Authors: Mohammad Soroush (University of Alberta) | Seyed Abolhassan Hosseini (University of Alberta) | Morteza Roostaei (RGL Reservoir Management Inc) | Peyman Pourafshary (Nazarbayev University) | Mahdi Mahmoudi (RGL Reservoir Management Inc) | Ali Ghalambor (Oil Center Research International) | Vahidoddin Fattahpour (RGL Reservoir Management Inc)

Kazakhstan owns one of the largest global oil reserves (~3%). This paper aims at investigating the challenges and potentials for production from weakly-consolidated and unconsolidated oil sandstone reserves in Kazakhstan.

We used the published information in the literature, especially those including comparative studies between Kazakhstan and North America. Weakly consolidated and unconsolidated oil reserves, in Kazakhstan, were studied in terms of the depth, pay-zone thickness, viscosity, particle size distribution, clay content, porosity, permeability, gas cap, bottom water, mineralogy, solution gas, oil saturation, and homogeneity of the pay zone. The previous and current experiences in developing these reserves were outlined. The stress condition was also discussed. Furthermore, geological condition, including the existing structures, layers and formations were addressed for different reserves.

Weakly consolidated heavy oil reserves in shallow depths (less than 500 m) with oil viscosity around 500 cP and thin pay zones (less than 10 m) have been successfully produced using cold methods, however, thicker zones could be produced using thermal options. Sand management is the main challenge in cold operations, while sand control is the main challenge in thermal operations. Tectonic history is more critical in comparison to the similar cases in North America. The complicated tectonic history, necessitates the geomechanical models to strategize the sand control especially in cased and perforated completion. These models are usually avoided in North America due to the less problematic conditions. Further investigation has shown that Inflow Control Devices (ICDs) could be utilized to limit the water breakthrough, as water coning is a common problem, which initiates and intensifies the sanding.

This paper provides a review on challenges and potentials for sand control and sand management in heavy oil reserves of Kazakhstan, which could be used as a guideline for service companies and operators. This paper could be also used as an initial step for further investigations regarding the sand control and sand management in Kazakhstan.
 

Download paper

Authors: Edgar Alberto Mayorga Cespedes (Ecopetrol) | Morteza Roostaei (RGL Reservoir Management Inc.) | Alberto A. Uzcátegui (RGL Reservoir Management Inc.) | Mohammad Soroush (RGL Reservoir Management Inc., University of Alberta) | Hossein Izadi (University of Alberta) | Seyed Abolhassan Hosseini (RGL Reservoir Management Inc., University of Alberta) | Brad Schroeder (RGL Reservoir Management Inc.) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Dionis M. Gomez (Ecopetrol) | Edgar Mora (Ecopetrol) | Javier Alpire (Ecopetrol) | Joselvis Torres (Ecopetrol) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.)

Designing/Selecting the proper sand control mechanism for horizontal wells in unconsolidated heavy-oil reservoirs tend to be under-looked in some cases. Stand-alone completions pose some sand control challenges, which could jeopardize the oil production or even lead to critical problems. Massive sand production, screen/formation plugging, formation of velocity hot-spots and mechanical integrity failures are some of the well-known issues. This study attempts to optimize the sand control design for horizontal wells in a heavy-oil field in Colombia.

A careful selection of representative core data was made to study the variation of sand Particle Size Distribution (PSD) within the development area. Reservoir fluid properties were analyzed. Based on PSD variation and current design criteria in the industry, several seamed slotted-liner configurations were proposed as an alternative completion for testing. Later, a series of large-scale Sand Retention Tests (SRTs) were performed to assess the selected alternatives under typical field production conditions. Effects of aperture size and open to flow area (OFA) were investigated to evaluate flow and sand control performance.

This investigation started by a detailed study of the PSD, particle shape variation and composition of fines in the development area. The PSDs were then classified into four distinct minor and major sand facies, ranging from medium to very coarse sand with different fines content. Further investigations have shown that current design is only suitable for a limited number of PSDs, while the overall PSD classes indicate requirement of wider slot aperture sizes. The results of the SRTs indicated that the flow performance of the screen is mainly controlled by the slot aperture. Choosing the optimized aperture size avoids unacceptable sanding even for the multiphase flow scenarios with gas. Results also indicated that by increasing the aperture size and application of the seamed slots for the studied formation, plugging could be mitigated. Finally, a detailed Finite Element Analysis (FEA) was conducted to compare the mechanical integrity of the current slotted liner design and the optimized design obtained from the experimental testing.

