Exploitation of heavy oil from deep reservoir is often dictated by appropriate selection of viscosity reducer and artificial lift. For the proposed pilot in this study, it is necessary to identify suitable viscosity reducer to produce heavy oil from deep reservoirs, with down-hole electrical submersible pump (ESP). Broad field data of this reservoir are depth of 9300 feet, crude API gravity of 10 and crude viscosity of 10000 centipoise, at 4500 psi of SBHP and at 190°F of BHT.The main objective of this study is to evaluate different viscosity reducer chemicals (VRC) for their efficiency in reducing the viscosity under severe reservoir conditions SARA analysis was carried out on flashed crude oil sample to check the asphaltene stability of samples. Series of viscosity tests were conducted using an electro-magnetic viscometer in order to test performance of different viscosity reducers at diverse temperatures and pressures conditions. Experimental studies showed that as pressure decreases, viscosity of oil sample decreases with reduction in temperature. However, when the effect of different viscosity reducers on representative oil sample was studied, at 5000 psi and at reservoir temperature of 190°F, it was noticed that reduction in viscosity of oil sample from 16,230 centipoise to less than 850 centipoise could be achieved.It is concluded from lab studies that reduction of viscosity of given heavy oil sample can be achieved with the help of suitable viscosity reducer to an extent, wherein, it is possible to operate downhole ESP and produce heavy oil from deep reservoir. Studies can also have practical application as an alternative planned production strategy to exploit such reservoirs. Study results definitely have far reaching influence to decide optimum dosage of viscosity reducer during execution. These studies can be seen as a representative model for performance comparison to test different viscosity reducers under diverse conditions. Studies also emphasized the need for carrying out meaningful lab studies for appropriate selection of viscosity reducers; while planning exploitation of heavy oil and deep reservoirs.

A number of heavy oil or tar accumulations have been reported in several Middle East reservoirs. Heavy oil is often overlooked as a resource because of the expense and technical challenges associated with producing it.But more than 6 trillion barrels of oil in place attributed to the heaviest hydrocarbon. Most of the conventional onshore hydrocarbon reservoirs have been depleted, and time of easy hydrocarbon is over; so, it is prudent to look into the unconventional reservoirs like heavy oil. An accurate evaluation and characterization is obviously crucial to its efficient exploitation. The evaluation and characterization of heavy oil depends on its identification, quantification, analysis of representative fluid sample and reservoir properties.The methods proposed in the literature might be successful in identifying heavy oil reservoirs but are less reliable for quantifying the amount of heavy oil, and are insensitive to oil viscosity, the key property that controls the producibility of heavy oil. Heavy oil characterization is incomplete without the sampling of fluid in the reservoir environment. It is often desirable to acquire the sample with wireline formation tester tool and integrate the in-situ fluid properties with NMR logs.In this study we successfully integrate, conventional logs, NMR logs, in-situ fluid sample, PVT data and conventional core data for identification and quantification of heavy oil present in the pore space. This integrated study overcomes the limitations of individual techniques. Our case study shows that the porosity deficit between conventional total porosity and NMR porosity gives the identification of heavy oil present in the pore space, this difference between two porosities represents the extra viscous component of fluid that are not observable by the NMR tool. The amount of porosity deficit is the amount of extra heavy oil / tar in the pore space and this gives the quantification of the same.Conventional and NMR derived reservoir properties are required to be integrated with conventional core porosity, permeability, water saturation and viscosity derived from PVT sample in order to characterize Heavy Oil in Clastic Reservoirs.

Selecting the optimum combination of technologies is a critical and challenging activity while conducting the opportunity assessment under high levels of uncertainty in a deep (~9000 feet) extra heavy oil green field transitioning between appraisal and development phases. Low mobility requires enhanced oil recovery to be addressed early in the life of the field, so selected wells can be drilled and completed in selected locations to reduce uncertainty about producibility and flow assurance. This paper presents a practical approach to opportunity assessment based on Front End Loading (FEL) methodology, with three major steps: 1. Evaluation of known data, determination of complexities, uncertainties and risks by benchmarking with selected field analogs, 2. Identification of all potential technology options and 3. Definition of feasible appraisal and development scenarios and a high-level road map including estimates of life cycle cost opportunities for optimization. We found reservoir static complexity medium, well complexity low, and reservoir dynamic complexity high. FEL definition indices for reservoir and well indicated low reservoir definition and acceptable index for wells. These complexity and definition indices were used for conducting benchmarking with three analog fields providing references for risks and ranges of production, recovery and total cost. After multidisciplinary analysis with participation of 35 specialists organized into three clusters (subsurface, well and surface), 100 challenges (72 risks and 28 uncertainties) were identified, analyzed and ranked. Assessment of 36 parameters used for Enhanced Oil Recovery (EOR) screening were assessed from uncertainty perspective with preliminary selection of 7 potential EOR methods. Final integration was achieved with identification of 110 technology options for 30 key decisions, finally selecting best suitable options for 4 potential development chronological scenarios. Results are presented in a cost breakdown structure reflecting the most critical cost drivers, where high percentage corresponds to OPEX affected by identified risks and causal maps describes effects on total costs for subsurface, well and surface. We modeled all significant risks by visualizing its impact on total cost and we defined the mitigation actions ranked by risk adjusted stochastic economics performed as input for decision-making. This paper demonstrates that understanding the root causes of high cost per barrel and their relationship with uncertainties and risks during early stages of a heavy oil field life cycle, provides a common language for multidisciplinary cost optimization, and facilitates communication and involvement of all disciplines.

