Alabama

Globally, most oil fields are on the decline and further production from these fields is addressed to be practical in cost-effectiveness and oil productivity. Most oil companies are adopting two main technologies to address this: artificial intelligence and enhanced oil recovery (EOR). But the cost of some of these EOR methodologies and their subsequent environmental impact is daunting. Herein, the environmental and economic advantage of microbial enhanced oil recovery (MEOR) makes it the point of interest. Since, there is no need to change much-invested technology and infrastructure, amidst complex geology during MEOR application, it is entrusted that MEOR would be the go-to technology for the sustainability of mature fields.

Despite the benefits of MEOR, the absence of a practical numerical simulator for MEOR halts its economic validation and field applicability. Hence, we address this by performing both core and field- scale simulations of MEOR comparing conventional waterflooding. The field scale is a sector model(fluvial sandstone reservoir with 13,440 active grid cells) of a field in Asia - Pacific.

Here we show that pre-flush inorganic ions (Na⁺ and Ca²⁺) affect the mineralization of secondary minerals which influences microbe growth. This further influences carboxylation, which is relevant for oil biodegradation. Also, as per the sensitivity analysis: capillary number, residual oil saturation and relative permeability mainly affect MEOR. Secondary oil recovery assessment showed an incremental 6% OOIP for MEOR comparing conventional water flooding. Also, tertiary MEOR application increased the oil recovery by about 4% OOIP over conventional water flooding. It was established that during tertiary recovery, initiating MEOR after 5years of conventional waterflooding is more advantageous contrasting 10 and 15years. Lastly, per probabilistic estimation, MEOR could sustain already water-flooded wells for a set period, say, a 20% frequency of increasing oil recovery by above 20% for 2 additional years as highlighted in this study.

This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC.

ABSTRACT: Accurate knowledge of formation strength is essential for geomechanical modeling, borehole failure and in situ stress analysis. Laboratory strength measurements are limited in scale and spatial extent, posing significant challenges for extrapolating strength measurements, especially in highly heterogeneous formations such as fluvial and lacustrine sedimentary rocks. Acoustic/sonic P-wave velocity (Vp) provides one of the best proxies for formation strength, but it is stress- and frequency-dependent. Vp-strength relationships, therefore, can be very sensitive to experimental conditions. In this study, we investigate Vp-strength relationships for Mesozoic rift basin formations based on measurements on over 70 samples from the Newark Rift basin, a candidate site for geologic CO₂ storage and one of the largest in a series of the Mesozoic rift basins on the eastern North-American coast. Elastic wave velocity measurements were obtained for a range of confining pressures from ~2 to ~41 MPa, roughly corresponding to in situ confining pressure range. Although, overall, Vp values tend to increase with increasing pressure, the degree of Vp response to stress varies dramatically from sample to sample, and does not appear to correlate directly to lithology or porosity. Laboratory Vp measurements agree well with corresponding sonic logs; therefore, a systematic frequency-dependent core-log difference is not observed, but accounting for Vp dependence on confining pressure is important. We quantify the Vp-pressure dependence using laboratory acoustic measurements and develop depth-dependent Vp-strength relationships. These could be used with sonic logs to improve geomechanical analysis, and could be potentially applied in similar Mesozoic rift basin formations.

1. INTRODUCTION

Formation strength is a key parameter in reservoir geomechanics and borehole stability analysis (e.g., Zoback, 2010), but it cannot be continuously measured in situ. A standard approach is to measure rock strength on discrete samples ex situ; however, such laboratory strength measurements are limited in scale and spatial extent, potentially posing challenges in extrapolating strength values, especially in highly heterogeneous and fractured formations. To address these problems, and to provide a solution in the absence of drill cores, a number of relationships between strength and other formation properties such as velocity, elastic moduli, and porosity, have been proposed for various geologic settings (e.g., Horsrud, 2001; Lal, 1999; Vernik et al., 1993). P-wave velocity (Vp) is a particularly attractive target for correlation to strength, as it can be reliably measured in situ with various geophysical techniques, such as well logging and seismic data analysis.

ABSTRACT

Fluid mud and fluidized muck measured during an environmental dredging project used passive sondes and a sampling protocol to quantify bottom boundary layer cohesive sediment flux density. Results describe the efficacy of dredging using movement of fluidized particulates as a surrogate estimation of muck movement reduction (MMR). Horizontal flux arrays passively capture moving particulate material. Near bottom fluid mud transport exceeds surface fluxes by more than 400 times. The results are important since they clearly demonstrate how the sondes can be used to passively capture and quantify high concentrations of fluid mud and muck within the marine bottom boundary layer.