A comprehensive sand control design workflow for cold primary heavy oil production in horizontal wells is presented in this work. The current study is one of the first that investigates and compares conventional straight slotted liners with seamed slotted liners at larger scale for a field. Moreover, this study helps to better understand the effect of design parameters of seamed slotted liners on sand control, flow performance and mechanical strength.

Download paper

Authors: Vahidoddin Fattahpour (RGL Reservoir Management Inc.) | Morteza Roostaei (RGL Reservoir Management Inc.) | Seyed Abolhassan Hosseini (University of Alberta) | Mohammad Soroush (University of Alberta) | Kelly Berner (RGL Reservoir Management Inc.) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Ahmed Al-hadhrami (Occidental Petroleum Oman) | Ali Ghalambor (Oil Center Research International)

Most of the test protocols developed to evaluate sand-screen designs were based on scaled-screen test coupons. There have been discussions regarding the reliability of such tests on scaled test coupons. This paper presents the results of tests on wire-wrapped screen (WWS) and slotted liner (SL) test coupons for typical onshore Canada McMurray formation sand.

A unique sand control evaluation apparatus has been designed and built to accommodate all common stand-alone screens that are 3.5 in. in diameter and 12 in. in height. This setup provides the capability to have a radial measurement of pressure across the sandpack and screen for three-phase flow. Certain challenges during testing such as establishing uniform radial flow and measuring the differential pressure are outlined. Produced sand is also measured during the test. The main outputs of the test are to assess the sand control performance and the mode of sanding in different flow directions, flow rates, and flow regimes.

It was possible to establish uniform radial flow in both high- and low-permeability sandpacks. However, the establishment of radial flow in sandpacks with very high permeability was challenging. The pressure measurement at different points in the radial direction around the screen indicated a uniform radial flow. Results of the tests on a representative particle size distribution (PSD) from the McMurray Formation on the WWS and SL test coupons with commonly used specifications in the industry (aperture sizes of 0.012, 0.014, and 0.016 in. for WWS and 0.012, 0.016, 0.018, and 0.020 in. for SL) have shown similar sanding and flow performances. We also included aperture sizes smaller and larger than the common practice. Similar to previous tests, narrower apertures are proven to be less resistant to plugging than wider slots for both WWS and SL. Accumulation of fines close to the screen causes significant pore plugging when conservative aperture sizes were used for both WWS and SL. In contrast, using the test coupon with a larger aperture size than the industry practice resulted in excessive sanding. The experiments under linear flow seem more conservative because their results show more produced sand and smaller retained permeability in comparison to the testing under radial flow.

This work discusses the significance, procedure, challenges, and early results of physical modeling of stand-alone screens in thermal operation. It also provides insight into the fluid flow, fines migration, clogging, and bridging in the vicinity of sand screens.
 

Download paper

Authors: Seyed Abolhassan Hosseini (RGL Reservoir Management Inc., University of Alberta) | Morteza Roostaei (RGL Reservoir Management Inc.) | Arian Velayati (University of Alberta) | Mohammad Soroush (RGL Reservoir Management Inc., University of Alberta) | Mohammad Mohammadtabar (RGL Reservoir Management Inc., University of Alberta) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.)

Erosion of standalone screens in thermal wells can lead to significant damage and reduction in production. The dominant failure mechanism is the development of localized high-velocity hot spots in the screen due to steam breakthrough or flashing of the steam across the screen. This study provides methods to assess the erosion potential of screen material devices to determine the allowable production conditions which avoid erosion.

In this study the effects of impact angle, flow rate, sand concentration, particle size, and fluid viscosity on erosion are systematically investigated through a multivariable study. Experimental impingement testing is performed on screens in different orientations. Erosion is accessed by collecting weight loss data of the screen. Empirical erosion models are calibrated to provide predictions of functional relationships between erosion rate and varied parameters. Computational Fluid Dynamic (CFD) simulations are performed prior to the experimental work to visualize particle flow paths through the screen and determine local flow and impact velocities and wear patterns.

The performance of five existing erosion models is assessed through experimental testing of sand control screens. In order to translate short-term, high-velocity laboratory test results into field erosion predictions, an empirical erosion model is then developed and employed to provide well flow guidelines and minimize erosion potential. This suggests that the use of erosion prediction models in situations in which due to lack of time/data tuning is not possible, may still provide a reasonable estimate for the rate of material loss of the screen. The model is used to obtain threshold superficial velocity curves for several conditions.