Effective exploitation of deep and heavy oil reservoirs is a strategic objective for KOC. It is observed that suitable mode of artificial lift is required to produce these reservoirs. Objective of present work, is to evaluate diverse challenges, offered by various artificial lift methods, to produce these reservoirs. Scope of work includes selection of appropriate artificial lift technology along-with suitable production methodology, to facilitate sustained production from these reservoirs. This study is carried out for representative deep and heavy reservoir of KOC. Perforation zone is at 9300 feet. Viscosity of well-fluid is 7800 centipoise at reservoir temperature of 190°F. API gravity of well-fluid is 10. It is known that well-fluids can flow to the well-bore; but cannot flow to the surface. Analysis of various artificial lift systems, such as, Gas Lift, SRP, PCP, ESP and Jet Pump, is carried out, with reference to the available well data and field operational constraints. Study also encompasses need for any other technology, which is required along-with artificial lift, to produce this reservoir. It is observed that it is not possible to use either SRP or PCP because both have limitations, to operate, at high depths. It is not possible to employ gas-lift, due to constraints related to availability of injection gas. ESP and Jet Pump, are the only two technically feasible lift modes. It is perceived that ESP is more suited than Jet Pump, with regard to the issues, like, cost, operational ease, surface foot-print and HSE. However, with regard to our simulation studies, it is observed that it is not possible to produce this reservoir, with ESP alone because due to high viscosity of well-fluids. Therefore, use of downhole heater below down-hole ESP or continuous injection of suitable viscosity reducer, below down-hole ESP, is considered. Either of this, add-on utility can help to reduce viscosity of well-fluids, to such an extent; wherein, it is possible for down-hole ESP, to lift well-fluids up to the surface. Study also entails laboratory work, which is carried out to select suitable viscosity reducer, with reference to the oil sample of this reservoir. It is concluded from simulation studies that target rate of 500 b/d can be achieved with ESP, to produce this reservoir, provided it is backed-up by proper mechanism, to reduce viscosity of well-fluids, before well-fluids enter into the pump. Study has adequately addressed challenges, offered by various artificial lift modes, to produce deep and heavy oil reservoirs. It is also inferred from the studies that coherent integration of suitable lift system with other compatible technologies, is essential, to achieve sustained production from this reservoir. The study constitutes crucial benchmark for us, to decide future production strategy to exploit similar reservoirs. The study can serve, as a useful reference guide, for exploitation of deep and heavy oil reservoirs, of comparable nature.

KOC planned to drill a challenging horizontal well in Ratqa field where there are serious limits to build deviation, reservoir navigation and hole instability. The candidate well was targeted into early Cretaceous Zubair reservoir, a highly laminated sand/shale sequence. Objective of this horizontal well is to target two highly depleted thin reservoirs (UCH and LCH) within Zubair, with a thick shale layer in between. While navigating the wellbore optimally through sweet spots within the reservoir units is a challenge, the risks of shale instability and differential sticking are other expected challenges during drilling. The target reservoirs sequence is around 8-10ft thick and there is 8ft thick interbedded shale separating the two sands. How to land the well properly inside the upper channel with optimum exposure of two sand units is one concern, and stability of interbedded shale at high angle is another concern. In order to mitigate these issues, pre drill geo-mechanical modelling was performed to predict the require mud weight and real time geo-mechanical monitoring was also carried out in conjunction with geo-steering. The resistivity contrast of these sands is around 70Ωm versus 10Ωm, which would give 9ft – 10 ft depth of detection (DOD) for azimuthal resistivity tool. This service would help to place the well optimally inside the reservoir and also provide early warning before exiting reservoir. The well was landed 7ft TVD inside the upper channel and continued building to 90° inclination in the lateral section with mud motor in order to build faster and also to prevent any stuck up with high configuration tool. The re-logged section confirmed that the wellbore already reached the base of upper channel. It was then decided to continue drilling to lower channel by crossing the interbedded shale using 9.5ppg mud weight in order to keep options open for running Inflow Control Devices (ICD). However, tight hole, over pull, pack-off, bit stalling, bigger size cavings etc. indicated poor wellbore condition. As drilling with lower mud weight already initiated shale instability it was then attempted to gradually increase the mud weight to avoid further deterioration of hole condition. It was then decided to sidetrack the section with a mud weight of around 12+ppg, as recommended by the pre-drill model. In addition, mud formulation was adjusted to block micro-fractures/invasion into shale to reduce differential sticking risk. Real-time wellbore stability monitoring was carried out including LWD log responses, cavings characterization, hole condition monitoring, etc. The wellbore was built to 89° inclination upon entering the lower channel as per correlation and was maintained inside the lower channel. The lateral section achieved 1,120ft long footage with a 78% exposure inside the sweet spot. Integrated real-time geo-steering and geo-mechanics successfully helped placing the well optimally in the target sands without hole instability.