bluuebunny/crossref_metadata_2025 huggingface dataset:
Deep Water Gas Fields Intervention Using WROV
Authors: Labib AbdelRahman
Published: December 2007

In the last few years, there has been a significant increase in gas production to meet the global energy demand. To date, most of the recoverable gas potentials are situated in offshore concessions, and mostly in deep water. Therefore, the need to consider the environmental and technical challenges to establish and maintain any offshore gas production facility are important to the success of the field development and operation.

The use of remote technology has been used in the subsea sector of the oil and gas industry for many years; however, the scale at which it has been used in the past against the needs for the future is becoming a major consideration to the development and operation to any subsea gas production fields. Remotely Operated Vehicles (ROV) is one of the most advantageous remote tools to any deepwater operation. Introduced to the offshore industry over 25 years ago the ROV has developed from a simple observation vehicle into a sophisticated underwater work platform (Work Class ROV) reaching depths of 4000mtrs and beyond. The numbers of tasks that WROV can perform cover are many and varied and are referred to as "ROV intervention operations". Typical examples of intervention tasks are subsea production system; valve actuation, component replacement, control umbilical connection. With the majority of these tasks undertaken by the ROV, and some intervention tool specifically designed for the task.

Intervention accounts for 2 – 3 % of the total cost of offshore oil production, it frequently paces other operations on the critical path during oil field construction and operation because the operation of very costly equipment (such as supply vessels, drill rigs, and derrick barges) depends on the success of ROV operations. Making these operations more efficient and reliable will produce a large cost saving ripple effect throughout the aspects of the offshore operation.
Integrated Approach for Seismic Fracture Characterisation for Improved Reservoir Performance
Authors: Angerer Erika , Lanfranchi Pierre , Pharez Stephen , Rogers Stephen
Published: December 2007

The flow properties of fractured reservoirs are highly dependent on the prevailing fracture characteristics. A detailed knowledge of these subsurface patterns is therefore crucial for optimising reservoir production and performance. Fracture information is available at a wide range of scales. At one end, there are structural interpretations and basin models that describe faulting on a kilometer scale and at the other end, downhole measurements (borehole image logs) and core samples which provide fracture characterisation on a centimeter scale. Fractures of all lengths are created by regional tectonic stresses and therefore have comparable characteristics, such as orientation and density, regardless of scale.

The seismic method records reflections that exhibit azimuthal variations in amplitudes and traveltimes in the presence of fractures. Thus the gap between faults and micro features is bridged by sub-seismic fracture characterisation from azimuthal anisotropy (Rüger, 1998, Bakulin, et. al., 2000). An integrated workflow is presented that reconciles all available geological, geophysical and engineering information to build unified and consistent fractured reservoir models.
Residual Oil Saturation Analysis of The Burgan Formation in the Greater Burgan Field, Kuwait
Authors: Al-Sabea Salem , Bean Clarke , Crowe John
Published: December 2007

Residual Oil Saturation (Sorw) is a critical reservoir model parameter for evaluating reserves in the Greater Burgan Field. Past Sorw studies in Greater Burgan Field either looked only at core test data, or only looked at cased-hole log data. None of the past studies considered areal position, different rocktypes, or changes in remaining oil saturation with varying amounts of water sweep.

This study includes analysis of Sorw from open-hole water saturation, Time-Lapse PNC data and Special Core Analysis water flood experiments.

The majority of the log data in Greater Burgan Field water –swept zones are concentrated in the 3rd sand middle, 3rd sand lower and 4th sand formations. The comparisons of the results from all three methods used in the study to measure remaining oil saturation (ROS) are limited to these reservoirs.

Results from these methods were remarkably consistent.

All reservoir sand with extensive PNC log data showed that zones encroached by water for 22+ years tend to be at or near residual oil conditions. Measurements in the zones with water encroachment for less than 22 years have about a 50% chance of being incompletely swept. Analysis of the 22+ year data allowed reasonable ranges of Sow were estimated from this data.

Investigations of ROS spatial variations in the Magwa, Ahmadi and Burgan sub-fields were made. 3rd sand middle was the only reservoir with both adequate PNC and open-hole coverage in ROS from these three areas in Greater Burgan Field.

ROS by rocktype was reviewed in three categories of reservoir rock (excellent, medium and poor quality reservoir) as currently defined by log analysis in Greater Burgan Field. The vast majority of log data occurs in rocktype 1, the highest quality reservoir rock. Only 3rd sand lower formation contained sufficient data in all three reservoir quality rocktype to make valid comparison. Both core flood Tests and PNC Time-Lapse methods also showed no difference in ROS based rocktype.
Comparison of Permeability Predictors from NMR, Formation Image and other Logs in a Carbonate Reservoir
Authors: Hassall J. K. , Ferraris P. , Al-Raisi M. , Hurley N. F. , Boyd A. , Allen D. F.
Published: December 2007

An extensive petrophysical analysis has been carried out on a study well in a giant carbonate field in the Lower Cretaceous of Abu Dhabi. The well was cored, and a comprehensive log suite recorded including: Nuclear Magnetic Resonance (NMR), Borehole Imaging, Shear Sonic and Mineral Spectroscopy in addition to the more normal logs.

