Reservoir Simulation of Non Selective Placement of a Polymer Gel Treatment to Improve Water Injection Profiles and Sweep Efficiency in the Lagomar Field Western Venezuela

2004 ◽  
Author(s):  
Julio Herbas ◽  
Raul Moreno ◽  
Amaury Marin T. ◽  
Maria F. Romero ◽  
Dennis Coombe
Keyword(s):  
Reservoir Simulation ◽  
Water Injection ◽  
Polymer Gel ◽  
Sweep Efficiency ◽  
Gel Treatment ◽  
Selective Placement

Large-Volume Foam-Gel Treatments to Improve Conformance of the Rangely CO2 Flood

1999 ◽  
Vol 2 (01) ◽  
pp. 14-24 ◽  
Author(s):  
T.L. Hughes ◽  
F. Friedmann ◽  
D. Johnson ◽  
G.P. Hild ◽  
A. Wilson ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Large Volume ◽  
Fractured Reservoirs ◽  
Gas Injection ◽  
Cost Effective ◽  
Fracture Network ◽  
Polymer Gel ◽  
Sweep Efficiency ◽  
Gel Treatment ◽  
Incremental Oil Recovery

Summary Large-volume foam-gel treatments can provide a cost-effective method to achieve in-depth conformance improvement in fractured reservoirs. The applicability and cost effectiveness of the approach depends on the availability of a cheap source of gas, the efficiency with which the foam can be placed into the high permeability thief zone(s), and the effectiveness of the gelled foam barrier in diverting reservoir drive fluids to improve oil recovery. This paper reviews progress in the application of large-volume CO2-foam-gel treatments to improve conformance in the Rangely Weber Sand Unit (RWSU), Colorado. During the period November 1996-November 1997 three large-volume foam-gel treatments were successfully placed into the Rangely reservoir. The first 36?400 bbl treatment, implemented November 1996, increased the pattern oil rate from 260 barrels of oil per day (BOPD) in March 1997 to ±330 BOPD in August 1998; a conservative estimate of incremental oil recovery is ±40?000 bbl by the end of August 1998. The second 43?450 bbl treatment, implemented August-September 1997, increased the pattern oil rate from ±430 BOPD in March 1998 to ±470 BOPD in August 1998; post-treatment, the pattern oil rate data is described by a linear regression with slope, +56 BOPD but it is too early to make a firm estimate of incremental oil recovery. The third 44?700 bbl treatment, implemented October-November 1997, increased the pattern oil rate from ±330 BOPD in May 1998 to ±375 BOPD in July-August 1998; a linear regression of the post-treatment data gives a positive slope but again it is too early to estimate incremental oil recovery. Some general features in the pattern production response given by the three foam-gel treatments were observed. First, each of the treatments induces a stabilization in the pattern oil rate which, for treatments I and II, is accompanied by a decrease in the pattern gas rate. Second, the first positive oil rate response given by each of the treatments is observed 6-8 months after treatment execution and is dominated by the response at producer wells lying to the west/southwest and/or east/southeast of the treated injector well. For a given treatment volume, the cost of a foam-gel treatment at Rangely is 40%-50% below the average cost of polymer gel treatments. As the foam is injected at a higher rate, the total pump time required for a 40?000 bbl foam-gel treatment is similar to a 20?000 bbl polymer gel treatment. Early during pumping treatments II and III, we attempted to increase the CO2 content of the foam from 80 to 85 vol?%; this resulted in a wellhead pressure which was too close to the CO2 pressure limit necessitating a decrease in foam injection rate. Thus, in optimizing foam-gel treatment cost, there is a balance between maximizing the content of the inexpensive CO2 phase and minimizing total pump time. For Treatments II and III, the cost of the liquid phase formulation was reduced by decreasing the concentrations of surfactant and buffer. The implementation and evaluation of three large-volume foam-gel treatments at Rangely indicates that the foam-gel approach provides a cost-effective method to achieve in-depth conformance improvement in fractured reservoirs. Introduction A recent survey1 indicated that the proportion of U.S. EOR production recovered by gas injection has increased from 18% to 41% during the period 1986-1996. A major contribution to this trend has been the strong increase in the number of miscible carbon dioxide (CO2) projects which now account for > 70% of the total number of ongoing gas injection projects in the U.S. The Rangely CO2 flood began in 1986; currently, there are 372 active producer wells and 300 active injector wells, 259 of which are injecting CO2 using the water-alternating-gas (WAG) process. In the application of gas injection to heterogeneous reservoirs, oil recovery efficiency can be limited by poor conformance as an increasing proportion of the injected gas flows through higher permeability thief zones and/or fractures. The importance of conformance improvement has long been recognized at Rangely. The main problem being addressed is poor CO2 conformance due to preferential flow through the natural fracture network leading to premature gas breakthrough at the associated producers. This process increases operating costs and reduces oil recovery. The objective of the Rangely Conformance Improvement Team (CIT) is to improve conformance in order to reduce operating costs and increase the oil recovery to >1 billion bbl (>50% OOIP) compared to the current 815 million bbl (43% OOIP). A number of mechanical methods and chemical treatments have been employed to improve conformance at Rangely. While dual injection strings and selective injection equipment (SIE) have been used for improved injection profile control, chemical treatments using polymer gels2 and CO2 foam3 have been used to improve volumetric sweep efficiency and oil recovery. During the period 1994-1997, 49 injector wells were treated by placing a MARCIT™ gel4 into the fracture network.5 While these treatments have improved local sweep efficiency and oil recovery, economics limit the maximum treatment volume per injector well to 15?000-20?000 bbl. Certain regions of the Rangely reservoir require considerably larger treatment volumes to reduce the permeability of a larger volume of the fracture network and improve conformance in a larger volume of the well pattern.