The main concern associated with existing erosion models is that they do not consider sand production, nor do they account for many other factors that affect erosion process. An erosion model, coupled with CFD simulation, has been developed, that account for factors such as geometry, size, material, fluid properties and rate, sand size, shape, and density in downhole flow conditions.
 

Download paper

Authors: Vahidoddin Fattahpour (RGL Reservoir Management Inc.) | Morteza Roostaei (RGL Reservoir Management Inc.) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Mohammad Soroush (RGL Reservoir Management Inc., University of Alberta) | Seyed Abolhassan Hosseini (RGL Reservoir Management Inc., University of Alberta) | Mark Anderson (Canadian Natural Resources Limited)

Primary Cold Heavy Oil Production with Sand (CHOPS) recovery factors are low (typically 8%) and most of the oil is left behind in the formation. Canadian Natural Resources Limited (Canadian Natural) is pursuing alternatives to primary recovery and secondary post CHOPS Enhanced Oil Recovery (EOR) to recover more of this stranded oil resource. Wire-wrapped screens were investigated, using a High-Pressure High Temperature Sand Retention Testing (HPHT-SRT) apparatus, for sand control and inflow performance in a CHOPS formation near Bonnyville, Alberta.

A new HPHT-SRT apparatus was designed/commissioned to better understand the role of oil viscosity on the capability of the standalone sand control screen. The facility allows to control the temperature of the fluid flowing across the sand pack and sand control coupon at different pressure drops. Each test is performed at constant pressure drops up to 300 psi. The temperatures up to 85 °C were tested. Coupons of wire-wrapped screen with three aperture sizes (0.008″, 0.010″, and 0.012″) were tested. Canadian Natural provided oil sand cores and crude oil from the target formation for this testing.

The results indicated a high dependency of the near screen flow performance on the temperature and oil viscosity. As the increase in temperature reduces the oil viscosity below 300 cP, the near screen pressure gradient falls 26% to 40% under constant pressure drop for different aperture sizes. As the screen aperture increases from 0.008″ to 0.012″, the flow rate increases up to 20% for the test stages at 85°C temperature and up to 162% for the test stages at 25°C, for the tested pressure drops. The results indicate that at higher viscosities, the aperture size is the dominant factor in screen flow performance where a slight increase in aperture increases the flow performance and reduces pressure drop. However, increasing the aperture size, up to 0.012″, led to an increase in the sanding over 0.20 lb per square feet of the screen (lb/sq.ft.), which exceeds the acceptable threshold of 0.12 to 0.15 lb/sq.ft. for typical SRTs. Based on the pressure drops and produced sand results, a 0.010″ aperture size was recommended for the target formation.

This paper outlines the results of the experiments with a HPHT-SRT, which is developed to better assess the function of sand control design for heavy oil assets. This phase of the work mainly focused on better understanding the role of the oil viscosity on sand control performance.

Download paper

Authors: Mohammad Soroush (RGL Reservoir Management Inc., University of Alberta) | Morteza Roostaei (RGL Reservoir Management Inc.) | Mohammad Mohammadtabar (RGL Reservoir Management Inc., University of Alberta) | Seyed Abolhassan Hosseini (RGL Reservoir Management Inc., University of Alberta) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Mohtada Sadrzadeh (University of Alberta) | Ali Ghalambor (Oil Center Research International) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.)

The historical challenges and high failure rate of using standalone screen in cased and perforated wellbores pushed several operators to consider cased hole gravel packing or frac-packing as the completion of the choice. Despite the reliability of these options, they are more expensive than standalone screen completion. Since several developments are not designed for cased hole gravel pack or frac-pack, purpose-driven sand control methods for cased and perforated wells are recommended.

This paper employs a combined physical lab testing and Computational Fluid Dynamics (CFD) for lab scale and field scale to assess the potential use of the standalone screen in completing the cased and perforated wells. The aim is to design a fit-to-purpose sand control method in cased and perforated wells and provide guidelines in perforation strategy and investigate screen and perforation characteristics. More specifically, the simultaneous effect of screen and perforation parameters, near wellbore conditions on pressure distribution and pressure drop are investigated in detail.

A common mistake in completion operation is to separately focus on the design of the screen based on the reservoir sand print and design of the perforation. If sand control deemed to be required, the perforation strategy and design must go hand in hand with sand control design. Several experiments and simulation models were designed to better understand the role of perforation density, the fill-up of annular gap between the casing and screen, perforation collapse and screen plugging on pressure drop. The experiments consisted of a series of step rate tests to investigate the role of fluid rate on pressure drop and sand production. There is a critical rate in which the sand filled annular gap will fluidize and also sanding would be different for different fluid density. Both test results and CFD simulation scenarios comparatively allow to establish the relation between wellbore pressure drop with screen and perforation parameters and determine the optimized design.