A high-resolution permeability profile was measured on the core. Plugs taken every foot were supplemented by minipermeameter measurements every inch. While this profile captures high frequency variability it is limited in its applicability to predicting reservoir behavior. Analysis of large scale flow unit permeability is better assessed with dynamic data.

A number of advanced log based permeability estimators were developed in an attempt to match the core permeability profile. The estimators are based on NMR, image analysis and Stoneley measurements among others. This paper presents a comparison of these predictors to the core and makes recommendations as to the preferred permeability prediction methods for this field.

For this well the Stoneley permeability correctly predicted a trend decrease of permeability with depth but failed to honor the full extent of the trend. As expected, given its vertical resolution, it also failed to respond adequately in the more heterogeneous intervals.

A method based on a mean NMR T2 measurement gave a good general match to the data, but again lacked vertical resolution. An electrical image based method brings an important improvement in sensitivity to the small-scale variations in permeability, but in some places failed to follow the lower frequency trends.

A composite method using the NMR to supply the overall trend, and the image to provide the higher resolution, gave the best match to the core permeability profile available from the tool suite, which was run. The method is a modification of the well-established SDR permeability equation. A new term is introduced to account for the contribution of connected vugs, which are responsible for the high permeability intervals in this well.

The logs used in the methods described here do not make direct measurements of permeability. Instead permeability is inferred indirectly from measurements sensitive to parameters such as texture and pore size. It is doubtful that a single methodology based on such measurements can provide a "universal" permeability estimator fitting all cases. The methods presented here should be applied with care and will benefit greatly from calibration to spot permeability data.

The method has particular application in high cost environments where a good permeability is required along the wellbore but the cost and rig time required for continuous whole coring cannot be justified.
Underbalanced Drilling; Remedy for Formation Damage, Lost Circulation, & Other Related Conventional Drilling Problems
Authors: Qutob Hani
Published: December 2007

Almost every drilling operation is a potential source of damage to well productivity, lost circulation, differential sticking and other related conventional Drilling problems.

This paper re-visits the key damage mechanisims and provides a broad overview on how they occur during various oilfield operations, and their effect on well productivity. Also, lost circulation or fluid invasion potential in high permeability zones, large open fractures, heterogeneous carbonates with massive interconnected vugular porosity, or pressure depleted zones would be a major issue of concern during conventional drilling condition. The worst-case scenario would be a combination of one of these high permeability features with significant pressure depletion.

In order to overcome the above problems while drilling, the industry developed a method to drill with a bottom hole pressure below the pore pressure, called Underbalanced Drilling – UBD

As the majority of hydrocarbons being exploited today are found in existing pressure depleted or complex and lower quality Reservoirs with lots of the conventional drilling problems, this is where Underbalanced Drilling Technology can add value and in some cases reduce development cost. Soon, Underbalanced Drilling will become the standard field development technique, both Onshore and offshore, where the Geology and Reservoir are suitable.

The paper reviews several case histories and real results highlighting the advantages of Underbalanced Drilling Technology in reducing Formation Damage, Lost Circulations and improving well productivity.
Evaluation of IOR Potential within Kuwait
Authors: Al-Bahar Mohammad A. , Merrill Robert , Peake William , Jumaa Mohammed , Oskui Reza
Published: December 2007

Kuwait's production to date is characterized by large, massive reservoirs undergoing natural depletion with the help of strong natural aquifer drives. In a few fields, natural aquifer support is supplemented by pattern or peripheral waterflood. However, there has been no systematic attempt to define the Improved Oil Recovery (IOR) potential within the country. This study is a first attempt to assess this potential. The study considered 10 IOR displacement processes, suitable for long-term implementation within Kuwait. These processes included waterflood (including chemical floods), gas injection processes, and thermal methods. The study did not consider techniques based purely on well stimulation or infill drilling (e.g. cyclic steam injection, or horizontal well development); the potential for these techniques is already well understood and considerable data already exists for planning around these options. The study focused on screening reservoirs and identifying IOR processes for further study.

The screening was in two parts. The first part was an evaluation of process suitability for all reservoirs. The second part was a ranking of IOR opportunities by reservoir. In total, over 800 process/reservoir combinations were evaluated. The evaluation process made use of various industry criteria; however, these were modified to better reflect conditions within Kuwait. After screening for suitability, the reservoirs were ranked in importance for future study. This ranking included: incremental oil recovery, crude quality cost per barrel and urgency (timing). This ranking will be used to direct resources at particular projects for further study and, if positive, future implementation. Key technical contributions of this work include: data evaluation techniques, consistent ranking of reservoirs with varying degrees of risk, development of scoping economic models for preliminary project assessment.
Transient Behavior of Annular Pressure Build-up in HP/HT Wells
Authors: Oudeman P. , Kerem M.
Published: December 2007

Pressure build-up due to fluid thermal expansion in sealed annuli of HP/HT wells can have serious consequences such as casing failure or tubing collapse. To determine whether mitigation was required for a HP/HT development, annular pressures in an appraisal well were studied with a dedicated field test, which consisted of running a pressure/temperature memory gauge in a casing/casing annulus of a well and testing the well several times during a 3-month period, after which the gauge was retrieved and the data were read out.

