This paper focuses on laboratory tests concerned with the lateral behavior of a rod representative of part of a drill-string in the area of rotary oil drilling. The original experimental set-up takes into account the curvature of the rod, mud, stabilizers and rotation speed. The lateral behavior of the drill-string subjected to the axial excitations of the bit is governed by time varying parameter equations due to torsion-lateral and longitudinal-lateral couplings. The experimental results highlight the different kinds of lateral instabilities and they are compared either with existing experimental, or theoretical results. The experimental investigation described in this paper is included in a wide ranging study which also involves theory and the development of a computer code, both briefly presented here.

Hydrocarbon gas injection is the most widely applied process after waterflooding, and is a promising enhanced oil recovery (EOR) injectant for use in Middle East carbonate oil fields. Gas injection improves microscopic displacement efficiency and generally acts as pressure maintenance; however, unfavorable mobility ratio can negatively impact the ultimate recovery due to viscous fingering and gravity override. This paper describes two gas injection pilots that have been implemented in offshore Middle-East carbonate reservoirs, a secondary and a tertiary gas injection through line drive to assess injectivity, productivity, macroscopic sweep efficiency, flow assurance and operational efficiency in a field that has long water-injection history. A strong monitoring plan, including an observer well, was applied through time-lapse saturation logging, pressure measurements, production testing, tracer campaign, etc. to evaluate the pilot efficiency and address key uncertainties upfront prior to full-field application.This paper describes the pilot performance in the context of full-field development, local and macroscopic displacement efficiency, flow assurance issues, and operational learnings. The gas injection performance is strongly impacted by reservoir heterogeneity, gravity segregation and the existing pressure gradient, and the history match performed indicates near-miscible or miscible behavior depending upon local pressure regimes, which thus govern the ultimate recovery. The history match also shows that for the same pilot, performance can be further improved through water-alternating-gas (WAG) injection, resulting in a viable development scheme for full-field implementation.

Hydrocarbon gas injection projects are undertaken in order to maintain reservoir pressure, produce oil through swelling and reduce residual oil saturation by decreasing the interfacial tension (IFT). Along with local displacement efficiency, macroscopic sweep efficiency plays a dominant role in the success of gas injection projects, as recovery from the field depends strongly on reservoir geology and petrophysical properties. In this paper, a case study of one of the hydrocarbon gas injection pilots is discussed as the performance of the other two pilots has already been described in Kumar et al. 2015a. A five-spot pattern hydrocarbon gas injection pilot in tertiary mode has been carried out in a giant carbonate reservoir offshore Middle East, which has long peripheral water injection history. A comprehensive monitoring plan, including an observer well, was applied through time-lapse saturation logging, single well chemical tracer test (SWCTT), pressure measurements, production testing, and tracer campaign to assess the pilot performance and minimize uncertainties before large-scale application. This paper presents the overview of the pilot, monitoring plan and the findings which include microscopic and macroscopic sweep efficiency. The pilot areal sweep performance was affected by the existing pressure gradient of peripheral water injection while the vertical sweep efficiency was strongly affected by the reservoir heterogeneity. At the cessation of the pilot, a value of 6 ± 3% was measured from SWCTT in the producer well, which shows the robustness of the gas local displacement efficiency. The history match performed indicates that for the same pilot, the performance can be improved using horizontal line drive in place of five-spot pattern and it can further be enhanced through water-alternating-gas (WAG) injection. The learning from the three gas injection pilots is used in re-designing the future large-scale development plan and is described in details in Kumar et al., 2016a and 2016b.

Summary Hydrocarbon-gas injection is one of the most widely applied processes in the oil industry and is a promising enhanced-oil-recovery (EOR) method for use in Middle East carbonate oil fields. Gas injection improves the microscopic-displacement efficiency and generally acts as pressure maintenance; however, unfavorable mobility ratio can negatively affect the ultimate recovery because of viscous fingering and gravity override. This paper describes two gas-injection pilots that have been implemented in offshore Middle East carbonate reservoirs: a secondary and a tertiary gas injection through line drive to assess injectivity, productivity, macroscopic-sweep efficiency, flow assurance, and operational efficiency in a field that has a long water-injection history. A strong monitoring plan, including an observer well, was applied through time-lapse saturation logging, pressure measurements, production testing, and a tracer campaign to evaluate the pilot efficiency and address key uncertainties upfront before full-field application. This paper describes the pilot performance in the context of full-field development, local- and macroscopic-displacement efficiency, flow-assurance issues, and operational learnings. The gas-injection performance is strongly affected by reservoir heterogeneity, gravity segregation, and the existing pressure gradient, and the history match performed indicates near-miscible or miscible behavior depending upon local pressure regimes, which thus govern the ultimate recovery. The history match also shows that for the same pilot, performance can be further improved through water-alternating-gas (WAG) injection, resulting in a viable development scheme for full-field implementation.

