bluuebunny/crossref_metadata_2025 huggingface dataset:
Field Application of Electromagnetic Eddy Current Technology Enables Proactive Near Surface Casing Inspection
Authors: Mishkhes Abdulrahman T. , Al-Ajmi Mohammed D. , Al-Hajri Nasser M. , Al-Subaie Fehead M. , Fayyaz Muhammad F.
Published: July 2016

In mature onshore wells, near surface casing and wellhead landing base corrosion was identified as a critical concern that can compromise well integrity. Multiple field studies were conducted to identify the root causes for this corrosion growth, such as water presence (rain, shallow aquifers, etc.) or the absence of adequate cathodic protection. Consequently, a comprehensive surface casing and landing base inspection and repair program was established to proactively take the required corrective measures and ensure the integrity of all wells. The current inspection techniques involve cellar excavation, visual inspection for metal loss, ultrasonic (UT) inspection, or even cement chipping if required. Therefore, optimization of candidate selection and the use of alternative equivalent tools to detect near surface corrosion issues is imperative to enhance well integrity management.

As part of its well integrity management program, Saudi Aramco has put more focus on using eddy current tools (EDCs) to assess the integrity of downhole tubulars and identify downhole leaks. The limitations of the first generation tools were related to the total measured thickness and radius of investigation. However, with technology advancement, progressive tools were introduced with much higher thickness measurement capabilities and deeper radius of investigation that can reach up to the 30-in conductor casing. These added features enabled nonintrusive inspection of near surface casing integrity as well as downhole corrosion profiling.

This paper presents a field application of a nonintrusive approach to inspect shallow surface casing using electromagnetic EDC technology. The methodology allowed for early detection of surface casing corrosion growth, and, accordingly, proactive measures were implemented to enhance the well integrity program and save time, manpower, and operational costs. The paper also recaps multiple case studies of severely corroded near surface casing profiles identified by EDCs.
Elimination of Scaling Potential of Seawater in a Downhole Environment through the Innovative Use of Nanofiltration and Scale Inhibitor
Authors: Karadkar Prasad , Al Dahlan Mohammed , Sahman Faisal , Marshad Khalid , Yami Ibrahim , Soileau Chris , Al-Ghamdi Tawfik , El Hajj Hicham
Published: July 2016

Seawater-based fracturing fluids provide greater flexibility when designing stimulation treatments for offshore environments by reducing delays in stimulation vessel scheduling and using an, essentially, unlimited supply of seawater, opposed to fresh water. Because seawater has a higher ionic strength than traditional fresh water, lower viscosity is observed from guar-based polymers. By comparison, the seawater can produce scaling precipitates when sulfate ions contact the calcium, barium, and strontium ions in the formation. The formed sulfate precipitates could lead to formation damage in the form of scaling, pore throats being clogged, and an overall reduction in production capacity.

This paper presents an innovative polymer-based scale inhibitor (SI) to mitigate scaling issues from seawater with 4,000 mg/L sulfate when mixed with 200,000 mg/L total dissolved solids (TDS) formation water. From static bottle tests with seawater, 74% strontium sulfate inhibition was achieved at 300°F. To eliminate sulfate scaling issues, a nanofiltration (NF) membrane-based technique was used to filter seawater. The SI performance was tested by both static bottle tests at different mixing ratios and dynamic tube blocking tests at 300°F. Following static bottle tests, the key ion concentrations were determined using inductively coupled plasma (ICP) spectroscopy. Zero scaling was achieved by adding 300 mg/L SI. The fracturing fluid was prepared using a zirconate-crosslinked derivatized guar. The rheology of the fracturing fluid was measured with and without SI to investigate its influence on crosslinking and proppant carrying capacity at 300°F. High magnesium in the seawater consumes hydroxide ions and affects pH control. To obtain a stable fracturing fluid, the pH was optimized to minimize magnesium precipitation. Coreflooding experiments confirmed the addition of SI does not cause additional formation damage.

Using NF-seawater in conjunction with proven SIs can provide effective treatment of seawater-based-fracturing fluids. The separation technique (NF) and chemical solution (SI) complement each other to neutralize scaling issues completely. This technique minimizes freshwater usage in fracturing, which can enable significant savings for offshore operations time and cost.
Extended LWD High Resolution Imaging Solution for Well Placement and Reservoir Characterization in laterally Heterogeneous Carbonate Reservoirs
Authors: Zeghlache Mohamed Larbi , Zayer Mohammed F. , Khandakji Rami
Published: July 2016

Logging-while-drilling (LWD) imaging solutions have been a part of the oil and gas formation evaluation technologies portfolio for quite some time. Lately, most LWD solutions have evolved to address new challenges in complex environments. This paper discusses advanced LWD electrical imaging technology and its recent use to help solve persistent challenges related to both well placement and reservoir characterization.