First of all, comparison of the magnitude of the observed annular pressures with the burst and collapse ratings of the casings, shows that annular pressure build-up is a serious consideration in casing design. Such design is to be based on theoretical models for annular pressure build-up. The data acquired with the test serve to validate these models.

The data demonstrated that in the lower temperature range (20 to 40 °C), on average, pressure development in the annulus agreed reasonably well with theoretical model predictions, based on thermal expansion of the annular fluids and casings, and ballooning and compression of the casing strings. The influence of these factors could be established by analyzing the transient pressure response of the annulus. At higher temperatures the theoretical models overestimate pressure build-up. This is probably to be attributed to the properties of the completion fluids differing from the properties of the base fluid, water. Estimates on the basis of pure water properties can be considered a worst-case estimate for pressure build-up.

Leak-off of the annular fluids, which was seen to dominate pressure development during a previous test in a well with a cement shortfall between casings, did not play a significant role in this fully cemented and sealed annulus.
Multiphase flow meters (MFPM) – Field trials and their applications in fields
Authors: Bekkousha Miloud , Khoory Ahmed , Metwalli Magdi , Jawahiri Hamza Al , Sakaria Dipak , Rajabi Shehta Al
Published: December 2007

Abu Dhabi Company for Oil Operations (ADCO) UAE have been field testing and assessing the multiphase flow meter (MPFM) technologies as an alternative well testing tool for the past decade.

Currently, there are not any governing industry standards existing for the MPFM technology. Commercially available industrial MPFMs each apply their own unique technology and principle, which are sensitive to the fluid properties and flow regimes, which ultimately dictate the final MPFM reading. Every reservoir has its own characteristics and behavior, which changes with time and ultimately affects the MPFM measurements. Hence the selection of the MPFM suitable for its exclusive application is critical.

In order to implement and apply with confidence the MPFM technology and achieve optimal results, field trials are necessary for both the operator and the engineer. The field trials will further develop the knowledge (its limitation, potential and its behavior) of each of the MPFM's technologies available in the market.

This paper describes ADCO's experience and the methodology that was applied for the selection of MPFM and there upon its accuracy, reliability and its performance to develop confidence of the application and its usage.
South-Pars Phases 2 and 3: The Kinetic Hydrate Inhibitor (KHI) Experience Applied at Field Start-up
Authors: Glénat Philippe , Peytavy Jean-Louis , Holland-Jones Nick , Grainger Martin
Published: December 2007

South-Pars Phases 2&3 development in Iran is a "wet scheme" base design: no process is performed offshore, all the produced fluids (sour gas + condensate + water) are directly sent to shore through two 32" 109 km long sea lines. Corrosion and hydrate protection is based on buffered glycol (MEG+MDEA) which is regenerated onshore and sent back to the platforms through two 4½" piggyback lines.

The concomitant injection of a Kinetic Hydrate Inhibitor (KHI) and a Corrosion Inhibitor (CI) was initially considered as a back-up solution. This paper presents the field experience with KHI and CI injection which had to be applied for the field start-up during respectively 125 days and 80 days for each sea line.

This case represents the first large field application of KHI in the Middle-East and the potential of such Low Dose Hydrate Inhibitor (LDHI) is underlined.
Practical Flow Simulation Method for A Naturally Fractured Reservoir: A Field Study
Authors: El-Abd Salem , Al-Deeb Maged , Abdou Medhat , Linthorst Steef , Bahar Asnul , Kelkar Mohan
Published: December 2007

This paper presents the methodology, implementation and results of dynamic modeling of a naturally fractured carbonate reservoir, which consists of fracture swarm system and high matrix permeability. The focus of this paper is on the description of the dynamic single media model that was used to history match the historical production. The challenges in properly quantifying the separate effects of matrix and fracture within the framework of single media model become the major objective of the study. Brief description of the static model that consists of development of matrix and fracture models, as well as the method to integrate them, are also presented.

Both matrix and fracture systems play an important role in the production mechanism of the reservoir. History matching for twenty years of production was successfully done in a single media model through an iterative process between static and dynamic models to ensure the consistency between the two models. Different sets of relative permeability curves (for matrix and fracture systems) were generated to properly simulate the fluid movement in the reservoir.

