Porosity, water saturation, and net-to-gross evaluation can be challenging in thinly bedded sands. The use of standard induction resistivity for formation evaluation can lead to the overestimation of water saturation. This work explores the following options to improve formation evaluation in these conditions: the use of high resolution density and nuclear magnetic resonance (NMR) data to improve porosity vertical resolution; the use of high-resolution resistivity from an oil-based-mud microresistivity imaging tool in improving the saturation computation (Sw); and the comparison of imaging tool resistivity-based sand count and NMR-based thin-bed fraction.
Using high-resolution porosity inputs from density and NMR provided a porosity curve with a better vertical resolution to match the high resolution resistivity from the imaging tool. It also identified additional productive thin beds compared to the standard resolution outputs and allowed computation of a high-resolution irreducible water saturation.
The induction-based Sw is strongly affected by shoulder bed effect and overestimates Sw by approximately 10 to 15%. The high-resolution curve from the imaging tool was used as an input into the Sw computation, which was made possible by shallow oil-based mud (OBM) invasion. This approach gave good results in beds thicker than 6 in., where Sw from the imaging tool matches the irreducible water saturation computed from NMR, giving 20 to 30% Sw.
A thin-bed fraction curve was computed from the NMR data. It shows a good match with the image-based high resolution-sand count and the image features, demonstrating that NMR and the imaging tool are equally able to identify and quantify thin beds, even though they have different vertical resolutions. This study showed that the microresistivity imaging tool and NMR are essential tools to characterize thinly bedded reservoirs.
The Pliocene reservoirs of the Nile Delta (Egypt) contain significant amounts of thin-bed laminations. In these turbiditic systems, it is well recognized that the presence of shale layers between hydrocarbon-bearing sand layers can lead to a decrease of apparent resistivity that will in turn result in an overestimation of the water saturation of the sand layers. This phenomenon is called low-resistivity pay (see Olesen 2002 and Clavaud et al. 2005 for examples and explanations of this phenomenon in the Nile Delta).
In the case study presented here, it was observed that the conventional water saturation (using induction resistivity and standard-resolution porosity logs) overestimated water saturation compared to the nuclear magnetic resonance (NMR) irreducible water saturation, despite the fact that no water was produced. This discrepancy highlighted a case of low-resistivity pay.
Several approaches are available to solve this problem and obtain a true representation of the water saturation in the sand layers. The first approach uses triaxial induction resistivity measurements to determine formation resistivity in the directions parallel ("horizontal?? resistivity termed Rh) and perpendicular ("vertical?? resistivity termed Rv) to the layering. The combination of Rv and Rh, together with the fraction of sand and an estimate of shale anisotropy parameters allows the computation of the water saturation in the sand layers (Clavaud et al. 2005). This technique is not used here, although it will be considered for future applications.
The second approach uses high-resolution resistivity data from a microresistivity imaging tool, specifically designed for oil-based mud (OBM) environments, combined with high-resolution porosity data to resolve water saturation in each individual bed. This approach has been adopted in this paper. The results provided a good match with the NMR irreducible water saturation.
This paper discusses the exploration potential of extensional structures in pre-Messinian formations in central Nile Delta Basin. The study aims at detailed description of extensional events and discusses the exploration potential of specific structures generated.
Particularly, structural elements of pre-Messianian sequences were partially deciphered in the past, due to quality of seismic data and spare and scarce wells drilled to these levels. The newly acquired high quality 3D seismic data has been able to improve the image underneath the pre-Messinian. This has resulted in the understanding of tectonic activity, faults system and structures developed.
Two extensional events characterize the tectonic activity in the Late Oligocene through Messinian.
First extensional event is related to onset of Gulf of Suez rifting and generate a W-E system of basement involved faults and reactivation of syn-rift hinge zone. Related structures of this extensional phase are represented by growth anticline, drag folds and rotated blocks.
The second extensional tectonic event occurred in Tortonian. The structural style corresponds to tilted and eroded fault blocks dipping to north and being aligned in a north-south direction corresponding to the main normal faults trend.
This study of the pre-Messinian extensional structures described here will have a direct impact on the exploration activities design, several important prospects being delineating among the structures developed during both extensional phases.
The carbon dioxide (CO2) sequestration and storage in aquifers and depleted oil and gas reservoirs is eminently a feasible solution to provide substantial cut in overall emission into the atmosphere. The current need is to understand the factors affecting the CO2 sequestration potential and capacity of particular formation/reservoir.
