with complex fluid systems exhibiting large in-situ compositional (GOR) variations. For injection gas cases, improved accuracy is obtained using a tracer option in the reservoir simulator, to better estimate injection-gas quantity. This approach requires negligible cpu compared with detailed-EOS reservoir simulation.

Dynamic delumping is applied as an automated post-processing for any reservoir simulator. The results of our work provide a key technology for integrating subsurface and surface petroleum models, ensuring greater consistency in the complete value chain and enabling engineers to optimize assets, both locally and globally.
An X-Ray CT Study of Multidimensional Imbibition in Dual Porosity Carbonates
Authors: Alshehri Amar J. , Kovscek Anthony R.
Published: October 2012

Conventional recovery methods (e.g. waterflood) usually recover 50% of the oil in place. This number is even lower in fractured resources where water selectively channels through the fractures towards producers leaving much oil trapped in the matrix. The objective of this work is to investigate the improvement of oil recovery in fractured carbonates at low interfacial tensions (IFT) between oil and aqueous phases while accounting for gravitational effects. Experiments are conducted on cylindrical cores that are surrounded by fractures. The experiments are monitored by an X-ray CT scanner. Images are collected multiple times at each flooding stage to track front movement and quantify local fluid saturation. To achiever our objective, two experiments are needed in two orientations: horizontal (base case) and vertical. This work describes the experimental setup and the base case. In the base case, waterflood then surfactant flood were implemented in a spontaneous imbibition scheme. The waterflood recovered 37% of the original oil in place while the surfactant flood did not recover any oil.
Microvisual Investigation of Foam Flow in Ideal Fractures: Role of Fracture Aperture and Surface Roughness
Authors: Buchgraber Markus , Castanier L. M. , Kovscek A. R.
Published: October 2012

Foam as a gas-mobility control agent is successful in enhanced oil recovery processes. An emerging application of foam is to aid surfactant solution delivery for EOR in heterogeneous porous media. In fractured reservoirs, foam acts as a blocking agent slowing and redirecting the transport of the aqueous phase in high transmissibility fractures. Foam aids the imbibition of foamer/surfactant solution into the matrix blocks so that remaining oil is drained. The design of such foam treatments for fractured media is an important factor for economic as well as recovery success. In this work we investigate the behavior of foam flow in fractures at various foam qualities and liquid and gas velocities. Laboratory experiments with different fracture replicates etched in silicon micromodels were used. Micromodels allow real time observations of flow behavior with a microscope and provide a fracture geometry that is easily replicated. A plain smooth fracture with different apertures (40 μm and 30 μm), a fracture with variable smooth apertures (either 20 μm or 40 μm) arranged in a checkerboard pattern and a constant-aperture fracture with a rough face were used to observe pre-generated foam in terms of texture, pressure drop and flow behavior. Mobility reduction factors for a wide range of foam qualities and flow rates were analyzed. Measured pressure drops increase linearly with an increase in foam quality up to 90%. At qualities greater than 90%, mobility reduction is only slightly reduced further. In general, mobility reduction factors (MRF) of 10-600 times were measured for low to high quality foams, respectively. Additionally video footage of foam at micro and macro scale is used to tie rheology to bubble shape and size. Study results are useful as input for upscaling of the rheology of foam fractures and for ultimate use in reservoir simulations to design effective chemical EOR treatments for fractured media.
Experimental Investigation of Bitumen Recovery from Fractured Carbonates Using Hot-Solvents
Authors: Pathak V. , Babadagli T. , Edmunds N.
Published: October 2012

With the decrease in conventional oil and gas reserves throughout the world and an ever-increasing demand for fossil-fuel based energy and resulting high oil prices, focus has been shifting to unconventional and heavy oil and bitumen. Grosmont carbonates in Northern Alberta have been estimated to contain at least 300 billion barrels of heavy oil or bitumen. However, recovering this oil is extremely difficult because of the complexity associated with carbonate reservoirs in general, e.g., the Grosmont unit is known to possess a triple porosity system – matrix, fractures and vugs, based on core studies. The second problem is the fluid itself, which is highly viscous bitumen, immobile at reservoir conditions. To extract this bitumen from very heterogeneous carbonate rock, both heat and dilution using solvents may be needed. This paper reports the results and analysis of hot solvent experiments conducted on original Grosmont carbonate cores.