The results indicate an excellent history match that is also followed by the success in the blind tests of newly drilled wells. Significant improvement was obtained compared to the previous model in simulating water production that comes from the aquifer to the wells through a complex fracture network. The results were achieved through various sensitivity analyses of fracture conductivity and by fine-tuning of relative permeability curves that are based on the eight rock types defined for the reservoir.

In conclusion, the single media model used in this study can successfully simulate the behavior of a naturally fractured reservoir. The model has shown that it can produce excellent results in a very practical way.

The methodology described in this paper is suitable for other naturally fractured reservoirs, especially in the Middle East Area where significant difference between core-derived permeability and the well-test derived permeability exists.
New Software Tool Improves Fractured Reservoir Characterisation and Modelling Through Maximised Use of Constraints and Data Integration
Authors: Rawnsley K. , Swaby P. , Bettembourg S. , Dhahab S. , Hillgartner H. , de Keijzer M. , Richard P. , Schoepfer P. , Stephenson B. , Wei L.
Published: December 2007

As part of an ongoing drive to enhance oil recovery from several fractured carbonate reservoirs in Oman, Shell's Carbonate Development Team and Petroleum Development Oman have applied a workflow and research software package aimed at better characterizing the complex subsurface. The workflow comprises several steps, each one supported by a multidisciplinary research program, and implemented in an integrated software environment for application to field development and enhanced oil recovery projects. The software tool, which interacts with the existing Static and Dynamic modeling packages, produces integrated reservoir models including fracture specific information. The capabilities include: (1) Data integration and visualization (2) Constraints definition (from subsurface, analogue outcrops, geomechanics, etc.) (3) 3D fracture modeling (4) Link to reservoir simulation.

The tool is flexible, such that any type of well data (Static and Dynamic), seismic data (attributes and interpretations), and constraints can be brought together in a single display. An analysis package allows rapid visual and interactive structural analysis to be made, with quantification of structural elements. Constraints are derived from outcrop and subsurface field examples, geomechanical data and sandbox analogue experiments. A key constraint includes mechanical layering as a control on fracture geometries. Fracture networks are generated following the defined constraints combining statistics and mechanical rules. The fracture network properties useful for the Dynamic simulation can be quickly extracted. Because emphasis is placed on characterization and maximum use of the relevant constraints, the tool helps ensuring that the fracture modeling time is spent on understanding and assessing the uncertainties.

To date this workflow has been applied to several fields worldwide, demonstrating its suitability to address problems related to Natural Depletion, Waterflooding or Assisted Steam Gas Oil Gravity Drainage.
The Synergy between Static Reservoir Modelling and Flow Simulations for the Optimization of a Field Development Plan of a Carbonate Reservoir, Onshore UAE
Authors: Ribeiro M. T. , Hassan S. R. , Gomes J. S , Bahamaish J. N.
Published: December 2007

This paper presents a case study where a full interaction between static reservoir modelling and flow simulation was performed to optimize the development plan of a carbonate Field in Abu Dhabi.

Since no reliable seismic attributes could be extracted from the 3D seismic, coupled with the fact the reservoir had only a few wells, several geological scenarios were modeled using both deterministic and stochastic techniques. Sensitivities were performed on variogram ranges, deterministic trends and algorithms.

The population of the model with petrophysical properties was carried out using reconciled log and core data in the crestal area of the Field and propagated downflank with the assistance of trends. The simulation of the porosity was done with Sequential Gaussian Simulation and for the permeability a co-simulation with porosity technique was applied. The results of 1D permeability simulation were also tried. Both approaches for permeability modelling were matched with the well test results. Due to the absence of SCAL data and the fact that the open-hole log saturations are not reliable (low resistivity pay in some intervals), an analog Sw curve had to be used. Two extreme Sw curves (min and max) were considered to cover the uncertainty.

Different reservoir descriptions (geological/petrophysical scenarios) were subsequently flow simulated and the results evaluated against different development options. The selected models matched water cuts and reservoir pressures without the need for permeability multipliers.

Finally, the results on new drilled wells (blind tests), namely log properties, PBU and injectivity test results, showed a good agreement with the models. The selected models were used to compare different patterns of development under multiple pressure support schemes (peripherical and updip water injection, gas vs. water injection, etc.).

This paper calls for the importance of building different static models using different geostatistical parameters to address the static-dynamic uncertainties, instead of performing a large number of stochastic realizations.
A Novel Approach to Reservoir Surveillance Planning
Authors: Sinha Satyendra P , Al-Qattan Raghad
Published: December 2007