In a thin heterogeneous carbonate reservoir constrained by a tight control window of placement, the high-resolution, real-time laterolog electrical image proved to be an optimum solution to help determine well placement for maximizing reservoir contact. Running wireline imaging for fracture identification, inflow control device (ICD) completion design, and reservoir characterization can impose many risks related to well trajectory, borehole stability, borehole shape, and well control. However, an alternative LWD high-resolution laterolog electrical imaging solution—validated by the example described in this paper from a carbonate reservoir in the Middle East—demonstrated its capability to achieve the same objectives in those environments while avoiding the above-mentioned risks.

Well placement (geosteering) is dependent on control points from offset wells and LWD tool measurements that help identify the location of the bottomhole assembly (BHA) down hole in real time to enable on-the-fly decisions regarding well placement in the sweet zones. Imaging applications that outline a 360° view of the borehole are commonly used to identify formation dips, allowing geosteering specialists to make well trajectory adjustments. This paper illustrates an example of a resistivity contrast in a carbonate reservoir capped by a tight resistive boundary. The real-time LWD high-resolution electrical image helped identify formation dips and features of sublayers within the zone of interest. Noticeable changes in the sublayers' dip were most likely related to a boundary dip angle change. After adjusting the drilling assembly trajectory to account for that change, the LWD electrical image clearly illustrated parallel lines, indicating the well trajectory was smoothly following the same formation dip. In addition, the LWD focused resistivity tool capability to record high-resolution images while drilling proved to be an effective alternative solution to wireline imaging in these environments.
Estimation of MW and CGR in the Absence of Comprehensive Compositional Information: A Practical Application in a Near Critical Gas Reservoir
Authors: D'Windt Adolfo , Akbaar Yasmeen , Al-Arouj Mutlaq
Published: July 2016

Describing the volumetric behavior of a gas reservoir requires the knowledge of its composition; however, this information is often limited. This paper presents a workflow for predicting gas specific gravity in absence of comprehensive compositional information. The approach used is to express the real gas law in terms of specific gravity and solve for it by means of the Newton Raphson algorithm. The proposed method requires as input a live fluid density measurement and the non-hydrocarbon content. The Z factor is stated as an implicit function of pseudo-reduced properties that in turn can be explicitly expressed in terms of specific gravity; this is accomplished by means of suitable correlations. The pseudo critical properties determination accounts for the presence of non-hydrocarbon fractions thus this method is not limited by the amount of impurities concentration.

We applied the proposed workflow to a field case corresponding to a sour gas condensate reservoir from which fluid samples are available. Experimental data includes gas chromatography analysis, multistage separator test, and 790 data points comprising Z factor and fluid density measurements from CCE experiments. Specific gravity computation uses fluid density derived from static gradient measurements and an approximate knowledge of the impurities content. A number of 25 combinations of Z factor and pseudo-critical properties correlations were tested for which the convergence rate of the algorithm was 99.9%. Overall error for the specific gravity prediction ranged between −1.5% and 0.5%. CGR and saturation pressure behavior with depth were adequately reproduced.

The proposed methodology allows us for reliable determination of key fluid properties in absence of compositional information by using already and routinely available field data; no expensive additional laboratory work is required. Derived properties can be used for engineering studies purposes and for production testing validation.
Prediction of the Gas Compressibility Factor Using Coefficient-Matrices Based on ANN
Authors: Attia M. , Mahmoud Mohamed , Abdulraheem Abdulazeez , Abido M. A.
Published: July 2016

Gas compressibility factor (Z-factor) is an important parameter that is widely used in petroleum and chemical engineering. An accurate and fast calculation of this parameter is of crucial importance and is used as an essential input in petroleum reservoir simulation. The Standing-Katz chart was published in 1942 and it has been considered an industry standard for the gas compressibility factor. Several methods have been developed to calculate z-factor by correlations such as the one proposed by Brill-Beggs. Other methods such as Dranchuk and Abou-Kassem (DAK) use iterative-based solutions. The DAK correlation gives most reliable fit to the experimental data along with a low average percentage error compared with those from other methods. However, for high values, the DAK correlation fails with very high error compared with the experimental data.

In this study, artificial neural networks (ANN) are used to predict Z-factor. Data used for constructing the Standing-Katz charts and experimental data from the literature were used to build the ANN model and evaluate the quality of the new model compared with the other methods. Data used for constructing the Standing-Katz and Katz compressibility charts were used in constructing the neural networks model. 70% of the data was used for training, 15% for validation, and the remaining 15% for testing. The experimental data collected from the literature was given as a new data to test the quality of the model.