Three experiments were conducted using propane and one using butane as solvent. After heating the entire system containing the core sample, solvent gas was injected. The rock was allowed to soak in the hot solvent for a long time. The experimental temperature and pressure were decided on the basis of the results of our earlier work that suggested to be just above the saturation line of the particular solvent.. An attempt was made to keep the conditions close to the saturation conditions of the solvent being used to maximize the dilution and hence, the recovery. The oil produced was analyzed for viscosity and asphaltene content. The results in terms of recovery, the degree of dilution and upgrading achieved suggested that butane was a better solvent for this bitumen. Finally, the optimum conditions for operation of the hot solvent process were verified for Grosmont carbonates.
Laboratory Study of Velocity Variations during CO2 Flooding in Tuscaloosa Sandstone
Authors: Mohapatra Avinash , Rai Chandra S. , Sondergeld Carl H. , Richards Trevor
Published: October 2012

Surface seismic offers a promising technique to monitor CO2 flood fronts during enhanced oil recovery process. Changes in seismic signature have been observed with CO2 flooding but quantification of the seismic signature with respect to subsurface saturation is still in its infancy. This study is focused on quantification of the variation in seismic parameters (velocity and impedance) with the change in subsurface fluid type and saturation.

The results of a laboratory study are presented where velocity and density were monitored as the pore fluids (formation brine and oil, and CO2) are replaced sequentially. All the experiments were performed at in-situ pressure conditions on plugs (Tuscaloosa sandstones) recovered from a well in a field currently undergoing CO2 flooding. The plugs used are characterized as fluvial (quartz~87%, clay~10%) and distributary channels (quartz~75%, clay~17%).

During brine flooding on dry samples, a decrease in P-wave velocity (~2%) was observed till 95% saturation and thereafter the velocity increases by 15% during the remaining 5% saturation. After attaining 100% brine saturation, oil was pumped to displace brine till irreducible water saturation was achieved. A linear drop of 4% in velocity was observed during this step. Liquid CO2 was injected to displace oil-brine system and a drop of 8% in P-velocity was observed. Associated changes in P-wave impedance due to change in pore fluid saturation are 25%, -5% and -8% respectively for the three flooding experiment. Biot-Gassmann modeling shows good agreement with experimental results for gas-brine and oil-brine system but not for liquid CO2 flooding.

4D seismic data set acquired over the same region is quantitatively interpreted based on these laboratory measurements.
Sourceless Neutron-Density Porosity Determination: Fit-for-Purpose Formation Evaluation with Significant HS&E Benefits
Authors: Gjerdingen Tore , Hilton Joseph , Bounoua Noureddine , Irani Farzad , Fulton Chuck , Rodriguez Rubi
Published: October 2012

Chemical radioactive sources are commonly deployed in logging-while-drilling (LWD) assemblies to measure formation bulk density and neutron porosity. These measurements are widely used in porosity evaluation, lithology determination, clay volume estimates and fluid identification. Deploying logging tools with chemical sources poses Health, Safety and Environment (HS&E) risks requiring specific procedures throughout the entire process of planning, logistics and execution of well construction. Obtaining similar, identically equal or better formation bulk density and neutron porosity measurements without chemical sources has many advantages, particularly from the HS&E perspective in both standard and high-risk developments.

Advances in LWD technology have enabled the neutron porosity measurement to be obtained by employing an electronic neutron generator instead of a chemical source. These electronic neutron generators have been used for many years in different wireline tools and are now also available in LWD tools. The bulk density measurement has, until recently, only been measured utilizing a chemical source. Recent developments use the gamma rays induced by the interaction of high-energy neutrons (from the electronic neutron generator) with the formation as an "in-situ" source for subsequent derivation of bulk density.

Studies of the sourceless neutron-gamma-density (SNGD) data acquired in 15 to 20 horizontal and vertical wells have shown the accuracy obtained is within the specified limits, as compared to the traditional gamma-gamma-density (GGD) data. The typical density differentials observed in these environments are in the 0.01 to 0.02 g/cm3 range, which results in a porosity and saturation "error" in the order of 0.002 to 0.004 V/V. This level of accuracy is probably acceptable in a number of applications (e.g., infill drilling in mature fields), but may not be acceptable in other scenarios (e.g., more complex lithologies, extremely tight reservoirs), unless the HS&E considerations are overriding.