INTRODUCTION & BACKGROUND

The purpose of this paper is to describe results a study and ongoing research related to the design, application and deployments of in-situ arrays of sondes. The passive collection devices and protocol for their use is intended to quantify the vertical structure of the horizontal mass flux density of fluid mud movement in the marine bottom boundary layer. During deployment periods of half a day, days, weeks and months the sondes integrate sampling of particulates passing through a cross-sectional area and thus perform continuous spatial-temporal measurement of moving particulate matter within the lutocline. The need for sampling water and sediment characteristics that integrate spatial and temporal time scales has been reported in Gibbs and Konwar (1983) and Bianchi (2007). It has been noted that cohesive sediment particles such as flocs and colloidal aggregates within the bottom boundary layer lutocline cannot be sampled with traditional sampling techniques. The measurement protocol used to address the above sampling requirements make use of arrays (vertical and horizontal) of sondes designed to directly measure mass flux density (g m⁻² day⁻¹) of resuspended cohesive sediments in coastal water bodies.

Using the passive sondes allows measurements to be made that avoid noisy calibration problems common to optical and acoustic backscatter sensors (Gartner, 2009) that are spatial point measurements. These instruments do not have flux conserving properties used to estimate mass transport of fine grain particulate matter in the bottom boundary layer. In general, the use of the sonde technique allows one to passively capture or trap flocs and colloidal aggregates that move within or near the bottom lutocline as the particulates pass thru the sonde’s horizontal cross-sectional area opening. The sondes can be deployed in different horizontal directions. This deployment procedure allows the fluid mud particles to enter the sonde through its cross sectional opening. Thus, fluid mud fluxes in different flow directions are quantified as shown in previous studies and described in Rotkiske and Bostater (2015).

Single-well production data analysis (PDA) is an important subject to understand reservoir productions. This is commonly done with traditional methods/analytical models. But analytical models suffer from limited accuracy and applicability issues due to the way production data is matched, the error involved, and the assumptions that sometimes over simplifying the problem. Therefore, in this work, the authors want to provide an assessment of Ensemble Kalman Filter (EnKF)-based production data analysis model on single-well production.

By assuming homogeneous and isotropic reservoir permeability in a single-layer reservoir, we first formulate the basic EnKF algorithm and link it with single-well reservoir model. Results indicate estimation of skin factor and reservoir permeability present accuracy issues: large error for some cases and uncertainty bounds do not cover true values. Based on our evaluations, we propose the method of increased initial uncertainty bound and over estimating initial observation noise variance to improve the estimation. The method is tested with synthetic models, and results indicate that mean estimate have better match with true value, and the true values fall within a reasonable uncertainty bounds of the ensemble data predictions. Production data from 31 wells in real field are used for further verification. Excellent data matches are obtained with EnKF.

The model in the work could provide a reasonable estimation of reservoir properties for both synthetic and real-field cases. We also show that statistical inconsistency and poor data matches are encountered when matching production data for some extreme cases when permeability of damaged/stimulated zone is drastically different from reservoir permeability. But this issue could be alleviated with the proposed method. The model and method in this study proves to be applicable for real field evaluation.

We present readers with an implementation of EnKF-based in single-well production data analysis to overcome accuracy and applicability issues related with traditional analytical methods. We documented the accuracy and efficiency one could expect when applying this method in both synthetic models and real-field data to evaluate skin factor, drainage area, and permeability. We also proposed and verified a methodology to improve estimation accuracy under some extreme cases when estimation of skin factor possess a problem. This paper could provide a guild to the readers when constructing their own production data analysis model.

This award is intended to acknowledge the section and YP committee officers for outstanding efforts in the areas of interest to young professionals and other industry newcomers. The award will be given in three categories: - Overall Excellence - Most Improved - Most Innovative Winners will be announced at the President's Luncheon at SPE's Annual Technical Conference and Exhibition (ATCE). Plaques will be presented to the YP committee and section officers. Please note that the award for Outstanding Section YP Committee does not replace the President's Awards for Section Excellence. To be considered for this award, the section YP committee chairperson should complete the form below and send it to the section chair for submission with the section's annual report.

There has been recognition in the oil and gas and mineral extractive industries for some time that a set of unified common standard definitions is required that can be applied consistently by international financial, regulatory, and reporting entities. An agreed set of definitions would benefit all stakeholders and provide increased - Consistency - Transparency - Reliability A milestone in standardization was achieved in 1997 when SPE and the World Petroleum Council (WPC) jointly approved the "Petroleum Reserves Definitions." Since then, SPE has been continuously engaged in keeping the definitions updated. The definitions were updated in 2000 and approved by SPE, WPC, and the American Association of Petroleum Geologists (AAPG) as the "Petroleum Resources Classification System and Definitions." These were updated further in 2007 and approved by SPE, WPC, AAPG, and the Society of Petroleum Evaluation Engineers (SPEE). This culminated in the publication of the current "Petroleum Resources Management System," globally known as PRMS. PRMS has been acknowledged as the oil and gas industry standard for reference and has been used by the US Securities and Exchange Commission (SEC) as a guide for their updated rules, "Modernization of Oil and Gas Reporting," published 31 December 2008. SPE recognized that new applications guidelines were required for the PRMS that would supersede the 2001 Guidelines for the Evaluation of Petroleum Reserves and Resources. The original guidelines document was the starting point for this work, and has been updated significantly with addition of the following new chapters: - Estimation of Petroleum Resources Using Deterministic Procedures (Chap.