The ANN model constructed using the DAK correlation gave an average absolute percentage error of 0.197 for testing; this value is better than that given by the DAK correlation. The error evaluated using the experimental data for ANN model is very low compared with the DAK correlation and those presented in the literature. In addition, a mathematical model is generated from the ANN model that can be used easily to determine the Z-factor at any conditions.
Enhanced Petrophysical Evaluation in Complex Lithology Using Advanced Analysis of Cuttings Data: A Case Study from Saudi Arabia
Authors: Hashem Mohamed M. , AlGhamdi Tariq M. , Ibrahim Azizi M , Zeriek Rachad , Taher Ahmed
Published: July 2016

Advanced analysis of cuttings (ACA) provides qualitative measurements of the gamma ray spectrum and allows for quantifying of mineral elements for each sample in mud logging. The advancement in technology permits the ACA measurements to be conducted in near real time, which enables integration with the conventional log measurements for the purpose of constructing robust, multi-mineral petrophysical model. The result of the data integration prevails in the petrophysical mineral model.

The ability to acquire samples at a higher sampling rate, proper sample treatment and oxides correction, had improved the quality of data acquired from ACA when compared to the initial trials. ACA sample resolution had been improved immensely when compared to the first trial, because it reached the level where it can resolve the layering of the reservoir in the targeted formations. LWD measurements are essential in real-time petrophysical evaluation but slim neutron spectroscopy (NS) tool is not available, and only some contractors have slim spectral gamma ray (SGR). ACA was used to complement the previously mentioned deficiency in LWD technology. A reliable carbonate multi-min petrophysical model was successfully built and implemented in near real time evaluation using ACA and LWD data integration. In addition, the ACA has the advantage of acquiring the SGR and NS in high temperature (>320°F) slim (<4 inches) hole. As a result, the combination of ACA and wireline logs were used to evaluate a deep reservoir. The ACA is more cost effective when compared to similar measurements from conventional logs.

This paper discusses the ACA and its integration with conventional log data for petrophysical interpretation of the carbonates and clastics formations, respectively. The availability of SGR and NS are very important in complex lithology evaluation. This case study shows that advanced mudlogging data integrated with standard logging measurements, assisted in building enhanced petrophysical model, where the SGR and NS logging measurements were absent.
Operating a Sampling While Drilling Tool in Low Permeability Carbonates and Lessons Learned on Hydrocarbon Breakthrough
Authors: Abdelkader Ramy , Berkane Mustapha , Deering James R. , Ceyhan Adil G.
Published: July 2016

It is more effective to capture clean reservoir fluids as early as possible during drilling operations, and with the realization of formation-sampling-while-drilling (FSWD), this goal is fast becoming a reality. This paper summarizes one example from Saudi Aramco and shows the benefits of this evaluation procedure.

Our experience in sampling oil bearing formations drilled with water-based mud, has seen that the data from these instruments, which are now able to withstand the rigors of the drilling environment, can be used in real-time to control the sampling process, capture high quality samples, and also place the well where required. In this case study, a tight carbonate reservoir was the objective with the oil column being near saturation pressure. Under these circumstances, the challenges presented to us while sampling, included maintaining low flow rates and potential three-phase conditions, due to unavoidable drawdown while minimizing the time on the wall.

During sampling, pump efficiency was consistent with low-mobility formations, even with the various multiphase flow regimes encountered. Hydrocarbon breakthrough was significantly faster than historical wireline sampling performed in the same reservoir. FSWD greatly improves our costs by saving rig time. Also, FSWD was utilized to evaluate low-resistivity-pay zones and observe if they hold a movable water fraction. We see this as crucial for geosteering wells to prevent drilling through the zones with movable water, which will enhance the productivity index of the wells.

As a first time experience of FSWD in tight zones, a valuable lesson came to light where additional real-time monitoring improvements can be made, including the need to improve real time data quality, to accurately determine clean-up fractions while sampling. Based on this experience, we have formulated operational guidelines for improving real-time data analysis and determining the most opportune time to sample during the drilling process.
Acoustics Deep Shear Wave Imaging DSWI Analysis in Fractured Carbonate Reservoirs
Authors: Zeghlache Mohamed Larbi , Silva Andre , Gouda Mohamed , Zaid Ahmed Abou
Published: July 2016

Carbonate reservoirs evaluation is challenging from different aspects related to stratigraphic and structural features heterogeneities. One of the major challenges is fractures evaluation in terms of fractures nature, intensity, aperture and extension. Near and far field evaluation techniques had been utilized to achieve advanced fractures evaluation and modeling. This later is a key factor for a successful carbonate reservoir development.

Resistivity images and cores help in the quantitative analysis of near wellbore fractures intensity and aperture; high resolution seismic data can help to evaluate major structural features at a bigger scale. It is essential to bridge the gap between the borehole and field scale to further enhance evaluation of these fractures.

Using acquired sonic log and special processing; deep shear wave imaging (DSWI) uses cross-dipole shear wave components to "image" reflectors up to 70 ft (radius of investigation) away from the borehole, whether intersecting the borehole or not. This radial distance coverage can be even further away depending on many parameters.