The HS&E benefits are important to keep in focus as they have a direct human benefit through the entire process of equipment preparation, transportation, wellsite operation and potential bottomhole assembly abandonment. Associated with this there is also the economic benefits related to less rig time required for source handling, and the potentially large savings in a lost-in-hole (LIH) abandonment scenario, in the locations where this is applicable. All these different aspects, HS&E, financial and technical, associated with the SNGD system need to be evaluated from a holistic viewpoint to ensure the most appropriate, fit-for-purpose acquisition program is selected in each case.
SmartWater Flooding: Industry's First Field Test in Carbonate Reservoirs
Authors: Yousef Ali A. , Liu Jim , Blanchard Guy , Al-Saleh Salah , Al-Zahrani Tareq , Al-Zahrani Rashad , Al-Tammar Hasan , Al-Mulhim Nayef
Published: October 2012

In recent years, improved/enhanced oil recovery by tuning the ionic composition of injection water has attracted the attention of the petroleum industry, and currently deemed as new emerging research trend.

In view of research results for the last four years, we demonstrated in previous reports (SPE 137634; SPEREE Journal, vol. 14(5), pp. 578-593; SPE 143550, SPE 141082, SPE 154076; SPE 154077) that substantial oil recovery beyond conventional waterflooding from carbonates can be achieved by optimizing the salinity and ionic composition of field injection brine. Similar potential has been confirmed also in the secondary recovery mode. For recovery mechanisms, research confirmed that the driving mechanism is wettability alteration of carbonate rock surface and can be attributed to surface charges alteration, and microscopic dissolution of anhydrite. In this paper, we present the results of two field trials conducted in a carbonate reservoir to demonstrate the SmartWater Flood potential.

Both field trials confirmed that in-house research results can be replicated at field scale. Injection of SmartWater revealed a reduction of ~7 saturation units in the residual oil beyond conventional seawater. Considering these field trials are the first-ever applications in carbonate reservoirs, they further provided another confirmation that SmartWater Flood has significant potential to be a new recovery method targeting carbonate reservoirs. A special type of single-well chemical tracer was used in these trials to measure the residual oil in the vicinity of the well following the injection of each water type. During all stages of field trials, careful QA/QC program was put in place to monitor variation in ionic composition in all injected or produced fluids and further insure optimum ionic composition of SmartWater slugs. Several field trials are planned to optimize the current process leading to a multi-well Demonstration Pilot to determine the impact on ultimate recovery and reserves.
Stimulated Shale Volume Characterization: Multiwell Case Study from the Horn River Shale: II. Flow Perspective
Authors: Ehlig-Economides Christine A. , Ahmed Ibraheem , Apiwathanasorn Sippakorn , Lightner Jacqueline , Song Bo , Vera Fabian , Xue Han , Zhang Yannan
Published: October 2012

Characterization of shale gas stimulation and production mechanisms is of paramount importance to continued horizontal well hydraulic fracture stimulation design and execution. This study integrates analyses of fracture calibration tests, hydraulic fracture treatments, production logs, pressure buildup and well interference transients, and long term production data to quantify hydraulic fracture extent, shale permeability, and the expected ultimate recovery.

The study includes integrated analysis of 16 horizontal wells drilled from a pad in two opposing directions with mostly uniform length and spacing. Uncertainties in the hydraulic fracture and formation properties are reduced through rigorous modeling with analytical and numerical models. Results enable critical analysis of the shale development plan.

Recommendations from this study offer insight on stimulation design modifications to yield improved well performance and increased recovery efficiency within the pad stimulated volume defined by the wells.
Closed-loop Feedback Control in Intelligent Wells: Application to a Heterogeneous, Thin Oil-Rim Reservoir in the North Sea
Authors: Dilib F. A. , Jackson M. D. , Mojaddam Zadeh A. , Aasheim R. , Årland K. , Gyllensten A. J. , Erlandsen S. M.
Published: October 2012