The purpose of this study is to investigate the CO2 storage in carbonate reservoir rocks under different conditions of pressure and temperature. Two groups of experiments were undertaken including; (1) investigating the CO2 solubility under different brine salinities, and different pressure and temperature conditions, and (2) studying the effect of CO2 storage time interval on porosity and permeability of carbonate reservoir rocks. Core storage experiments were undertaken using actual and similar core samples saturated with 25,000 ppm NaCl brine. The potential of the CO2 storage capacity and variations in porosity and permeability are evaluated and quantified.
The results showed that solubility of carbon dioxide decreases with increase in brine salinity and/or temperature. The increase of pressure causes a decrease in carbon dioxide solubility. In addition, the effect of temperature on carbon dioxide solubility diminishes above 120 oF and 4,000 psi pressure. The results also indicated that storage of carbon dioxide increases the petrophysical properties of porosity and permeability of carbonate rocks when the storage period is more than 150 days. On the other side, the CO2 storage for short time < 7 days causes reduction in porosity and permeability of carbonate reservoir rock.
The application of the attained results of this study is expected to have good impact on design storage process of carbon dioxide, validation of developed mathematical models, and improving our understanding of the process.
Determining of reservoir surface subsidence is a crucial problem especially for soft and unconsolidated formations. For long time production with water injection and/or water influx, the pore pressure decreases with increasing in effective stress leading to reservoir compaction and vertical surface subsidence. In this paper, a Tank Capacitance-Resistive Model (TCRM) has been done to estimate the history of vertical subsidence in the upper sandstone member/main pay of South Rumaila oil field in Iraq. It is a mature oil field with around 58 years of production with 40 producing wells and it has also 20 injection wells located only at the east flank. The average surface area for this reservoir is 142 km2. The reservoir is modeled considering an infinite acting aquifer at the east and west flanks. A commercial reservoir simulator has been adopted parallel with the Tank Capacitance-Resistive Model to estimate the subsidence in very active aquifer. The Carter-Tracy water influx model has been adopted to calculate the water influx rate. The TCRM depends on the concept of continuity equation that considers the difference between the water injection and oil production as reservoir input and output, respectively. So, the simulator calculates the total water injection rate and water influx to be treated as water injection in the continuity equation.
The results demonstrated that reservoir formation has plastic deformation because it has recurrence subsidence in the reservoir thickness. The current subsidence for this reservoir in the current time after 58 years of predict is 1.5 ft at the crest of the reservoir and it is approximately close to the local subsidence at each grid in the reservoir crest.
The extraction of oil and gas for long time causes a huge decline in reservoir pressure. This decline may result in a reduction in pore pressure especially if there is not enough acting aquifer to support the formation pore pressure. This will lead eventually to decrease in petrophysical properties such as permeability, and porosity. Therefore, decreasing in pore pressure with constant overburden leads to increasing of the vertical effective stress that results in reservoir compaction and thickness reduction and might lead to surface subsidence and then results in damage to surface facilities and wells, but also reactivates faults(1). This model has been used with fast reservoir simulator to estimate the reservoir subsidence for non-aquifer reservoir.
It can be taken place in unconsolidated and soft reservoirs, especially in those with large pay thickness and shallow depths. The surface subsidence had happened in specific parts of the Lost Hills oil field in California(2) and it was up to 10 ft. Also, it has been over nine meters in the Ekofisk field in the Wilmington field in California(3).
Kothiyal, M. D. (Cairn Energy India Ltd) | Parasher, A. (Cairn Energy India Ltd) | Qutob, A. H. (Weatherford Oil Tool ME Ltd) | Cooper, R. J. (Weatherford Oil Tool ME Ltd) | Forsyth, G. R. (Weatherford Oil Tool ME Ltd)
The subject well is an onshore oil producer located in Cairn Energy India's Rajasthan block. The well had stratified sand sections completed with 4-inch inflow control device (ICD) screens and isolated by swellable packer assemblies. The well was put into production at a rate of approximately 1,000 bopd; however, due to formation damage - notably paraffin and scale - the well could not sustain production and eventually ceased.
Our objective was to selectively stimulate 15 ICDs using coiled tubing. The well had a minimum restriction and a larger setting diameter which warranted the usage of coiled tubing deployed inflatable straddle packer system. This enabled passage through the restriction and setting in the larger outer diameter to selectively treat each zone by mechanically diverting the stimulation fluid.
