Shbair, Alaa (ADNOC Onshore) | Saputelli, Luigi (ADNOC) | Noordin, Firdaus (ADNOC Onshore) | Bogoslavets, Victor (Baker Hughes) | Alblooshi, Younes (ADNOC) | Soufi, Abdulrahman Al (ADNOC Onshore) | Hijjawi, Mohammed (ADNOC Onshore)
Water injection is by far the most popular method used in the secondary recovery phase of field development for oil displacement and pressure maintenance. Proactive reservoir management is important to validate the efficiency of the existing water injection schemes and to assess field development strategies to prolong oil production plateau and improve the recovery factor (RF). The main challenges arise in stretching the reservoir target whilst ensuring stabilized or reduced water cut (WCT), minimizing by-passed oil volumes and preventing wells from becoming inactive due to high WCT.
In order to mitigate premature water flooding issues, mainly two options are available: (1) artificial lift techniques to activate producers suffering early and rapid water breakthrough; and (2) optimized completion designs via preventive or corrective controls. Preventive (i.e. proactive) approach involves segmenting the wellbore using sliding sleeves, influx control equipment, limited-perforated liners, while corrective (i.e. reactive) methods attempt to divert/remedy unwanted water influx via water-shut off (WSO) interventions. None of these alternatives can be fully pursued as full-field development strategies without realizing the technical limitations as well as their economic benefits.
The objective of this paper is to determine the value of applying subsurface water control strategies in the context of enhancing reservoir management and develop a novel framework to assess potential remediation opportunities. The technical evaluation was supported by a robust Integrated Reservoir Management (IRM) process. This process identified the rig/rigless jobs opportunities to intervene inactive wells due to high WCT and rank all possible mitigation methods in an automated economic manner.
The findings have also proved the value of installing autonomous inflow control devices (AICDs) to control water production along horizontal sections. In effect, it controlled water slumping without jeopardizing oil production of wells awaiting gas lifting. A case scenario of combined Gas-lift and ICD deployments suggested a net incremental value of $66 million (or 106%). Field test results of the horizontal well’s production and WCT were found to be within 10% of the expected planned rates, and the oil gain is expected to further improve by 50% when gas-lift is commenced.
Methods currently used to evaluate laboratory performance of asphaltenes inhibitors are non-optimal because the conditions used are so far from those prevailing in the field, leading to incorrect assessment of dose rates or even selection of chemicals that may not be beneficial at all. We present a dynamic flow test method for asphaltenes risk assessment and inhibitor qualification that uses field-representative temperature, pressure and fluid dynamics to enable successful correlation with field behaviour.
This paper discusses the most commonly used laboratory test methods for asphaltenes testing and proposes a new dynamic flow method that offers a significant improvement over other widely-used techniques. Reconditioned dead crude oil is co-injected with
We present a case study describing the use of the dynamic flow test equipment to assess asphaltenes deposition risk and to qualify asphaltenes inhibitors for field application. We demonstrate that the method is able to rank chemicals for performance at inhibiting deposition under flowing conditions and at more field-representative temperature and pressure, with much lower percentages of
We discuss the effect of critical parameters affecting the extent of asphaltenes deposition. Fluid dynamics are recognised to play a key role in asphaltenes deposition in the field, not least, because at higher wall velocities the erosive force acting on field deposits is high enough to limit further growth and steady state can be reached. Flowing tests were conducted under a number of fluid-dynamic regimes in which asphaltenic crude oil was destabilised by addition of
This paper presents the development of a new laboratory test method utilising dead crude both for asphaltenes risk assessment and inhibitor qualification that offers significantly improved correlation with field behaviour over conventional dispersancy testing, yet remains much more cost effective than labour-intensive autoclave testing utilising live fluids. When considering asphaltenes risk analysis the approach also allows for deposition
Siddiqui, Muhammad Arsalan (NED University of Engineering & Technology) | Tariq, Syed Mohammad (NED University of Engineering & Technology) | Haneef, Javed (NED University of Engineering & Technology) | Ali, Syed Imran (NED University of Engineering & Technology) | Manzoor, Abdul Ahad (NED University of Engineering & Technology)
Asphaltene deposition can cause production reduction in oil fields and can create problems in surface/subsurface equipment. The three main factors which affect asphaltene stability in a crude oil are the changes in pressure, temperature and composition. Composition changes occur as the pressure depletes with time and fluid becomes heavier or with gas or chemical injection in reservoir. Any of these changes can destabilizes the asphaltene in crude oil and can cause different operational difficulties, loss in production and increases safety concerns. The objective of this study is to develop a workflow for modeling asphaltene precipitation during pressure depletion and its application to develop mitigation strategy via asphaltene stability maps for a gas condensate field in South Potwar basin, Pakistan
Reservoir management best practices originate from efficient well operations. The fluid flow profile from individual wells can change over time, sometimes unpredictably; as the reservoirs become depleted, changes in hydrocarbon properties occur, and water cut begins to increase. During primary, secondary, and tertiary recovery from conventional and unconventional wells, production surveillance is pivotal for optimum reservoir management. Determining the downhole production flow profile from multiple zones helps to manage drawdown pressure, regulate surface choke settings, and mitigate excessive water production.