Reservoir Performance is tracked and monitored with the help of various surveillance measurements. The surveys may include static and flowing bottom hole pressure measurements, pressure transient studies, production logging, pulsed neutron capture logging and flow rate measurements. The measured or interpreted values include reservoir pressure, productivity index, reservoir permeability, well efficiency, flow capacity, water saturation, fluid contacts and flow rates of oil, gas and water. These values, when appropriately grouped and mapped, indicate the reservoir performance and fluid flow movement. However, the asset needs to be managed with limited surveillance every year. This brings into focus the need to optimally select the candidate wells or completions. Surveillance is planned with an objective to minimize the uncertainty in the measured values. This results in maximizing understanding of the reservoir performance leading to sound reservoir monitoring and better business decisions. Continuity, productivity, probability & uncertainty maps are regularly prepared using Kriging. Measurement errors are assumed to follow a Gaussian distribution. The maps quickly reveal the need to have surveillance in particular wells/completions. The important contributions of the value-driven surveillance planning include Data integration of well and reservoir performance including all the surveillance and well integrity data.Analysis and interpretation of surveillance data becomes a prerequisite for requisitioning surveillance. Mapping and analyzing interpreted data becomes an integral part of any surveillance process.Intuition and subjectivity in surveillance planning is substituted by an objective method based on robust geostatistics.Surveillance data becomes more visible to the team. This generates team involvement, better quality of information and a shared understanding of reservoir management needs.
Seismic Integration for Better Modeling of Rock Type Based Reservoir Characterization: A Field Case Example
Authors: Bahar A. , Abdel-Aal O. , Ghani A. , Silva F. P. , Kelkar M.
Published: December 2007

This paper presents the result of a reservoir study where seismic data have been fully utilized to obtain a better rock-type based reservoir characterization model. The study was conducted for a highly faulted carbonate reservoir in the Middle East. The available 3D Seismic data have been used to determine the structure map, fault and fracture network, and porosity distribution. Additionally, two seismic attributes (Energy Half Time and Max. Peak Amplitude) had also been used to assist the determination of stationarity regions used for geostatistical simulation.

The reservoir characterization strategy for this study was started with the detailed development of a geological reservoir rock type (RRT) scheme. The RRT scheme was developed based on depositional facies, diagenetic overprints and petrophysical properties, including pore throat size distribution, porosity and permeability. The scheme was then used to constrain the property modeling inside a geological framework that was built based on the seismic interpretation.

Prior to the development of 3D porosity model, four porosity maps were generated based on the available interpreted Acoustic Impedance (AI) and well log data. Each map represents the difference of the influence of seismic data, from full seismic influence to no seismic influence. One map has been selected to represent the seismic derived porosity based on the degree of correlation between the AI data and well-log porosity.

The integration of seismic-derived porosity into the 3D simulation model was conducted using Bayessian Update principle inside a conditional simulation technique. In this technique, 3D porosity distribution honors the underlying RRT and at the same time its vertical-column average honors seismic-derived porosity. The comparison of the results between the simulation with seismic and simulation without seismic has clearly indicated the value added by seismic data, namely improving the simulation result in the areas of poor well-coverage. This is important in order to honor the diagenesis effect that is difficult to model due to a limited number of wells.
Predict Injection Profile of an Injector Using a Soft Computing Method
Authors: Wei Mingzhen , Sung Andrew H. , Wang Jiachun , Liu Lingzhi , Zhang Shujuan , Li Xuxin
Published: December 2007

Knowing the injection profile of each injector in a reservoir is of major importance for analyzing residual oil distribution underground. However, in practice, it is impossible to acquire real-time injection profiles for each well when they are needed.

In this paper, a two-step learning fuzzy system was introduced to predict injection profiles for wells with outdated data or without data by analyzing those injectors whose injection profiles are well characterized. Five pivotal parameters were selected to be fed into the subtractive clustering algorithm and ANFIS (adaptive-network-based fuzzy inference system) to model their non-linear relationships with the injectivity of each producing layer. Experiments in comparing the two-step method and the backpropagate feed-forward (BPFF) neural network showed that the two-step method can automatically generate a more simply structured fuzzy inference system (FIS) and can simulate complicated numerical nonlinear relationships with higher accuracy.

This method was used in injection profile prediction in one block of the Daqing oilfield. The average accuracy was shown to be above 80%.
3D Reservoir Characterization and Reservoir Management Study, October, J Nubia Field, Gulf of Suez, Egypt
Authors: Gaber Nabil Salah , Ahmed Hassan Alhussieny , Stoner Douglas T. , Artigas Gabriel B. , Mercado Gary M. , Mahgoub Ismail Shaban , Elreheem Mohamed G
Published: December 2007

An extensive, multi-discipline field study was completed in 1999 on the October J Nubia reservoir, located in the Gulf of Suez, Egypt. Although this field is relatively small (7 active wells, 132 MMBO OOIP) as compared to other Gupco's fields, the study proved worthwhile, generating three development prospects, all of them have been drilled and resulted in a rate increase of 6000 BOPD and a reserve gross of 6.6 MMBO.

The study team built a comprehensive, 3-dimensional Earthvision reservoir property model which was an excellent building block for understanding reservoir volumes and performance. The property model provided the tools necessary to understand fluid migration across faults in a 3-dimensional setting. The structural analysis began with the reinterpretation of a full-field, 3-dimensional seismic data set. The structural model was then populated with petrophysical parameters to produce the property model.