Important challenges remain in the development of optimized control strategies for intelligent wells, particularly with respect to incorporating the impact of reservoir uncertainty. Most optimization methods are model-based and are effective only if the model or ensemble of models used in the optimization capture all possible reservoir behaviors at the individual well and completion level. This is rarely the case. Moreover, reservoir models are rarely predictive at the spatial and temporal scales required to identify control actions. We evaluate the benefit of using closed-loop control strategies, based on direct feedback between reservoir monitoring and inflow valve settings, within a geologically heterogeneous, thin oil-rim reservoir. This approach does not omit model predictions completely; rather, model predictions are used to optimise a number of adjustable parameters within a general direct feedback relationship between measured data and inflow control settings. A high-resolution sector model is used to capture reservoir heterogeneity, which incorporates a locally refined horizontal grid in the oil zone, to accurately represent the horizontal well geometry and fluid contacts, and capture water and gas flow. Two inflow control strategies are tested. The first is an open-loop approach, using fixed inflow control devices to balance the pressure drawdown along the well, sized prior to installation. The second is a closed-loop, feedback control strategy, employing variable inflow control valves that can be controlled from the surface in response to multiphase flow data obtained downhole. The closed-loop strategy is optimized using a base case model, and then tested against unexpected reservoir behavior by adjusting a number of uncertain parameters in the model but not re-optimising. We find that closed-loop feedback control yields positive gains in NPV for the majority of reservoir behaviours investigated, and higher gains than the open-loop strategy. Closed-loop control can also yield positive gains in NPV even when the reservoir does not behave as expected. However, inflow control can be risky, because unpredicted reservoir behavior also leads to negative returns. Moreover, assessing the benefits of inflow control over an arbitrarily fixed well life can be misleading, as observed gains depend on when the calculation is made.
Investigation of Anisotropic Mixing in Miscible Displacements
Authors: Adepoju Olaoluwa O. , Lake Larry W. , Johns Russel T.
Published: October 2012

Dispersion (or local mixing) degrades miscibility in miscible flood displacements by interfering with the transfer of intermediate components that develop miscibility. Dispersion, however, can also improve oil recovery by increasing sweep efficiency. Either way dispersion is an important factor in understanding miscible flood performance.

This paper investigates longitudinal and transverse local mixing in a finite difference compositional simulator at different scales (both fine and coarse scale) using a two-dimensional convection-dispersion model. All simulations were of constant mobility and density, first-contact miscible flow. The model allows for variations of velocity in both directions. We analyzed local (grid-block) concentration profiles for various miscible displacement models with different scales of heterogeneity and permeability autocorrelation lengths. To infer dispersivitiy we fitted an analytical two-dimensional convection dispersion model to the local concentration profile to determine simultaneously local longitudinal and transverse dispersivities. Streamlines of simulation models were traced using the algorithm proposed by Pollock (1988). To our knowledge this is the first systematic attempt to numerically study local transverse dispersivity.

The results show that transverse mixing, which is usually neglected in the one-dimensional convection dispersion model of dispersion, is significant when the flow direction changes locally as a result of heterogeneity. The computed streamlines, which highlight the variation in flow directions, agree with the computed transverse dispersivity trends. We find that both transverse and longitudinal dispersion can grow with travel distance and that there are several instances in which transverse dispersion is the larger of the two.

Often, the variations in the streamlines are suppressed (homogenized) during upscaling. This paper gives a quantitative and systematic procedure to estimate the degree of transverse mixing (dispersivity) in any model. We conclude that local mixing, including transverse mixing should be considered when upscaling a fine scale model for miscible displacement to ensure proper preservation of fine-scale sweep and displacement efficiency and ultimate oil recovery for miscible displacement simulations.
Continuous Incremental Reserves in an Oil Rim Marginal Field Development through Integrated Technical Initiatives and Technology Advancements
Authors: Masoudi Rahim , Karkooti Hooman , Othman Mohamad B. , Altunbay M. Mehmet
Published: October 2012

Oil rim reservoirs are commonly marginal reserves with challenging drive-systems with high development cost and, therefore, are commercially less attractive. Development evaluation of such complex fields with the conventional methodologies and technologies may result in unsuccessful scenarios. The studied field, located in offshore Peninsula Malaysia, is a marginal oil rim reservoir with the oil column less than 42 ft with limited oil-in-place. The field was initially evaluated as a challenging development and a non-commercial asset. However, the integration of various technical initiatives and applying new interpretive techniques turned the field into an attractive asset and reserves have been continuously upgraded since the field development started.