This paper presents a rigorous mechanistic analysis of the heat transfer and fluid flow around the wellbore to aid in determining a generalized wellbore flow profile. The approach enables the calculation of multiphase rates independently of downhole spinner data and is based almost solely on temperature measurements. Because temperature measurements are reliable and more commonly available, the method provides a robust technique to determine flow contributions across a broad spectrum of surveillance applications. The technique is shown to work with other logs, such as capacitance, fluid density, and gas holdup tool, to relay more refined information about fluid phases during production.
The methodology presents an application of transient temperature modeling for computing flow rates from temperature data obtained during a wireline run. The approach includes an analytical wellbore fluid transient-temperature model. Temperature calculations depend on mass flow rate and flow duration; therefore, an inversion technique is applied to match the measured temperature and calculated temperature for a given time duration to estimate flow rate. The model is observed to depend on determining an accurate geothermal gradient, particularly in cases of early time flow. The various heat transfer resistances in the system are calculated based on the completion mechanics. The method also accounts for the effect of friction and pressure drop in the wellbore on fluid temperature. The case study included demonstrates the utility and value of the transient model. The transient nature of the model also facilitates multiple applications. Real-time flow rate monitoring, zonal contributions, flow behind casing, quantitative determination of leaks, and completion integrity are all potential applications of the proposed method.
The tool and methodology can be used with production logging spinners to calibrate the model and provide a permanent downhole monitoring tool to help avoid expensive logging reruns. The study provides a foundation for various applications arising from conventional production logging measurements and could be particularly useful in cases, such as offshore fields, where more evolved unconventional techniques can be difficult and expensive to apply.
Reverse circulation cement placement is the technique when cement slurries are pumped down the annulus and up the casing, as opposed to conventional primary cementing where fluids are pumped down the casing. Reverse circulation can reduce bottom hole pressures compared to conventional cementing, making it particularly attractive for cementing zones where margins to the fracture pressure are small. Since the fluids are not mechanically separated in the annulus, density and viscosity hierarchies need to be carefully designed to minimize mixing and slurry contamination. We investigate the effect of variations in density and viscosity on the displacement efficiency by means of computational fluid dynamics to improve the design of a successful reverse circulation cementing operation.
The simulations are performed using an open-source computational fluid dynamics software, enabling a parameter study of the effect of flow rate, inclination, standoff and fluid parameters such as density and viscosity on the displacement process. We compare the reversed circulation displacement efficiency and the hydraulic pressure in the annulus to corresponding conventional primary cementing operations.
The displacement flows involve complex non-Newtonian viscosities in eccentric annuli, and the flow is typically fully three-dimensional. The efficiency and quality of the fluid-fluid displacement is governed by the hierarchy of fluid properties between the displaced and displacing fluids for both conventional and reverse circulation cementing. Furthermore, it is shown how flow rate and geometric constraints such as inclination and standoff affect the efficiency.
Previous work has focused primarily on hydraulic pressure and downhole temperature calculation. We investigate the effect of fluid hierarchies on cement contamination during reverse circulation cementing. The combination of fluid hierarchies and flow rate need to be carefully designed to avoid cement contamination while maintaining low bottom hole pressures during reverse circulation.
In the last few years, large efforts have been made to develop advanced and smart technologies that can predict and prevent asphaltene precipitation. In the history of asphaltene deposition science, two schools of thought have emerged to predict the phase behavior of asphaltene. One school uses colloidal science techniques, believing that asphaltene exists in oil at a colloidal state. The other school adopts thermodynamic methods, believing that the asphaltene occurs in oil in a true liquid state.
The main drawdowns of asphaltene deposition in some reservoirs that are prone to asphaltene precipitation are the alteration of reservoir rock's wettability, and the plugging of the formation, flowlines and separation facilities. Different production strategies have been developed to eliminate or reduce the asphaltene precipitation. As asphaltene properties are dependent on its composition, as well as the reservoir temperature and pressure, thermodynamic and kinetic control strategies are utilized to control the pressure and temperature of the system or the conditions of solid formation. Common intervention techniques include stimulating the well periodically using a mixture of acid, xylene, and mutual solvent. Advancement in the asphaltene flocculation-inhibitor treatments allows it to be used in treating the asphaltene in the reservoir without damaging the formation. There are some limitations and environmental restrictions on the current conventional intervention techniques associated with using low flash-point chemicals. These limitations can be resolved by using environmentally friendly techniques, such as laser energy to disturb asphaltene particles.