The combination of resistivity imaging and acoustics deep shear wave imaging techniques is a great value added to fractured carbonate evaluation; this paper discusses a case study and lessons learned in a challenging evaluation well where both techniques were deployed to validate this process and enhance petrophysical and reservoir characterization models.

Future work will involve integration between results of acoustics deep shear wave imaging technique and both borehole seismic and surface seismic data to enhance the fracture model; and ultimately optimize well placement as well as reservoir performance.
Impact of Chemical Flood Implementation Time on Ultimate Recovery and Net Present Value
Authors: AlGeer Mohammed A. , Alshehri Amar J. , AlKhatib Ali M.
Published: July 2016

During waterflooding processes, injected water disconnects oil droplets as it flows through pores/throats in the reservoir. These disconnections are a consequence of capillary effects hindering the mobilization of oil through pores/throats of the reservoir. Thus, mobilizing the remaining oil in place by any enhanced oil recovery (EOR) process becomes very challenging.

Chemical flooding has been identified as an effective EOR method, which is usually implemented in tertiary mode, where field development has reached a mature level. At this stage, the efficiency of waterflooding, in terms of mobilizing remaining oil, declines due to capillary trapping. Chemical EOR (CEOR) methods such as polymer-surfactant flooding are used to reduce this trapping and mobilize the remaining oil.

Although most EOR processes have been implemented in tertiary mode, earlier implementation is more desirable, because capillary trapping is less prominent. This study investigates the impact of post-waterflood implementation time of surfactant-polymer flooding on ultimate recovery and net present value (NPV), given this capillary trapping. A series of numerical experiments was conducted to test this effect while accounting for operating expenses associated with both flooding options. Capillary pressure curves for the waterflood case and the chemical flood case were added to incorporate capillary trapping effects. Then the chemical-flood implementation time was varied to evaluate its impact on the ultimate oil recovery. These experiments were performed on two stylized reservoir models PUNQ-S3 and SPE10M reservoir models.

Given our assumptions, the ultimate recovery did not significantly change with varying the CEOR implementation time. There is, however, an optimum implementation time for CEOR at which NPV is maximized. The optimum implementation time becomes sooner as the geologic model is more heterogeneous.
A Roadmap to Successfully Select a Proper Gel Treatment Technology
Authors: Aldhaheri Munqith N. , Wei Mingzhen , Bai Baojun , Alsaba Mortadha
Published: July 2016

Polymer gels have been effectively applied to extend the productive life of mature oilfields by mitigating water production and enabling the recovery of bypassed oil reserves. A key component for a successful conformance improvement treatment is the identification of the most appropriate gel technology for a targeted reservoir. Gel projects are capital sensitive and involve high degree of risk; therefore, it is crucial to select a proper gel technology and provide an optimized design project.

This paper presents the first generalized comprehensive selection system for injection well gel technologies based on the comparative analyses of the characteristics of conformance problems in gel field projects. 111 field trials of three in-situ gel systems including bulk gels, colloidal dispersion gels, and weak gels were summarized from 1978 to 2015. First, reservoir/fluids characteristics, diagnosis indicators used in the evaluation of drive-fluid channeling strength, and treatment operational parameters were summarized. Then, problem zone volumes were estimated using a design rule of thumb and the problem development status was indicated using some production-related parameters. Finally, all characteristics of conformance problems were compared for different gel systems to identify factors implicitly used in the nomination of gel technologies in the field projects.

We recognized that gel selection process starts by matching characteristics of conformance problems with technical specifications and mechanisms of the gel systems. Then, the initial candidate technology is confirmed by screening criteria to ensure gel system compatibilities with reservoir and injected fluids. We identified that the most influential characteristics in the selection process are drive-fluid channeling strength, volume of problem zone, problem development status, existence of cross-flow, and the nature of the required solution whether it depends on gel strength or volume. It was recognized that the existence of crossflow or high oil saturation in the offending zones turns a limited conformance problem into a large volume issue that needs the application of the flood-size treating technologies. For these situations, current oil saturation in the problem zones is the key factor rather than oil saturation in the less conductive zones because it is guaranteed by the high reservoir permeability heterogeneities. In addition, the problem development status does not only affect the selection of a gel system, but also its design parameters such as polymer concentration. The novelty of the new gel selection system is in its utilization of standardized general parameters and provision of distinct parameter cut-offs for each gel technology.
Automatic Calibration of Uncertainty Estimates Using Anchoring Heuristics
Authors: Dossary Mubarak
Published: July 2016

The difficulty of assessing uncertainty has been well-documented by many authors (Capen 1976, Begg, Bratvold et al. 2003, Bickel and Bratvold 2007). Part of this difficulty is attributed to the biases that affect estimation and decision-making. This has also been documented in the literature (Tversky and Kahneman 1974, Welsh, Bratvold et al. 2005, Welsh, Begg et al. 2007, Virine 2008). The best solution to resolving those biases is the calibration of the uncertainty estimates (Capen 1976, McVay, Lee et al. 2005).