The challenge was significant. Multiple zones required treatment in a single run by performing 15 multi-settings, maintaining seal integrity following each set, and returning the tool to its original outer diameter for retrieval. The well was deviated at 74 degree which challenged accessibility.
The assembly was run successfully and managed to selectively stimulate all required zones in one trip. Using this application, we confirmed that all treatment fluid was effectively sealed and treated by diverting the treatment fluid directly into the required zone, preventing more permeable sections absorbing most of the fluid, and ensuring the treatment chemicals were used in a cost effective manner. The single coiled tubing run avoided multiple runs to isolate sections using plugs. The well subsequently began to flow once lifted with nitrogen, positively indicating that the ICDs were effectively cleaned and the zones successfully treated.
This case demonstrates the innovative use of thru-tubing wellbore isolation techniques to effectively enhance production in wells with challenging configurations and operating parameters. This study further paves the way for similar interventions in wells with similar characteristics.
As discussed previously, the well had ceased production due to clogging of the ICDs with paraffin and scale; therefore the objective was to selectively stimulate each of the 15 non-performing ICDs in the well in a rigless operation. This would involve isolating each of the target ICDs and mechanically diverting the treatment fluid into the zone of interest, followed by moving onto the next zone and repeating the isolation and treatment procedure. The well was completed with the 4-in. (101mm) ICDs and swellable packer assemblies that had an inside diameter of 3.547-in (90mm). In order to access the target treatment depth, the stimulation assembly had to pass a minimum restriction of 2.562-in (65mm.) created by an F-nipple in the upper completion assembly.
Thermal oil recovery methods have been widely used not only in heavy oil reservoirs, but also in light oil reservoir with Waterflooding to improve oil recovery. The Steamflooding could be considered as an effective way to enhance the oil displacement especially in heterogeneous reservoirs The field, of 58-years of production history, is located in South of Iraq. It has 40 producing wells. There was an infinite active aquifer located at the east and west flanks. The strength of this aquifer from the west flank is much larger than its in the east flank because the reservoir permeability at the eastern boundaries is lower than as at the western one for all the layers; therefore, Twenty injection wells were drilled at the east flank to maintain the aquifer water approaching to the reservoir. The average surface area for this reservoir is 142 km2 and average formation depth of 10350 ft subsea with a maximum vertical oil column of 350 ft. Average porosity is 21%. The oil is 34°API with an average initial bubble point pressure of 2660 psia. Current reservoir pressure is approximately 4200 psia and the reservoir temperature is 210°F. In this study, a thermodynamic reservoir simulation has been adopted to investigate the competence of Steamflooding to improve oil recovery.
The objective of this work was to examine the feasibility of steam-injection processes, so a thermodynamical reservoir model (CMG-STARS) has been applied to demonstrate the effect of using steam injection as a heating agent to increase the sweep efficiency in this heterogeneous formation. The twenty injection wells have been converted to steam injection for twelve future prediction years. The process has demonstrated a considerable increase of the cumulative oil production. This result has been compared with the base scenario of water injection at the same injection rates of 10,000 STB/DAY per well. The water injection scenario has been done by CMG-IMEX. This incremental has been proved over most of the production wells that have distributed among the reservoir by showing a significant difference between the two cases.
Thermal oil recovery has been widely used in heavy oil reservoirs to enhance/improve oil recovery because of it's ability to positively change the reservoir and fluid properties for more efficient production. Once the steam is injected to the reservoir, it leads to the reduction of oil viscosity and enhance the oil displacement towards the production wells despite the heat loss to the surroundings below and above the formation. The remaining amounts of heat lead to oil mobilization by reduction of its viscosity (1). Since the viscosity is highly sensitive to the temperature, it is reduced a lot due to the temperature (2). Moreover, the steam flooding causes gradually decline in wettability, interfacial tension leading to the enhance oil displacement and sweep efficiency(16). The distribution of the remaining heat into the reservoir depends on the reservoir properties such as permeability and thickness in addition to the reservoir temperature, steam quality, thermal conductivity, and volumetric heat capacity especially in multilayered reservoirs (1). Also, the steam flooding efficiency depends on the oil saturation values. The efficiency of displacing and production performance increases as the oil saturation increases (2). The conduction phenomenon causes the oil production to the surface. However, the convection leads to oil displaced in the steam zone. The steam injection rate per the entire reservoir in heavy oil reservoirs depends on the reservoir thickness, permeability, and well spacing and it ranges from 100-120 t/d per injector (2).
