Track Fractured Well Inflow Performance Using Historic Production Logging and Surface Well Performance Data in Sultanate of Oman

PDO operates about 200 deep gas wells in the X field in the Sultanate of Oman, producing commingled from the Barik gas-condensate and Miqrat lean gas reservoir completed by multiple hydraulic fracturing. Their inflow performance relation (IPR) is tracked to diagnose condensate damage, hydraulic fracture cleanup and differential reservoir pressure depletion. The best IPR data is collected through multi-rate production logging but surface production data serves as an alternative. This paper describes the process of deriving IPR's from production logging and surface production data, and then evaluates 20 years of historic IPR data to quantify the impact of condensate damage and condensate cleanup with progressive reservoir pressure depletion, to demonstrate the massive damage and slow cleanup of hydraulic fractures placed in depleted reservoirs, to show how hydraulic fractures facilitate the vertical cross-flow between isolated reservoir intervals, and to highlight that stress-dependent permeability does not play a major role in this field.

First Permanent Inflow Monitoring Experience in a Smart-Liner, Intelligent-Completion, Multi-Lateral Adnoc Offshore Well

The scope of this paper is to share a field experience with permanent inflow tracer deployment and monitoring of an intelligent multi-lateral well, completed with Smart-Liner (Limited Entry Liner). It will describe what ADNOC Offshore has learnt through inflow tracing clean up surveillance from several restarts and steady state production through inflow modelling interpretation techniques. This passive method of permanent monitoring technology utilizes chemistry and materials expertise to design tracers that release signature responses when they come into contact with either in-situ oil or formation water. The chemical tracer technology enables wireless monitoring capabilities for up to five years. Unique chemical tracers are embedded in porous polymer matrix inside tracer carriers along select locations in the lower completion to correlate where the oil and water is flowing in a production well. Interpreting tracer signals can provide zonal rate information by inducing transients to create tracer signals that are transported by flow to surface and captured in sample bottles for analysis. The measured signals are matched with models through history matching to yield zonal rate estimates. ADNOC Offshore has installed inflow tracers in an intelligent multi-lateral well to monitor laterals’ contributions, to verify new completion technology, and to estimate the flow profile from individual sections of Smart-Liner, run for the first time in the field. The interpretation results have been able to characterize inflow performance without any intervention in the well. Several restart and steady state surveys are planned to understand some key characteristics of the well completion and reveal how the well has changed since it was put on production. This technology will help allocate commingled production to the three laterals. The use of inflow tracers will provide multiple inflow surveys that will reduce operational risk, well site personnel, costs and will improve reservoir management practices. Permanent inflow tracing is expected to change the way production monitoring can be performed, especially in advanced wells where PLTs or Fiber Optic technology cannot access multi-laterals.

Semi-Analytical Method for Accurate Calculation of Well Injectivity During Hot Water Injection for Heavy Oil Recovery

Representation of wells in numerical simulation of petroleum reservoirs is a challenging task due to large difference in typical scales of grid blocks (tens to hundreds meters) and wells (~0.1 m), with high pressure and saturation gradients around wells. Although a variety of grid refinement techniques can be used for local simulations, they have limited application in field-scale problems due to huge model dimensions. Thus, auxiliary quasi-stationary local solutions (so-called inflow performance relations) are used to relate well flow rate with well and grid block pressures. These auxiliary solutions are strictly derived for linear cases and generalized to non-linear problems by using grid-block averaged values of fluid and reservoir properties. In the case of hot water injection for heavy oil recovery, this results in significant errors in well injectivity calculations due to large temperature and saturation gradients dynamically influencing viscosity and relative permeability distributions around the well. In this paper we propose a method which combines a semi-analytical solution of the hyperbolic Entov-Zazovsky problem for non-isothermal oil displacement with integration for pressure distribution taking into account nonlinear dependencies of fluid viscosities and relative permeabilities on temperature and saturations. Both constant injection rate and constant well pressure cases are considered. Example calculations demonstrate that the method helps to avoid underestimation of well injectivity in non-isothermal problems caused by grid-block averaging of fluid and reservoir properties in conventional inflow performance relations.

Inflow Performance Analysis of a Horizontal Well Coupling Stress Sensitivity and Reservoir Pressure Change in a Fractured-Porous Reservoir