Calibration is incorporating past experiences in the new estimation process by applying correction factors to the raw estimates, based on the reliability of past estimates, to give calibrated estimates. This cannot be done instantly because it requires tracking past probabilistic predictions and comparing them to actual outcomes. Such information is not usually available because it requires project management discipline, corporate knowledge management, and appreciation for the value of quantifying uncertainty.

The objective of this paper is to demonstrate an automatic calibration method that can be readily applied for any uncertainty estimation without requiring past information about the reliability of previous estimates. This method combines two components: anchoring heuristics as demonstrated by Tversky and Kahneman, and the graphical demonstration by Capen (1976). The results of this study show that any general estimate of an uncertain parameter (e.g. Porosity, Permeability) can be calibrated by doubling the range while anchoring in the central tendency of the estimates. The process was applied to survey results a la Capen (1976) and showed an increased confidence in the estimate from 34% to 72%.
Determination the Rheological Properties of Invert Emulsion Based Mud on Real Time Using Artificial Neural Network
Authors: Elkatatny S. M.
Published: July 2016

Drilling fluid rheology properties play a critical role in the drilling operations. These properties such as, plastic viscosity, yield point, apparent viscosity, flow behavior and flow consistency should be monitored during the drilling operation. In normal operation, these properties are measure twice a day, while the mud density, Marsh funnel viscosity, and solid content, which are measured every 10 to 20 minutes. Previous models were introduced only to predict the apparent viscosity of the drilling fluid from the Marsh funnel viscosity with large errors.

The objective of this research is to introduce a new model to predict the drilling fluid rheological properties from the Marsh funnel viscosity, solid content, and density measurements in real time. A developed mathematical model was obtained from the weights, biases, and the transfer functions used in the Artificial Neural Networks (ANNs). The ANNs black box was converted to white box to obtain a visible mathematical model that can be used to predict the drilling fluid rheological properties only using Marsh funnel viscosity, solid content, and density.

Field measurement for 9000 drilling fluid samples were used for model training and testing, the viscometer readings at 300 and 600 rpm were predicted using the visible mathematical model from the ANNs. The rheological parameters such as yield point, plastic viscosity, apparent viscosity, and consistency index were determined from the viscometer readings at 300 and 600 rpm. The predicted rheological parameters were compared with the measured ones from the field and the match was very good. The average absolute error for the various parameters ranges from 1 to maximum 5 compared to 60 if we used the previously developed correlations. The developed model is a robust technique and tool that can be used to predict the real time drilling fluid rheological parameters that are essential for the drilling hydraulics design and also to predict the performance of drilling fluid.
Real-Time Well Integrity Diagnostics Using the Latest Developments in Visual Logging Technology; a Case Study.
Authors: Al-Hajri Nasser M. , Al-Ajmi Mohammed D. , Al-Subaie Fehead M. , Hognestad Andre , Johannessen Erik
Published: July 2016

This paper will present a case study that illustrates wide-ranging capabilities of the latest improvements to visual logging technology. The well studied was identified as having a wellbore obstruction during a routine wireline survey. Conventional well accessibility diagnostics were run that include multi-size drifting tools and lead impression blocks. This assessment was inconclusive, which was attributed to wellbore geometry (deviation). A downhole bailer sample was taken at the wellbore obstruction depth. Extensive composition identification laboratory analysis was conducted on the sample. Physical examination of the sample using magnet attraction and acid solubility was performed along with a solvent extraction test to identify hydrocarbon content in the sample. Additionally, the sample crystalline structure was identified using X-ray diffraction and X-ray fluorescence to determine elemental composition. Laboratory analysis has indicated that the sample is mainly iron sulfides containing iron oxide and calcium carbonate as minor components.

In light of the above findings, two possible sources of the downhole obstruction were conceived: Severe casing collapse induced by galvanic corrosion.Scale funneling along the casing wall due to high iron and sulfate contents in the injected water leading to iron sulfide precipitation.