Abu Dhabi's mature field with more than 50 years of production history and over 350 wells that is presented in this paper is one of the world's largest offshore oil fields. As oil fields mature, water and gas breakthroughs become increasingly frequent and the understanding of fluid movement becomes crucial for proper reservoir management, efficient remedial works and optimum workovers and future wells drilling, which all expected to enhance oil recovery. This paper introduces an innovative logging technique designed to track fluid movement deep in the formation in flow and no-flow intervals and through casing.

Carbon dioxide (CO2) injection is considered to be a viable option for enhanced oil recovery (EOR) and has already been implemented commercially for more than 40 years. However, the applications are limited to onshore and offshore application for EOR activities have not yet been implemented. This paper presents the subsurface evaluation using laboratory experiments (PVT and corefloods) and compositional modeling, the design and surveillance program of a CO2 pilot project planned in a carbonate reservoir located offshore Abu Dhabi. PVT and coreflood experiments demonstrate the local displacement efficiency of CO2 in tertiary mode due to gas-oil miscibility, swelling of oil and reduction in oil viscosity. The screening study performed using a tuned equation of state (EOS) predicts significant additional recovery in a previously waterflooded area. A pilot is planned in one of the reservoirs of the field, which has 40 years of peripheral seawater injection history. The pilot design is influenced by existing peripheral pressure gradient, and is located down-dip in the field that covers approximately 80 acres. The pilot location is selected based on geology, reservoir quality, maturity to waterflood and surface facility constraints. A comprehensive reservoir surveillance plan, including one to two observers well, is developed to monitor pilot performance. The planned pilot will reduce uncertainties and risk associated with CO2 injection and address bottleneck uncertainties in an offshore environment before large-scale application. The first offshore CO2 injection pilot is designed for implementation in a tertiary mode in a giant carbonate field, which is still under secondary recovery production, to minimize interaction with current production and impact on surface facility. The paper also presents the possible mitigation for various challenges identified like asphaltene, scaling, corrosion, impact on existing carbon steel well completion, etc. associated with CO2 injection. The methodology and technical analysis used to evaluate and design the CO2 pilot are applicable to other potential fields in the region.

This paper describes preparations and planning for a campaign of foam gas shut-off pilot operations in a large carbonate reservoir located offshore Abu Dhabi containing an oil column in equilibrium with a large gas cap. Throughout the field history and due to the heterogeneity (permeability ranges from 5 mD to 1 D), the major challenge to produce the oil rim independently from the gas cap was how to control premature gas breakthrough in the oil producers. Mechanical interventions in high gas-oil ratio wells are particularly complicated due to the risk of losing oil potential and are generally unsuccessful. Injection of foam for gas shut-off (FGSO) is a near-wellbore treatment, which has been trialed elsewhere in the industry with some success. Foam can act as an auto-selective agent to shut-off confined gas inflow through a gravity-controlled source like coning or cusping, while oil breaks the foam, resulting in preferential oil flow and reduction in gas-oil ratio. In addition, this type of operation has been identified as an EOR enabler, because it can help prepare for the technical and logistical challenges of using EOR chemicals in the field, generate data useful for the modeling of surfactant and polymer under reservoir conditions, and mitigate early gas breakthrough in the case of gas-based EOR developments. For the reservoir in question, a key complicating factor was to identify a surfactant, which could generate strong foam in-situ (mobility reduction factor of 50) at harsh reservoir conditions (temperature of 220-230 °F and water salinity above 200,000 ppm, including 20,000 ppm divalents), with an acceptable level of adsorption. The candidate selection process took into consideration overall behavior of the reservoir as well as performance of the individual high-GOR wells. Target well selection criteria included homogeneity of permeability, an understanding of gas sources and their movement, and observation of a rate- or draw-down-dependent GOR. The experimental lab program involved testing several surfactant formulations in bulk as well as in corefloods with and without the presence of reservoir oil to evaluate foaming ability and level of gas flow reduction. One formulation showed the right level of in-situ mobility reduction, in addition to stability and moderate adsorption at the prevailing reservoir conditions, and was therefore selected for a pilot test involving four wells.

The main objective of this study is to enhance a Predicted Permeability (K_Pred) by integrating Permeability resulted from the interpretation of more than 100 P.T.A. Initially the predicted permeability was generated using neural network method (Combining core and log data) over all 254 wells penetrating the reservoir. To achieve this task a number of workflows have been discussed and tested and finally two methods were implemented which resulted in two permeability models. The first model, consist of generating enhanced permeability maps for each porous zone using Permeability Predicted (K_pred), core and well test data. These maps were used as multiplier in Upscaled model to generate the total permeability then exported to reservoir engineer for simulation. The second model, consist of generating the enhanced permeability by integrating Permeability Predicted (K_pred), core and well test (KH) under each well (Log scale) in order to capture the dynamic changes of the property. This enhanced permeability was populated in geological model using stochastic methods conditioned to Rock Type and porosity.