Lautenschlager, Carlos Emmanuel Ribeiro (ATHENA / GTEP / PUC-Rio) | Righetto, Guilherme Lima (ATHENA / GTEP / PUC-Rio) | Inoue, Nelson (ATHENA / GTEP / PUC-Rio) | da Fontoura, Sergio Augusto Barreto (ATHENA / GTEP / PUC-Rio)
This paper deals with the implementation and validation of a new hydromechanical partial coupling methodology conducted between two commercial simulators of flow and stress. Such configuration is based on a coupling methodology developed by the Computational Geomechanics Group - ATHENA/GTEP - PUC-Rio, based on the consistent inclusion of terms in flow equation in order to approach the results of fully-coupled simulations. The IMEX® flow simulator was included in the workflow of the coupling code in order to widen the application scope of the methodology developed. To include the new option of flow simulator was required some implementation effort together with validation through simplified models. The algorithms developed to guide the programming were defined after detailed study of numerical and computational functioning of the flow software. The results obtained with the new simulator were compared with the pre-existing configuration (ECLIPSE flow simulator), considering one and two way partial coupling and fully coupled models. In the comparison scenarios set out to validate the implementation, it was evaluated changes of average pore pressure in the reservoir, compaction and subsidence, as well pore pressure variations. Comparisons with the results of pre-existing configuration and the full-coupling scheme demonstrated the success of the developed algorithm. The exchange of coupling parameters between simulators, in the new configuration, has been implemented effectively. Parametric studies of the variables also demonstrated the quality of the new configuration coupling. The rigorous choice of exchange parameters between flow and stress simulators is crucial for obtaining reliable results.
Reservoir production causes changes in the stresses and strains within the reservoir and surrounding rocks. Such changes give rise to the so-called geomechanical effects, namely the effects observed in the system due to the change in pore pressure, characteristic of the extraction and injection of fluids in porous media. In a recent paper, Herwanger & Koutsabeloulis (2011) illustrate some of these effects: subsidence of the surface or seafloor, slipping among stratigraphic planes, reactivation of faults, loss of seal integrity and compaction of the reservoir.
The numerical analyses that consider the geomechanical effects should consider the phenomena in a coupled way. According to Settari & Vikram (2008), coupled problems in geomechanics must take into account the interrelationship of hydraulic, thermal and mechanical variables in the solution of differential equations involved in each particular problem. In general, the mechanical problem is usually addressed by the finite element method and the flow problem by the finite difference method.
The conventional reservoir simulation solves the hydraulic problem involving flow of oil, gas and water through a porous medium. In these simulations, the variation of the pore volume is determined based only in the changes of pore pressure due to the activity of production and injection, and a predefined value of rock compressibility. According to Inoue & Fontoura (2009a), in this type of simulation the total stresses are held constant, and there is no compatibility of displacements between the boundaries of the reservoir and the surrounding rocks: overburden, sideburden and underburden. In fact, what is observed in a field development is the variation of fluid pressure that results in variation of the rock stress state. These variations, in turn, cause changes in porosity, which is reflected in the pressure field. This process of interaction between phenomena is what characterizes the nature of the coupled problems in reservoir engineering. Inoue & Fontoura (2009b) state that in the conventional reservoir simulation - where only the mass balance equations, equations of state and Darcy's law are considered - the change in porosity is dependent only on the variation of the pore pressure and rock compressibility.
Reservoir saturation monitoring, through cased wells, usually is the main key factor for proper reservoir management and recovery optimization in the cases of developed and mature oil fields. Thermal decay time tool (TDT) has been the main technique used for monitoring the inter wells water saturations in developed reservoir. One of the main problems that encountered while using TDT log is the reservoirs with low formation water salinity, this problem may also appear in reservoirs that are supported by water injection projects, in which the formation water is diluted by the injected water. This problem has been solved by combining TDT technique and cased hole formation resistivity tool (CHFR).
The ability to detect and evaluate bypassed hydrocarbon and monitor fluid movement in sandstone reservoir is a vital question to improve production and increase recovery. It is difficult to interpret the TDT data in reservoirs with low-salinity sandstone formation water. This problem cannot be solved because TDT measurements depend on the salt content in formation brine. Instead the cased hole formation resistivity tool (CHFR) is proposed to overcome the limitations associated with pulsed-neutron tools. This paper presents case studies of pay zones-saturation monitoring obtained from TDT and CHFR logs recorded in wells in mature sandstone reservoir which suffers from high water cut. The results are referenced to open-hole resistivity logs to monitor the vertical movement of reservoir fluids. It was found that water saturations calculated from CHFR logs are more accurate than TDT log in most cases. Water shut-off remedial action to manage water production from producing sections in the studied wells has been much more successful based on CHFR / TDT logs than the proposed remedial action based only on TDT data interpretation.