To ascertain the source of obstruction, the latest visual logging technology was deployed in this well. This technology provides extreme wide-angel (185/360°) images along the entire wellbore length through its lens and image capturing design. An advanced operating system inside the tool adds flexibility for image enhancements and real-time data transmission. Specially designed software was used to view the recorded data and align images with time, depth, and tags for log interpretation. The software uses advanced image logarithms to add pan, tilt, and zoom capabilities during live inspection and views of stored images. Visual logging has revealed scale build-up inside the wellbore and ruled out casing collapse.
Improved Fluid Efficiency for High-Temperature Viscoelastic Surfactant Based Stimulation Fluids Using Synergistic Effects of Nanoparticles
Authors: Sangaru Shiv Shankar , Yadav Prahlad Kumar , Huang Tianping , Al-Rabah Mohammed , Sarmah Pranjal
Published: July 2016

A viscoelastic surfactant (VES) based fluid has been proven to be a cleaner alternative to the conventional polymer based fluid. However, there are still certain technical challenges that need to be overcome to make it as a viable alternative. High fluid loss observed with VES fluids is one such issue that is investigated in this paper. It is known that certain nanoparticles can improve the rheology and fluid loss efficiency of VES fluid when added individually. Lab experiment results demonstrate that in certain conditions adding two different nanoparticles can act synergistically to improve the fluid efficiency more than when adding only one of the nanoparticles.
Reservoir Simulation Assisted History Matching: From Theory to Design
Authors: Shams M.
Published: July 2016

Petroleum reservoirs are geologically large and complex. In order to technically and economically optimize the exploitation of these hydrocarbon reserves, multimillion dollar investments, reliable numerical reservoir simulation models should be constructed to predict the reservoir performance and response under different production scenarios. Reservoir numerical simulation models can be only trusted after good calibration with actual historical data. The model is considered to be calibrated if it is able to reproduce the historical data of the reservoir it represents. This calibration process is called history matching, and this is the most time consuming phase in any numerical reservoir simulation study. Traditional history matching is carried out through a trial and error approach of adjusting model parameters until a satisfactory match is obtained. The biggest challenge that faces the simulation engineer during this critical phase is that, several combinations of reservoir history matching parameters might be satisfactorily matching the past dynamic behavior of the system which makes the process ill-posed due to the non-uniqueness solution issues. Traditional history matching is accordingly a time-consuming, expensive, and often frustrating procedure and as a consequence, the assisted history matching technique has been arisen.

In assisted history matching technique, the simulated data is compared to the historical data by means of a misfit function, objective function. The history matching problem is translated into an optimization problem in which the misfit function is an objective function bounded by the model constraints. The objective function is minimized using appropriate optimization algorithm and thus the results are the model parameters that best approximate the fluid rates and pressure data recorded during the reservoir life.

The objectives of this paper are to clarify the idea behind assisted history matching process and discuss its different aspects, experimental design, proxy models, and optimization algorithms, and show how these aspects are integrated to overcome the frustrating nature of the history matching problem. Finally, guide lines are provided to enhance the design of the assisted history matching process.
Model-Assisted Examination of Disposal Systems Capacity Based on Injected Water Quality
Authors: Al-Ajmi Mohammed D. , Al-Hajri Nasser M. , Al-Subaie Fehead M.
Published: July 2016

The sustainable operation of disposal systems that are part of wet crude handling facilities, is essential to ensure uninterrupted oil production from such plants. This paper will present the results of hydraulic simulation modeling of the capacity of a wastewater disposal system through an examination of the quality parameters for injected water. Applicable formation damage characterization methods, such as pressure transient analysis and continuous flow measurements, were utilized in this study to build representative models for each disposal well connected to System-A. The models were calibrated in a manner that couples surface and subsurface flow from the disposal pump all the way to the reservoir.

Water quality monitoring of disposed water was conducted by measuring the oil in water content. These data were, then, history matched with respective well injection performance to identify potential sources of well injection impairment.

An all-inclusive analysis, utilizing hydraulic simulation techniques, was performed to model the current injection performance and forecast the future reliability of a System-A disposal network, taking into account the impact of water quality and reservoir pressure variations. The collective inputs from laboratory analysis along with hydraulic simulation aided in formulating several key findings and recommendations with regard to setting appropriate limits of water quality control parameters.
Pinpointing Irregularities in a Well's Integrity: Case Study
Authors: Al-Thwaiqib Ibrahim , Ghanmi Ahmed , Al-Mulhim Abdullah , Bawazir Mustafa
Published: July 2016

Although early corrosion detection may allow preventive maintenance to reduce the risk of environmental damage and surface incidents (explosion, fire, leakage, and related consequences), many of the wells producing today were completed decades ago, when corrosion control and monitoring were not a primary concern. Even with today's technological advances, corrosion cannot be completely prevented, but it can be controlled and minimized through proper planning, monitoring, and maintenance.

Middle Eastern operators have experienced varying degrees of casing completion failures in recent years due to common highly corrosive, water-bearing zones across shallow depths. The electromagnetic (EM) pipe inspection tool provides critical monitoring for evaluating casing integrity by locating, identifying, and quantifying damage and corrosion. Failure to address potential corrosion attack can impact well profitability as operators must respond by implementing extensive and potentially expensive restoration methods. Not only does mitigation increase operating expenses, it may force operators to shut-in well production for unplanned periods of time.