Extensive reservoir performance mapping also helped our understanding of fluid movement within the reservoir and helped identify areas of bypassed pay. As an example, watercut maps constructed for each of the fourteen reservoir subzones helped determine primary pathways of water encroachment.

The reservoir is a tilted fault block encompassing 750 acres. The producing formation is the highly prolific carboniferous Nubia sandstone with an average gross pay thickness of 600 feet, net pay thickness of 375 feet, porosity of 23 percent, and permeability in the darcy range. The reservoir has a fairly strong natural waterdrive, helping maintain reservoir pressure above the bubble point.

Even though the reservoir was forecasted to recover 48% of the original oil-in-place, the study located three areas of poor sweep. The three authorized drilling prospects are estimated to recover an additional, risk-weighted reserves of 9 MMBO. In addition, a detailed zonal performance analysis helped identify perforation and conformance work in existing wells, which should recover an additional 3 MMBO. The resulting property model and reservoir development plan now provide the operational tools necessary for managing this property for the next several years.
Synthetic Seismograms: Value of Adequate Log Data Process
Authors: Avu A. A. , Odegbesan C. O. , Pointing E. G. , Udoh N. B. , Kolarsky R.
Published: December 2007

Sonic and density logging tool responses are susceptible to poor borehole conditions. The ability to replace spurious well log responses with a reasonable estimate prior to generating a synthetic seismogram would mitigate stretching and squeezing to force a match with the seismic. This paper focuses on the importance and impact of shale editing on the quality of well – to – seismic match and describes the trend curve approach used.
A Study of IOR by CO2 Injection in the Gullfaks Field, Offshore Norway
Authors: Agustsson H. , Grinestaff G. H.
Published: December 2007

This paper describes the feasibility study of a large-scale miscible CO2-WAG (MWAG) injection scheme in the Gullfaks Field, offshore Norway. We describe the reservoir engineering workflow and simulation techniques, the predicted production and injection profiles, and the main infrastructure solutions under consideration.

Compositional cross-section models and recently available streamline-tracer simulation techniques are employed to scale up from element models to a fast, full-field simulator with a high degree of flexibility.

The starting point for the workflow is a set of black oil and streamline front tracking models, history matched on coarse and fine grids. A fast, finely gridded streamline model is used to identify the MWAG injection targets, define injection well locations and completion strategy. Fine gridded cross-sections are extracted and used in a compositional simulator to study and quantify the miscible displacement process. These are the used to derive scaling parameters used in a simple, ultra-fast streamline-tracer model, scaling the MWAG process up to field level. The streamline-tracer model interactively optimises solvent allocation and generates production predictions on a well-by-well basis. Water flood recovery and incremental IOR are predicted simultaneously in a single simulation run.

In addition, the general economic limitations and example technical solutions for implementation of a CO2 MWAG on the Gullfaks Field are briefly described.
Estimation of Oil Recovery and CO2 Storage Capacity in CO2 EOR Incorporating the Effect of Underlying Aquifers
Authors: Bachu Stefan , Shaw Jerry C. , Pearson Robert M.
Published: December 2007

Atmospheric concentrations of CO2 have risen since the beginning of the industrial revolution, primarily as a consequence of fossil fuel combustion for energy production and other industrial activities. Recognizing the challenge imposed by the potential for climate change, recent initiatives by various governments and by energy producers target a significant reduction in the intensity of CO2 emissions into the atmosphere. A major mitigation strategy for reducing the intensity and amount of CO2 emissions into the atmosphere is CO2 capture and sequestration, of which geological sequestration is a major component. Although enhanced oil recovery operations have the lowest capacity of all options for geological CO2 sequestration, they are most likely to be implemented first because of the additional economic benefit that will help offset the cost of CO2 sequestration.

Assuming that the pore space previously occupied by the produced oil can be backfilled with CO2, a methodology has been developed for the identification and screening of oil reservoirs that are suitable for CO2 flooding and for estimating their CO2 sequestration capacity at depletion, as well as under enhanced oil recovery.

The methodology has been applied to close to 11,000 oil pools in the Western Canada Sedimentary Basin that are recorded in provincial reserves databases. Of these, 4,767 oil pools are technically suitable for CO2 flooding, with an estimated incremental oil production and total CO2 sequestration capacity of 350×106 m3 (2,200 MMbbl) and 988 Mt CO2, respectively. However, only 110 oil pools have individual CO2 sequestration capacity greater than 1 Mt CO2 each, but together they account for ~61% of the total. The incremental oil production from these 110 oil pools is estimated to be 150×106 m3 (930 MMbbl) oil, and these oil pools should be considered first in detailed studies of CO2 EOR and sequestration.