Shape Factor and drainage area in hydrocarbon reservoir are of the necessary and influencing factors on evaluation and optimization of drilling operation in oil fields. There are numerous methods to calculate the reservoir average pressure in conventional and sandstone reservoirs in that shape and drainage area of the reservoir are of important variables. On the other hand, these relations especially set for sandstone reservoirs and have limited usage in natural fracture reservoirs. This research demonstrates an approach to figure out shape factor and drainage area of wells in carbonated and naturally fractured reservoirs in all pressure and fluidity conditions. To assess this goal, results of well testing are carried out both for development of inflow performance curve and finding the drainage area. To make sure about the validity and preciseness of this method, it was investigated against the data from a well in a natural fracture field and the results were compared with those of other methods. Results dictated that the new approach can provide us with more precise and correct routes for the shape of the well in naturally fractured reservoirs. The suggested approach in this research needs production test data that has been optimized by well testing data for naturally fractured reservoirs. Additionally, this approach implemented to the draw down test and Tiab direct technique which is related to Warren and Root solution. What's more, this approach is reliable for all vertical wells in naturally fractured reservoirs (NFRs) with accessible production test data and well testing.
Facilities sand management is tasked with the goal of ensuring sustained hydrocarbon production when particulate solids (i.e. sand or proppant) are present in well fluids, while minimizing the impact of these produced solids on surface equipment. Particle size and total concentration of formation sand or proppant determines their net effect on production and the resulting operability of surface facilities. Conventional sand management control focuses on sand exclusion from the wellbore, either by production limits or completion design. Completions may adversely affect inflow due to skin buildup and both controls impede maximum hydrocarbon production. Alternatively, co-production of fluids and solids, with subsequent sand handling at surface facilities, is an inclusion paradigm that allows sustained hydrocarbon production. Produced solids are removed at the wellhead upstream of the choke using fit-for-purpose equipment. This methodology allows for increased or recovered hydrocarbon production, while their removal upstream of the choke protects facilities operations.
A description of the design, performance, operation, and effect on production rate is provided for sand inclusive production through application examples in the Caspian Sea, Indonesia, and South China Sea. Specific reference is given towards wellhead desanding, which forms the greater part of this approach, and has expanded from the first field installation in 1995 in the UK to every major oilfield producing region. Implementation of dedicated facilities sand management technology has resulted in increased hydrocarbon production from sand producing wells, extension of well life on marginal fields, and re-start of shut in wells.
The first industry-wide workshop to address solids handling from downhole generation to topsides disposal inclusive was held by the SPE Gulf Coast Section in April, 2002 in Houston, TX. This workshop was entitled Facilities Sand Management: Getting the Beach out of Production. This workshop hosted speakers to discuss sub-surface sand management, sand monitoring & measurement, flow-line erosion, facilities design, separation, solids cleaning, disposal, and slurry injection. Attendee response showed that the leading sand handling needs were subsea separation and disposal, subsurface-surface integration, and increasing the robustness of surface facilities to handle sand production.
Several production companies have started to integrate facilities sand management into their sand control portfolio. Equal merit is given to sand separation at the surface facilities and completion technologies to determine which approach provides sustained hydrocarbon production. Gravel pack and screen completions have a well-established installation and operating base and form the majority of conventional sand control. While controlling sand production in numerous wells, these techniques may still pass sand of <50-125 µm diameter under normal operating conditions, and this sand interferes with facilities operations. In the case of a completion failure, the sand amount and particle size may increase rapidly leading to production restrictions or damaged equipment.
The necessity for a technology that could protect surface facilities equipment (i.e., chokes, flow lines, pumps, separators, valves, etc.) in cases of completion failure, open hole completion, or rapid unplanned sand production led to the development of the multiphase desander for solids removal at the wellhead. Since the implementation of this technology 18 years ago, the wellhead desander has found repeated use as a service tool for the collection of solids during workover or well test operations and as a permanent unit operation to protect surface facilities equipment. Implementation of fit-for-purpose sand handling technology into surface facilities has enabled sustained operations in cases where previous actions were to shut in wells, limit hydrocarbon production, or suffer lengthy and costly maintenance outages.