The immediate aim of the examples presented in this paper is to understand the levels of corrosive damage that are present in the wells; that have serious repercussions on the flow efficiency of completions. This assessment of well integrity investigations is used to identify any extensive corrosion in the outer casing before it penetrates through the inner casings. The provided field examples were logged rigless to establish the condition of multiple pipes. Corrosion intervals were suspected of being responsible for reducing well performance and killing the wells. Casing metal loss (ML) evaluations assisted in identifying which wells need workover attention to avoid excessive loss in production, environmental pollution, repair costs, or accidents.
New Data-Driven Method for Predicting Formation Permeability Using Conventional Well Logs and Limited Core Data
Authors: Shabab Mohamad , Jin Guodong , Negara Ardiansyah , Agrawal Gaurav
Published: July 2016

The need for improved data accuracy, cost effectiveness and delivery time to assist in decision making has gained importance in reservoir characterization and evaluation. This paper presents a robust and inexpensive data-driven method for predicting the formation permeability profile from conventional well logs (CWLs) using the support vector regression (SVR) technique with limited core measurements. The method's feasibility and applicability are demonstrated on one field data set from a North Sea well contained a complete suite of logs and extensive core measurements.

The relationship between formation permeability and well logs is often overwhelming complex and nonlinear. We use the SVR method to establish the correlation between CWLs and limited core permeability, thereafter building a permeability-prediction model as a function of selected well logs. The basic logging data used here include density, neutron, deep resistivity, compressional and Stoneley wave slowness. The permeability derived from these well logs generally compares well with the measured core permeability. Additional logging data including the clay weight fraction, thorium/potassium content, or nuclear-magnetic-resonance (NMR) bulk volume movable and irreducible are also separately integrated into those basic logs to determine if the prediction accuracy can be improved. There is no obvious difference among the predicted permeability profiles even these additional well logs are added, which could imply that the basic logs are sufficient to generate the permeability with good accuracy.

SVR method could be used to improve the log interpretation accuracy as shown in this study. It can be easily adapted to predict other rock electrical, mechanical and petrophysical properties when only conventional logs and few core measurements are available. It is especially useful for unconventional reservoirs where traditional models may not be applicable and new methods are still evolving. Such new data analysis technologies could optimize our logging service and core analysis planning.
Assessment of Capillary Pressure Heterogeneity to Optimize Oil Recovery & Development Cost of Carbon Dioxide Floods
Authors: Al Sulaiman Ahmed A. , Krinis Dimitrios , Hossain M. Enamul
Published: July 2016

Carbon dioxide injection has been widely used as an EOR process, even in carbonate reservoirs with complex rock system. In order to enhance the post water flooding recovery, CO2 exposure with the remaining oil in lower zones should be maximized. This is a great challenge, as CO2 is considerably lighter than oil making gravity the dominant force. However, reservoir complexity can influence CO2 penetrating distance before a complete gravity segregation occurs. Therefore, understanding the reservoir heterogeneity and corresponding impact on oil displacement is a key to successful CO2 flooding projects. Particular focus was placed on vertical variation of oil-water capillary pressure and relative permeability curves.

This paper provides a detailed assessment of heterogeneity based oil-water capillary and relative permeability curves on ultimate oil recovery by CO2 floods. In addition, it studies the effect of CO2 vertical placement, well type, CO2 injection rate, and simultaneous CO2 and water injection on recovery. This was achieved with a numerical simulation approach using a commercial simulator, ECLIPSE. Numerous sensitivities were carried out with a conceptual 3D model undergoing water and CO2 flooding to optimize ultimate recovery at minimum cost. The investigation is based on two scenarios in which the complexity of the vertical capillary and relative permeability curves was varied.

The results from both scenarios showed consistent trend indicating that the variation in oil-water capillary and relative permeability curves can influence the oil- CO2 exposure thereby affecting the ultimate recovery. Among the considered factors, CO2 injection rate has the greatest influence on the ultimate recovery. The heterogeneity in capillary pressure and relative permeability causes CO2 to penetrate longer distance before a complete tonguing occurs. The maximum oil- CO2 exposure was achieved in the case where the highest contrast in such transport properties exists between the top zones. At higher CO2 injection rates, additional recovery gains were achieved as CO2 penetration was enhanced further by viscous force. The recovery gain increases even more with simultaneous CO2 and water injection. Moreover, results obtained from shallower water and deeper CO2 injections were encouraging. The effect of CO2 placement was found of a concern only in cases where the highest capillary pressures exist in the top zones. Limited effect was observed by the well type, thus injection of CO2 in shallower layers in vertical wells could be a cost effective option. The ultimate oil recovery for both scenarios post-optimization has increased remarkably compared to water flooding and CO2 pre-optimization cases.
Collosion Avoidance Awareness and Mitigation Measures
Authors: Dabyah Ali Al , Sananiry Abdel Rahman , Al-Shehri Fayez
Published: July 2016