The field was undergone proactive phasing development and reservoir management with a fit-for-purpose monitoring plan. The development strategy with long horizontal wells (i.e., up to 2 km) and smart completion with inflow control devices was matured through the development phasing and well-by-well performance evaluation. Various tracer applications with the PLT campaign in the long horizontal wells pre/post water-breakthrough (WBT) were used to justify the long horizontal wells. Well placements relative to contact were progressively improved allowing the delay in WBT and increasing the RF. Production rate, draw-down and GI/GP were continuously optimized pre/post water/gas break-through. Simulation model incorporated robust modeling of flow dynamics of the oil intervals in the capillary transition zone and long horizontal wells with smart completion modeling using the segmented well approach.

The applied development strategies together with the proactive reservoir management made the field development as a record successful case in Malaysia. The recovery factor progressively increased from earlier 16% to 35% presently. In this paper, suggested workflow, guidelines and key tasks with the field data and the results are presented and discussed for the studied field.
Calculation of Average Reservoir Pressure during Primary and Secondary Recovery and Under Variable Boundary Conditions
Authors: Dastan A. , Kamal M. , Collins J. R. , Neubauer E. B.
Published: October 2012

A new method is introduced to calculate the average reservoir pressure around wells from pressure buildup or falloff tests regardless of the shape of the drainage area or the types of boundaries surrounding it. Practicing engineers can apply the proposed method using any of the widely available Well Testing programs. Average reservoir pressure is used in just about all reservoir engineering studies conducted via simulation, material balance, or even decline curve analysis. Existing techniques, such as the Matthews-Brons-Hazebroek (MBH) method (1954), are valid for limited drainage shapes and boundary conditions. In particular, they cannot handle secondary recovery projects (waterflooding, steam injection, etc.), or irregular drainage shapes which are routinely used in the industry. As a result, typically the value of p* is used as a substitute for average reservoir pressure, which may result in significant error.

The new method enables petroleum engineers to calculate the average reservoir pressure accurately for every reservoir type by integrating transient, production, and static data. Our technique calculates a robust approximation of the drainage area based on the production/injection history for each well in the reservoir. A given well may be offset by other injection and production wells and no-flow and/or constant-pressure boundaries, all of which are taken into account for estimation of the drainage area. Our technique also accounts for areal variations in reservoir thickness and depth. The size and shape of the drainage area directly impacts the average pressure characteristics, which can be calculated with the help of relatively simple runs using a reservoir simulator. The results are generalized by creating type curves similar to the MBH type curves for each well in the reservoir.

The new method was applied to several wells in a large oil field offshore Nigeria with the methodology and results presented in this paper. The new technique enables us to calculate the average reservoir pressure accurately for every reservoir type, all drainage area shapes and boundary conditions, a variety of production patterns, and for multiphase flow conditions. It is difficult to overestimate the value of properly calculated average reservoir pressure. It is one of the main parameters used to history match field data. It affects multiple drilling and production optimization decisions like, infill drilling, mud pressure, and determining flow rates of producers and injectors. With accurate average reservoir pressure, optimization of field management is possible by determining the number and the locations of infill wells, the level of injection and production from different wells, and other reservoir performance related decisions. The new method significantly improves our ability to produce valid values of average reservoir pressure.
Optimization of Coiled Tubing Extended Reach Practices in the Bakken Region: A Case Study
Authors: Griffin John , Nichols Chris
Published: October 2012

Wells in the Bakken formation of the Williston Basin are currently being drilled in excess of 20,000 ft. measured depth with horizontal sections often exceeding 10,000 ft. in length. Due to current coiled tubing (CT) operational limitations, such as premature lockup, multiple zones at the toe are often left stimulated but possibly flow restricted due to unmilled frac plugs or ball seats. Technological advancements in friction reducers, downhole tools, and string design have greatly improved the industry's methods of decreasing mechanical drag, enabling coiled tubing to reach greater depths. With current pre-job modeling software, expected depths can be simulated but, due to lack of knowledge regarding technical operating parameters, results are inconsistent with field data, leaving operators unsure as to whether zones will be left behind.

This case study was conducted as a sensitivity analysis to provide operators and service companies with a means to measure the effectiveness of current extended reach practices and tools.

A field trial case history for a number of similar wells was performed comparing differences in actual versus predicted modeling of surface weights and maximum depth before reaching lockup. Preliminary results show average gains of 10% in extended reach with the use of downhole water hammer tools (WHT) and frictional drag reducers. A 50% reduction in circulating pressure has been obtained, extending coiled tubing fatigue life. Additionally measuring lubricity in the flowback fluids at surface provides an indication of fluid performance.