To account for the effect of underlying aquifer influx that reduces CO2 storage capacity, analysis of the production history of these 110 oil pools shows that the water-oil and gasoil ratios are indicative of the strength of the underlying aquifers, but the recovery factor is not. The underlying aquifer is considered strong if cumulative net WOR>0.25, and weak if WOR<0.15. For WOR between 0.15 and 0.25, strong aquifer support is indicated by cumulative GOR<1,000 m3/m3 (5,600 scf/bbl), otherwise the aquifer support is weak. Material balance analysis on 19 of these oil pools with active aquifers indicated that, if the reservoir pressure is only allowed to increase back to the initial pressure, the CO2 sequestration capacity is reduced on average only by ~3%, if the underlying aquifer is weak, and by ~50% if the underlying aquifer is strong.
Investigation of Liquid CO2 Sequestration and EOR in Low Temperature Oil Reservoirs in the Illinois Basin
Authors: Frailey Scott M. , Grube John P. , Seyler Beverly , Finley Robert J.
Published: December 2007

Current studies of geologic storage of CO2, with the exception of CO2 sequestration in coal beds, focuses on supercritical CO2, emphasizing the stability of the fluid, solubility of CO2 in saline formation water and miscibility with crude oil. Likewise, with the exception of very early research, the use of CO2 to enhance oil recovery (EOR) historically focused on supercritical CO2 to achieve miscible conditions with crude oil. The only possibility of liquid CO2 geologic storage is in formations with temperatures less than the critical temperature of CO2. Due to the naturally occurring geothermal temperature gradient, most all geologic formations currently considered for CO2 sequestration and EOR exceed the TcCO2.

A research plan has been developed to investigate the use of depleting (mature) oil reservoirs with formation temperatures less than critical temperature of CO2 to sequester liquid CO2 and investigate the implications of EOR from the liquid CO2 displacement process. Relatively higher pressures are required to attain liquid CO2, which translate to fracture gradients as high as 1.0 psi/ft. However, fracture stimulation data published in early literature and field data from fracture stimulation companies in the Illinois Basin show that fracture gradients of up to 1.0 psi/ft are commonly recorded in the shallower producing horizons of the Basin. Therefore, the pressure requirement may not be a detriment.

Because of the liquid/gas phase changes and consequent changes in density and viscosity of CO2 at subcritical temperatures, low temperature oil reservoirs provide a unique opportunity for liquid CO2 storage and the application of a novel and innovative EOR-CO2 cyclic multi-reservoir displacement process within the Illinois Basin.
Geological Sequestration of Carbon Dioxide in Depleted Gas Reservoirs
Authors: Sobers L. E. , Frailey S. M. , Lawal A. S.
Published: December 2007

The purpose of this paper is to investigate the effects of phase behavior on the sequestration CO2 of in depleted gas reservoirs (dry gas, wet gas and retrograde gas). Carbon dioxide sequestration in depleted and abandoned gas reservoirs can accomplish two important objectives. Firstly, it could be important part of present climate control initiative to reduce the concentration of carbon dioxide in the atmosphere. Secondly, it could be instrumental to enhance gas and condensate recovery. Using the pressure-temperature diagrams and two phase flash calculations, the phase behavior of natural gas-carbon dioxide mixtures were analyzed to provide enlightenment on the sequestration process. From analysis of simulated results, it was found that carbon dioxide exhibited a drying effect on wet and retrograde gas mixtures and a wetting effect on dry gas. The results for retrograde gas condensate depended on the composition of reservoir fluids at abandonment conditions. The main difference being the liquid volume present with increasing pressure and carbon dioxide concentration. This influenced the volume of condensate vaporized with addition of carbon dioxide. It was also determined that carbon dioxide lowers the compressibility factor of all gas types. These results are favorable for carbon dioxide sequestration because decreasing compressibility factors represents increasing storage capacity.
Improved Mappings for Streamline-Based Simulation
Authors: Mallison B. T. , Gerritsen M. G. , Matringe S. F.
Published: December 2007

Our interest lies in extending the streamline method compositional simulation. In this paper we develop improved mappings to and from streamlines that are necessary to obtain reliable predictions of gas injection processes. Our improved mapping to streamlines utilizes a piecewise linear representation of saturations on the background grid in order to minimize numerical smearing. Our strategy for mapping saturations from streamlines to the background grid is based on Kriging. We test our improvements to the streamline method using a simple model for miscible flooding based on incompressible, Darcy flow. Results indicate that our mappings offer improved resolution and reduce mass balance errors relative to the standard mappings. Our mappings also require fewer streamlines to achieve a desired level of accuracy. In compositional cases where the computational cost of a streamline solve is high, we anticipate that this will lead to significant improvement in the efficiency of streamline-based simulation.
Experimental Study of Tertiary Immiscible WAG Injection
Authors: Righi E. Fernández , Royo J. , Gentil P. , Castelo R. , Del Monte A. , Bosco S.
Published: December 2007

An experimental study of immiscible WAG (water-alternating gas) injection is presented. The target reservoir is the waterflooded Troncoso sandstone in Chihuido de la Sierra Negra Field in Argentina. The original reservoir fluid was an undersaturated light oil with a viscosity of about 1 cp and 13 to 20 mole percent carbon dioxide.