The results of this study highlight the workflow to optimize the standalone screen design for the application in cased and perforated completion. The proper design of standalone screen and perforation parameters allows maintaining cost-effective well productivity. Results of this work could be used for choosing the proper sand control and perforation strategy, rather than using gravel packing and frac-packing methods in cased and perforated completions.

Download paper

Authors: Morteza Roostaei, Alireza Nouri, Vahidoddin Fattahpour and Dave Chan

This paper focuses on the study of proppant transport mechanisms in fractures during frac-packing operation. A multi-module, numerical proppant, reservoir and geomechanics simulator has been developed, which improves the current numerical modeling techniques for proppant transport. The modules are linked together and tailored to capture the processes and mechanisms that are significant in frac-pack operations. The proposed approach takes advantage of a robust and sophisticated numerical smeared fracture simulator and incorporates an in-house proppant transport module to calculate propped fracture dimensions and concentration distribution. In the development of software capability, the propped fracture geometry and proppant concentration, which are the output of the proppant module, are imported to the hydraulic fracture simulator through mobility modification. Complex issues of proppant transport in fractures that are addressed in the literature and captured by the current model are: hindered settling velocity (terminal velocity of proppant in the injection fluid), the effect of fracture walls, proppant concentration and inertia on settling (due to extra drag forces applied on particles, compared to single-particle motion in Stokes regime in unbounded medium), possible propped fracture porosity and also mobility change due to the presence of proppant, and fracture closure or extension during proppant injection. A sensitivity analysis is conducted using realistic parameters to provide guidelines that allow more accurate predictions of the proppant concentration and fluid flow. The main objective of this study is to link a numerical hydraulic fracture model to a proppant transport model to study the fracturing response and proppant distribution and to investigate the effect of proppant injection on fracture propagation and fracture dimensions.

Download paper

Authors: Morteza Roostaei (RGL Reservoir Management Inc.) | Edgar Alberto Mayorga Cespedes (Ecopetrol) | Alberto A. Uzcátegui (RGL Reservoir Management Inc.) | Mohammad Soroush (RGL Reservoir Management Inc. and University of Alberta) | Seyed Abolhassan Hosseini (RGL Reservoir Management Inc. and University of Alberta) | Hossein Izadi (University of Alberta) | Brad Schroeder (RGL Reservoir Management Inc.) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Dionis M. Gomez (Ecopetrol) | Edgar Mora (Ecopetrol) | Javier Alpire (Ecopetrol) | Joselvis Torres (Ecopetrol) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.)

Designing and selecting the proper sand control mechanism for horizontal wells in unconsolidated heavy-oil reservoirs tend to be underlooked in some cases. Standalone completions pose some sand control challenges, which could jeopardize the oil production or even lead to critical problems. Massive sand production, screen/formation plugging, hot spots, and mechanical integrity failures are some of the well-known issues. This study attempts to optimize the slotted liner design for horizontal wells in a heavy-oil field in Colombia.

A careful selection of representative core data was made to study the variation of sand particle-size distribution (PSD) within the development area. Reservoir fluid properties were analyzed. Based on PSD variation and current design criteria in the industry, several seamed slotted-liner configurations were proposed as an alternative completion for testing. Later, a series of large-scale sand retention tests (SRTs) were performed to assess the selected alternatives under typical field production conditions. The effects of aperture size and open-to-flow area were investigated to evaluate flow and sand control performance.

This investigation started with a detailed study of the PSD, particle shape variation, and composition of fines in the development area. The PSD then classified into four distinct minor and major sand facies, ranging from medium to very coarse sand with different fines content. Further investigations have shown that current design is only suitable for a limited number of the PSDs, while the overall PSD classes indicate the requirement for wider slot aperture sizes. The results of the SRTs indicated that the flow performance of the screen is mainly controlled by the slot aperture. Choosing the optimized aperture size avoids unacceptable sanding even for the multiphase flow scenarios with gas. Results also indicated that by increasing the aperture size and application of the seamed slots for the studied formation, plugging could be mitigated.

A comprehensive sand control design workflow for cold primary heavy-oil production in horizontal wells is presented in this work. The current study is one of the first that investigates and compares conventional straight slotted liners with seamed slotted liners at a larger scale for this field. Moreover, this study helps to better understand the effect of design parameters of seamed slotted liners on sand control, flow performance, and plugging tendency.

Download paper