More than 60% of gas reserves in the Middle East region are regarded as sour. The development of sour oil and sour gas fields or originally sweet oil fields, which undergo a souring process during production live, impose significant investments for the H₂S treatment and increase significantly the field operation costs. In order to evaluate the origin and development of the H₂S in a production system multiple locations covering all process stations such as down hole, well head, separators, gathering stations, pipelines have to be sampled an analysed. The in-field measurements of the H₂S concentrations and various laboratory analyses like S³⁴ / S³² isotope ratio, CSIA, DNA sequencing, MPN and Bacterial growth tests could be performed in order to provide a conclusive picture of the H₂S contamination.

The most promising and cost efficient technology is the analysis of the bacterial activity using DNA analysis and bacterial growth tests. The integration and interpretation of all above mentioned analysis types is key for the evaluation of the origin and development of the field souring process and provides a robust analytical basis for remediation, scavenging and mitigation operations. In combination with modern dynamic reservoir modeling tools, which allow the history match and forecast of the field souring process, the efficiency of mitigation or scavenging operations in the subsurface and at the surface can be simulated and optimized.

In context with the envisaged production enhancement, the application of EOR technologies and the souring of several reservoirs due to injection, the monitoring and handling of additional H₂S production become an important environmental and economic factor.

Numerous oil and gas reservoirs in Kuwait are suffering from H₂S contaminations. The H₂S concentrations in the affected reservoirs vary significantly from low ppm ranges up to 40%. The H₂S concentration levels are related to the generation processes. The high H₂S concentrations observed in the Lower Jurassic reservoirs can be related to the TSR process. The dominant H₂S generation process in the Upper Jurassic and Lower Cretaceous reservoirs is the thermal cracking of the organic sulphur compounds (OSC) occurring in the Najmah and Sargjelu source rocks. The H₂S contaminations observed in the Cretaceous reservoirs show indications of multiple H₂S sources. The bulk of the H₂S in these reservoirs is generated in situ by the BSR process. In some fields clear indications for H₂S migrated from deeper horizons e.g. via faults are observed.

H₂S contaminations are also observed at the top site facilities at various stages of the production process. The source for those contaminations is only partly in the subsurface. In several cases a distinct increase of the H₂S contaminations of the fluids on its way from the reservoir well to the processesing facilities is observed.

New sampling and analytical technologies tailored to the H₂S problematic have been developed, which support the selection of the appropriate mitigation or remediation strategy. The utilization of modern low cost DNA sequencing technologies for the analysis of the bacteria and archea species provide essential information for the design of appropriate chemical cocktails for the mitigation.

Reservoir modeling and forecast technologies have been developed to predict the development of the H₂S concentrations in a reservoir. However, for a reliable forecast - irrespective which modeling system or tool is applied - the understanding of the H₂S generation process is essential. Furthermore good quality and reliable H₂S measurements are mandatory for the history match.

The mitigation and remediation of H₂S is a major cost factor in the field development and operations. Field souring i.e. the increase of the H₂S concentration during field life is the worst case scenario, which could cause major investments to assure field production. Not only the costs for the H₂S treatment materials (e.g. biocides, nitrate) but also the investments in corrosion inhibitors, H₂S resistant pipes, valves, filters, and the upgrade of the processing facilities have a large financial impact. Furthermore HSE related measures and required safety and monitoring systems are increasing substantially the operation costs.

In view of KOC's ambitions to increase the oil production by 20% by 2020 and the subsequently expected increase of H₂S production, a contry-wide coordination of the treatment concepts for the H₂S could improve the efficiency of the mitigation operations and could potentially reduce the investments and operation costs related to the sour gas issue.

The Agbami field is one of the largest producing deep-water assets in Nigeria. It was discovered in 1998 and put on stream in 2008 with the field development staggered into three phases. Adopting a phased approach has eased the burden of project management and allowed the Asset team incorporate the key learnings of each phase into the subsequent phases while reducing uncertainty and improving decision making to derive maximum value from the asset. With the third phase of the field development approaching its later stages, it became necessary for the Asset team to take a second look at the wealth of data that had been gathered in the 7 years of production and reevaluate the subsurface understanding with a view to identifying bypassed or unswept oil that could potentially increase recovery from the reservoirs. Uncertainties are inherent in every project and the Agbami project is no exception being a major capital project with its fair share of uncertainties.