Phase behavior tests were conducted using live reservoir oil and synthetic candidate injection gases. They were aimed at assessing the extent to which compositional effects could affect oil recovery at current reservoir pressure.

Coreflooding experiments were performed on field core composites using current field production gas which has 65 mole % CO2. The samples were initially saturated with live oil and irreducible formation water and then flooded with formation water to residual oil saturation at reservoir conditions. Following waterflood, a number or WAG cycles were injected. The displacements were conducted at pressures well below the estimated minimum miscibility pressure for this system.

Tertiary oil recovery efficiency resulting from WAG injection was significant, leading to final residual oil saturations as low as 13 % pore volume (PV). Results of corefloods and compositional laboratory tests suggest that the displacement mechanism is a combination of compositional effects and fluid mechanical effects. The former include interfacial tension reduction, oil swelling and viscosity reduction. Mechanical, fluid distribution effects result from the presence of the free gas phase in the pore system and the cyclic variation in gas and water saturations, as accounted for in a recently developed immiscible WAG phenomenological model that has been used to simulate the process presented here.
Streamline Technology for the Evaluation of Full Field Compositional Processes; Midale, A Case Study
Authors: McKishnie R. A. , Malik S. , Chugh S. , Lavoie R. G. , Griffith P. J.
Published: December 2007

Traditionally, the evaluation of CO2 flooding processes is performed using finite difference compositional simulation models. However, compositional simulation is impractical for modeling large-scale CO2 floods due to computational runtime restrictions. In cases where reservoir heterogeneity and fluid mobility dominate the reservoir recovery mechanism, streamline simulation offers a viable alternative to compositional simulation. The "reduced" physics in streamline simulation allows field scale CO2 flood modeling to be feasible, as long as the streamline PVT model can be calibrated such that the streamline model will produce accurate results for CO2 injection processes. Using streamline simulation allows for the evaluation of multiple full field development scenarios that would otherwise not be possible using compositional simulation.

The objective of the study was to provide CO2 flood performance forecasts under various full field development scenarios for the Midale field. This paper focuses on the methodology and results from the 1000 well, >400,000 grid blocks, and 45+ years of history streamline simulation of the Midale field. In particular, it discusses the construction and history match of the full field model, calibration of the streamline model with the compositional model and development of the full field CO2 forecasts.
Improved Oil Recovery by In-fill Drilling in a Mature Field; A Success Story
Authors: Ghosh B. N. , Sarkar Soma. D. , Lohiya J. P. , Das T. K.
Published: December 2007

Proposal

North Kadi oil field in North Cambay Basin, India has been under production since 1969. The hydrocarbon accumulation in the field is mainly in Middle Miocene sandstone of Kalol Formation having high permeability and strong aquifer support. The development plan of the reservoir had been drawn on the basis of simulation studies carried out at various stages. Recently, remodeling of the field has been done for rational exploitation of the reservoirs.

Improved Oil Recovery (IOR) Scheme was formulated after updating the geological model. In-fill drilling of 33 locations were firmed up to achieve the optimal recovery. It envisaged 1.7% additional recovery of in-place oil in 20 years over the primary component of 31.23%. At the time of implementation of the scheme, the field had already produced 20% of 67.0 MMt OIIP. Thirty two IOR locations have been drilled during last three years. As of now, the incremental production from IOR wells is 26% higher than envisaged production profile. The in-fill wells have shown no interference on the performance of nearby wells within their past two years of production history.

The drilling and completion cost of the wells break-evened in 20 months. The IOR Scheme involving in-fill drilling rejuvenated the declining trend of a mature oil field.
Enhanced Oil Recovery with Horizontal Waterflooding, Osage County, Oklahoma
Authors: Westermark R. V. , Dauben D. , Robinowitz S. , Weyland H. V.
Published: December 2007

This paper provides details of a project to test horizontal waterflooding as a means of improved oil recovery in Osage County, OK. Supported by a grant from the Department of Energy (DOE), an independent operator, Grand Resources, Inc., has developed a process for selecting and developing candidate reservoirs for horizontal waterflooding. Reservoir screening is the first step in the process and then rock mechanics are used to predict wellbore stability for determining the most efficient completion method. Geologic and reservoir parameters are considered when selecting the radius of curvature for the horizontal well to be drilled and the air/foam drilling fluids to be utilized to avoid formation damage. The final step is to run a comprehensive set of logs through the curve and out into the reservoir allowing for petrophysical evaluation.

To accomplish an economically successful project, given the basic assumption of an existing field infrastructure having an adequate water supply well available, the following three goals must be met: 1) demonstrate that horizontal waterflooding is technically and economically feasible for recovering additional oil in shallow low permeability reservoirs; 2) demonstrate that open hole completions are a viable technique based on wellbore stability considerations; 3) demonstrate that short radius rotary steerable technology can drill horizontal wells at low cost and without reservoir damage.