This case study, which is based on field results and empirical analysis of over 40 wells, outlines a method to more accurately forecast CT lockup depths when running WHT or pumping friction reducers. This is enabled through greater understanding of the WHT or friction reducer that is being applied. From this study, operators and/or service companies can develop operating guidelines to help achieve maximum milling efficiency based on technical information provided.
A Distributed Microchip System for Subsurface Measurement
Authors: Yu Mengjiao , He Sufeng , Chen Yuanhang , Takach Nicholas , LoPresti Peter , Zhou Shaohua , Al-Khanferi Nasser
Published: October 2012

A revolutionary cost-effective "Microchip" system capable of measuring temperature and pressure over the entire wellbore was developed and tested in the field. The Microchip system includes two major components: the surface devices and the "tracer." A tracer (~7.5 mm in diameter) consists of fiber optic sensors, a SoC IC (System-on-Chip, which includes microcontroller, memory, transmitter and receiver circuits) and a battery, all encapsulated in a protective chemical coating shell. The surface devices include an "initiator" to reset the circuit of the tracer and a "data collector" to retrieve data from the tracer using wireless communication. When used in the field, tracers will be injected together with the drilling fluid. As the tracer travels through the wellbore, it will measure the temperature and pressure through the entire wellbore and store the data in the on-chip memory. When the tracers are carried out of the borehole by the drilling fluid, a "data collector" will communicate with the tracer to download the data stored in the on-chip memory on the tracer. Thirteen tracers were injected in an 11,050ft well and circulated with a 13ppg mud at 400-500gpm. After travelling about 6.6km in the 8-3/8 inch wellbore to a depth of 11,050 ft, seven tracers returned to the surface successfully. The first tracer returned to the surface after 57 min. Data recorded on the tracer shows a bottom hole pressure of ~7500psi and flowing bottom hole temperature of ~190 degrees Fahrenheit. Results are consistent with the static bottom hole pressure and temperature. The Microchip system can be used for subsurface measurement or as a diagnostic tool for identifying problematic zones. As an open platform, the Microchip system could also be expanded to other measurements by using different types of sensors. This Microchip system can be used in drilling and completion, pipeline monitoring and many other applications.
Removal of Sand Control Screens and Bottom Hole Assembly in Cased Hole Gravel Packed Wells in Chad, Africa
Authors: Nandogongar Alladoum , Soulanoudjingar Stephane D. , Driver Delbert , Mayfield Gary , Kamps Jake , Jimenez Manuel , Anderson Robin
Published: October 2012

The fields operated by Esso Exploration and Production Chad Inc. (EEPCI) in a consortium project with PETRONAS and Chevron in Central Africa, target highly unconsolidated sandstone formations. Sand control equipment must be utilized to prevent production of sand resulting in failure of downhole and surface equipment. Screens can erode as a result of "hot spots" where fluid velocities have increased considerably, allowing sand entry into the wellbore causing the subsurface equipment to fail and decrease production. With high drilling costs, and the limited amount of surface space, it has become critical to repair the more prolific of these damaged wells.

This paper provides an overview of the development and utilization of various failed sand control equipment removal and replacement techniques for workovers. Screen removal poses challenges not typically encountered when pulling other bottom hole assemblies from the well. The team has utilized existing available equipment and modified tools to address these unique challenges during workover operations.

Initial attempts to pull sand control equipment required weeks of rig time and met with limited success. Packer release tools were not always effective, and milling over these packers proved problematic. Additionally, long screen sections were difficult to pull. Learnings from each workover operation were incorporated until the optimum methods were eventually identified. Also, tools were modified resulting in time and cost efficiencies.

Additionally, a systematic approach of selecting the best candidates for repair was developed, taking into account various wellbore complexities such as age, type of completion, length of the bottom hole assembly, among others. Each complexity is weighted based on previous pulling experiences as well as taking into consideration the total volume of oil to return to production.

Since June 2009, 15 gravel pack failures were repaired, and wells returned to production utilizing these evolving and improving techniques. This represents over 5,300' of pulled screens. The first successful repair (June, 2009) required 20 days to complete. Applying learnings and improved techniques, the average repair time has decreased to 9.5 days (one at 6 days), with an average 40% of cost reduction; 60% to 70% less than the cost of a new drillwell.