Collision avoidance, one of the hottest subjects in the oil and gas industry, must be treated as high priority before executing any drilling programs. Wellbore collision avoidance procedures have a huge impact on the wellbore placement for targetson many desired reservoirs. A well planner/ drilling engineer must perform these procedures at the very beginning of the well planning stage, especially if the drilling involves platforms. Having a trusted historical database of the field is crucial, and this is where the integrity of the survey database and the survey programs provided by client must be reviewed very carefully. Any human error, software malfunction, or incorrect surveys can lead to major accidents at the rigsite, death of, worker injuries, environment pollution and financial losses.

This paper discuss the basic clearance calculations that indicate how far away one wellbore is from another and the mitigation measures that should be followed to have a valid collision avoidance procedures.
A Numerical Investigation on the Performance of Alkaline-Surfactant-Polymer Flooding in Naturally Fractured Carbonate Reservoirs
Authors: Mohammed Marwan N. , Hossain M. Enamul
Published: July 2016

Naturally Fractured Reservoirs are important contributors to the world's oil and gas reserves representing around one-fifth of the world's reservoirs. They usually are of lower recovery and higher residual hydrocarbon saturation than the rest of reservoirs due to its mixed wettability, low matrix permeability, low fracture porosity, and the complicated fracture network. When alkaline-surfactant-polymer flooding is conducted, it enhances the recovery by altering the wettability, lowering the interfacial tension of the rock, reducing the mobility ratio, and forming a secondary in-situ surfactant, consequently reducing the residual hydrocarbon saturation. However, majority of ASP operations usually underestimate the complicated structure and description of reservoirs. As a result, this lacking causes a serious flood modeling issue on NFRs since they rely on the matrix system mainly being the storage of hydrocarbon, and the fracture system carrying out the production.

This paper presents a comprehensive study on modeling ASP flooding on NFRs. It mainly addresses the effects of wettability, IFT, capillary forces, fracture parameters along with fracture and matrix permeabilities on ASP using a dual porosity and dual permeability model. It also addresses the performance, recovery factor and the optimum slug size for an optimum EOR operation, as well as to give guidelines and theoretical justification for better flooding practices based on a modeling approach only.

Sensitivity analyses on the constructed model of slug size, initiation time, sequence of injection, and concentration are done. Results show the optimized slug sizes of the injectants (i.e. 200 stb/day: 1 year of pre-injected water, 2 years of AS slug and 2 years of ASP slug), optimum initiation time and sequence of injection (1 year of water pre-injection followed by the ASP slug then followed by water flooding), in addition to the optimum concentrations of chemical injectants (alkaline and polymer concentrations of 50 lb/stb each, and surfactant concentration of 30 lb/stb). Also sensitivity analyses on the mentioned parameters are conducted and the results show how they affect NFRs. The study introduces a non-conventional injection method named Cyclic Alkaline-Surfactant-Polymer flooding. The performance and effectiveness of C-ASP are presented in addition to a comparison between C-ASP and conventionally used methods.
Simulation of Ionic Liquid Flooding for Chemical Enhance Oil Recovery Using CMG STARS Software
Authors: Dahbag Mabkhot S. , Hossain M. Enamul
Published: July 2016

A significant portion of crude oil remains in the reservoir after the application of conventional recovery. To meet the growing demand for energy, enhanced oil recovery (EOR) methods should be used efficiently to recover the extra amount of trapped crude oil after water flooding. Surfactant flooding is one of chemical EOR methods that can be implemented to recover oil from the remaining oil-in-place. Ionic liquids (ILs) which are salts having a melting point below 100 °C, can be considered as a prospective alternative to surfactant because of their superiority on surfactant in different points. Ionic liquids have unique advantages such as low cost, low toxicity, recyclable and high ability to work in harsh environments. In this work, three simulation runs were conducted to simulate core flooding experiments with an ionic liquid solution at different scenarios. Surfactant flood model (SFM) which is available in CMG STARS software was used to match the simulation results of oil recovery, well bottom-hole pressure, and imbibition relative permeability curves with flooding experimental results. The purpose of this paper is to prove the validity of core flooding experiments with ionic solutions to be simulated with SFM model. In addition, transfer the experimental work to simulation in order to facilitate the performance of other scenarios and to predict the future results through flooding with an ionic liquid solution. All three scenarios have given a good matching between simulation and real data of oil recovery, well bottom-hole pressure and imbibition relative permeability curves. Both simulation and experimental results indicated that secondary continuous flooding with IL solution gives oil recovery (71% original oil in place, OOIP) greater than secondary slug size flooding (64% OOIP); whereas tertiary flooding with IL solution was the lowest one with 48% OOIP.