This paper will discuss the asphaltene precipitation and deposition phenomena, preventive and detection techniques, and intervention methods and their limitations, providing a comprehensive overview on the current practice in asphaltene remediation and prevention.
This session will discuss open-hole sand control completion, gravel and screen design and field performance. This session will cover production enhancement of carbonate reservoirs using acid and non-acid treatments. Topics of papers in this session discuss evaluation, characterization, and remediation of formation damage in new, secondary recovery, and producing well environments. Rustom K. Mody, P.E., is the VP–Technical Excellence for Baker Hughes a GE Company. Mody has more than 39 years of experience in drilling, completion and production of which 30 years with Baker Hughes a GE company in various executive positions in technology.
Reverse-circulation primary cementing (RCPC), a technique in which cement is pumped down the annulus, has historically been used for specialized cases as an alternative to conventional-circulation primary cementing (CCPC), in which cement is pumped down the casing and circulates up the annulus. As the potential application of this placement technique has extended to deep water, traditional conventional hydraulic analysis is insufficient because of the complex flow path required by deepwater RCPC. The focus of this study is to provide a hydraulic analysis of this flow path, to determine causes of apparent equivalent-circulating-density (ECD) reductions, and to provide operators and well engineers with simple tools to estimate the changes in ECDs throughout the casing annulus.
Investigations of the specific hydraulic considerations of RCPC have been explored and evaluated since its first applications. This analysis builds upon previously published case studies and evaluations of hydraulics for traditional RCPC in which fluids are directly injected into the annulus from surface. By use of a graphical analysis, the hydraulics of deepwater RCPC, which requires an unconventional-flow path to divert flow from the work string into the annulus below the seafloor, is evaluated and compared with conventional placement.
The results of this study can be used for an initial determination of whether RCPC will produce the desired results for a specific wellbore geometry. By developing expressions for the pressure in the casing annulus for both conventional and reverse circulation, an analytic equation for the critical depth can be derived, assuming a constant pressure drop per unit length in the casing annulus. This study also evaluates the cause of pressure differences between conventional and reverse placement and the relationship of frictional-pressure drops, hydrostatic effects, and the elimination of applied lift pressure.
If the ECD is reduced at the bottom of the hole and increased at the previous casing shoe, then there is a point between those two where the pressures in conventional and reverse circulation are equal. A critical depth analysis has previously been performed for traditional RCPC applications. For deepwater applications that take into account the unconventional-flow path, analysis in this study shows that well geometry and location of a weak zone in the formation affect which placement method results in the lowest ECDs in a targeted area. For deepwater RCPC to be effective, the weakest part of the formation should be below the determined critical depth of the well.
The Operator is developing a large onshore field in the Sultanate of Oman. Its full field development requires the construction of over 300 wells. Critical to the success of the project is the sustained reduction in drilling time per well. This paper outlines the strategy and performance improvements achieved through the 12-1/4" intermediate hole section in the pursuit of this goal.
The vertical 12-1/4″ section measures 2,650 m and consists primarily of hard carbonate sequences. There is a 350 m clastic base, of which the final 170m comprises very hard and abrasive sandstone. Multiple bit runs with sub-optimal ROP characterize drilling performance through this section. The ideal section TD is 20 m below the hard basal section.
Several drilling optimization initiatives were developed into a Continuous Improvement strategy to address performance opportunities. Work streams included, offset well analysis, KPI delineation, standardized drilling practices and procedures, BHA and drill bit design, parameter optimization, real-time monitoring, and rig site bit run supervision. The removal of unnecessary downhole tools and the transition from matrix to steel body PDC bits has also helped reduce costs. The Operator fostered collaborative working relationships with its bit vendors to develop applicable bit technology whilst encouraging competition to drive incremental performance.
A novel initiative specifically developed for this application has been real-time monitoring using an ROP console. The advisor console is located both in the office and on the drill floor. The key functionalities of the system include, engineered optimum parameter fairways, real-time performance benchmarking, look-ahead lithology/rock strength/stringer identification, drilling related risk alerts, and current/upcoming formation information. The system is tailored to each rig type, BHA and bit type, and ensures latest performance expectations and parameter advice can be disseminated across rig lines.
The strategy has meant the section can now be drilled twice as fast, using half the number of bits. Section Total Depth (TD) is also frequently reached to the optimized depth (in one bit run) enabling continued optimization for the start of the next section (8-3/8").