Stress sensitivity has always been a research hotspot in fractured-porous reservoirs and shows huge impacts on well productivity during the depletion development. Due to the continuous reservoir pressure change, accurate evaluation of stress sensitivity and its influence on well productivity is of great significance to optimize well working system. Taking horizontal well trajectory as the research object, the principal focus of this work is on the analysis of inflow performance for a horizontal well coupling stress sensitivity and reservoir pressure change in a fractured-porous reservoir. Firstly, a relationship between permeability damage rate and stress sensitivity coefficient was established to quantitatively evaluate the influence of reservoir pressure and stress sensitivity on reservoir permeability. Secondly, considering stress sensitivity and reservoir pressure drop, a set of practical productivity equations were derived for a horizontal well in a fractured-porous reservoir by adopting the equivalent seepage resistance method. Finally, the influence of relevant important factors on the inflow performance of horizontal wells was discussed in depth. Results show that a positive correlation exists between stress sensitivity coefficient and maximum permeability damage rate. At the same maximum permeability damage rate, high initial reservoir pressure corresponds to low stress sensitivity coefficient. In general, stress sensitivity coefficient mainly ranges from 0 to 0.2. Reservoir pressure change drastically affects the production dynamic characteristics of horizontal wells, and both the inflow performance curve and the production index curve decline and shrink as reservoir pressure decreases. Stress sensitivity is negatively correlated with horizontal well productivity, and the inflow performance/production index curve bends closer to bottom-hole pressure axis, and an inflection point can be observed with the aggravation of stress sensitivity. In addition, horizontal wellbore length and initial reservoir permeability also show significant effects on the inflow performance and are positively correlated with well productivity. For water cut, it has little effect on the well production when bottom-hole pressure drawdown is low, but its effect gets stronger as the drawdown becomes higher. Meaningfully, depending on these newly established productivity equations, a reasonable production system can be quantitatively optimized and achieved for the horizontal wells in fractured-porous reservoirs.

A Pseudo-Radial Pressure Model for Near-Wellbore Condensate Banking Prediction

A new pseudo-radial pressure model for inflow performance analysis and near-wellbore condensate banking deliverability is developed. Analysis of condensate banking and evolution in near wellbore region (i.e. zone 3) has been extensively studied. The new zone 4 region identified in this work will help in delineating the limit of retrograde condensation and the onset of revapourisation. Revapourisation after retrograde condensation is usually not accounted for in most field applications. However, in mature fields such as the Oredo field investigated in this study, revapourisation and near wellbore dynamics play an important role in optimising production from the field. The results of the newly formulated model captured the transient retrograde revapourisation near the wellbore for the well X studied in this work.

Predicting Stabilized Oil Well Inflow Performance Relationship on Unconventional Reservoir

Unconventional reservoirs are described as any reservoir that requires special recovery operations asides the conventional operating practices. However, low permeability affects the time it requires to attain stability. Presently, most of deliverability test is only carried out in a maximum 24-hour time. Limited test time makes it almost impossible to attain the reservoir stabilization time while carrying out the deliverability test. Meanwhile, to construct Inflow Performance Relationship (IPR) curve, the properties from stabilized time are required. This study aims to discuss how to predict the IPR curve by determining the stabilized flow coefficient value (C) on unconventional reservoir. Furthermore, the stabilized C was used to determine the Inflow Performance Relationship (IPR) for low porosity and permeability reservoir model, also known as Tight Oil Reservoir. The stabilized time and deliverability exponent value need to be determined before the stabilized C value. The stabilized time also know as pseudo-steady state time was evaluated from John Lee and Chaudry equation with validation from the reservoir model. The method proposed by Hashem and Kazemi, which employed the use of transient data in determining the flow coefficient value was also used. In addition, deliverability exponent (n) was determined using an equation proposed by Johnston and Lee. Furthermore, the backpressure equation from Rawlins and Schellhardt was used to construct the IPR curve.

EVALUATION OF ESP PERFORMANCE DN1800 TO INCREASE WELL PRODUCTIVITY

The use of the Electrical Submersible Pump (ESP) in the oil lifting method is very popular because it is easy to install, less required installation of tools in the field and a high efficiency. To achieve the Q target, ESP parameters such as the number of stages and RPM need to be analyzed to align with the IPR (Inflow Performance Flow) curve. The use of nodal analysis is used to determine the relationship between Pwf and head pump. Iteration needs to be done to determine the range of the number of stages so that it aligns with characteristics of well. It is found that the recommended range stage is 580-600 at a well depth of 7684 ft. Moreover, it is found that with 3600 RPM and 600 stages is able to reach the Q target. The relationship between the number of stages and RPM value with Pwf is inversely proportional.

A Novel Mathematical Model Considering Real Gas PVT Behavior to Estimate Inflow Performance Relationship of Gas Well Production

Inflow performance relationship (IPR) is one of the most important methods for the analysis of the dynamic characteristics of gas reservoir production. The objective of this study was to develop a model to improve the accuracy of the IPR for evaluating and predicting the production of gas reservoirs. In this paper, a novel mathematical model, taking into account the real gas PVT behavior, is developed to accurately estimate the inflow performance relationship. By introducing a pseudo-pressure function and a real gas properties database, this model eliminates the error caused by the linearization method and improves the calculation accuracy. The results show that more than 90% of the energy in the flow field is consumed by inertial forces, which leads to significant high-velocity non-Darcy effects in the gas reservoir. The reservoir permeability, original reservoir pressure, stress sensitivity coefficient, and skin factor have a great impact on the inflow performance relationship of gas reservoir production. This model predicts gas IPR curves with excellent accuracy and high efficiency. The high-precision gas well inflow performance relationship lays a solid foundation for dynamic production analysis, rational proration, and intelligent development of the gas field.