Development of a Polymer Gel System for Improved Sweep Efficiency and Injection Profile Modification of IOR/EOR Treatments

2014 ◽  
Author(s):  
Freddy Crespo ◽  
B. R. Reddy ◽  
Larry Eoff ◽  
Christopher Lewis ◽  
Natalie Pascarella
Keyword(s):  
Polymer Gel ◽  
Sweep Efficiency ◽  
Profile Modification ◽  
Gel System

Carbonated Water Injection for Recovery of Oil and Wettability Analysis

2014 ◽  
Vol 695 ◽  
pp. 499-502 ◽  
Author(s):  
Mohamad Faizul Mat Ali ◽  
Radzuan Junin ◽  
Nor Hidayah Md Aziz ◽  
Adibah Salleh
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Promising Result ◽  
Water Injection ◽  
High Mobility ◽  
Wettability Alteration ◽  
Sweep Efficiency ◽  
Gas Flooding ◽  
Carbonated Water Injection ◽  
Carbonated Water

Malaysia oilfield especially in Malay basin has currently show sign of maturity phase which involving high water-cut and also pressure declining. In recent event, Malaysia through Petroliam Nasional Berhad (PETRONAS) will be first implemented an enhanced oil recovery (EOR) project at the Tapis oilfield and is scheduled to start operations in 2014. In this project, techniques utilizing water-alternating-gas (WAG) injection which is a type of gas flooding method in EOR are expected to improve oil recovery to the field. However, application of gas flooding in EOR process has a few flaws which including poor sweep efficiency due to high mobility ratio of oil and gas that promotes an early breakthrough. Therefore, a concept of carbonated water injection (CWI) in which utilizing CO2, has ability to dissolve in water prior to injection was applied. This study is carried out to assess the suitability of CWI to be implemented in improving oil recovery in simulated sandstone reservoir. A series of displacement test to investigate the range of recovery improvement at different CO2 concentrations was carried out with different recovery mode stages. Wettability alteration properties of CWI also become one of the focuses of the study. The outcome of this study has shown a promising result in recovered residual oil by alternating the wettability characteristic of porous media becomes more water-wet.

Field Implementation of In-Depth Conformance Gel Treatment Prior to Starting an ASP Flooding Pilot

2021 ◽  
Author(s):  
Mohammed T. Al-Murayri ◽  
Abrahim Hassan ◽  
Naser Alajmi ◽  
Jimmy Nesbit ◽  
Bastien Thery ◽  
...  
Keyword(s):  
Polymer Solution ◽  
Injection Pressure ◽  
High Viscosity ◽  
Production Well ◽  
Sweep Efficiency ◽  
Injection Wells ◽  
Appreciable Change ◽  
Well Pattern ◽  
Gel Treatment ◽  
Viscosity Polymer

Abstract Mature carbonate reservoirs under waterflood in Kuwait suffer from relatively low oil recovery due to poor volumetric sweep efficiency, both areal, vertically, and microscopically. An Alkaline-Surfactant-Polymer (ASP) pilot using a regular five-spot well pattern is in progress targeting the Sabriyah Mauddud (SAMA) reservoir in pursuit of reserves growth and production sustainability. SAMA suffers from reservoir heterogeneities mainly associated with permeability contrast which may be improved with a conformance treatment to de-risk pre-mature breakthrough of water and chemical EOR agents in preparation for subsequent ASP injection and to improve reservoir contact by the injected fluids. Each of the four injection wells in the SAMA ASP pilot was treated with a chemical conformance improvement formulation. A high viscosity polymer solution (HVPS) of 200 cP was injected prior to a gelant formulation consisting of P300 polymer and X1050 crosslinker. After a shut-in period, wells were then returned to water injection. Injection of high viscosity polymer solution (HVPS) at the four injection wells showed no increase in injection pressure and occurred higher than expected injection rates. Early breakthrough of polymer was observed at SA-0561 production well from three of the four injection wells. No appreciable change in oil cut was observed. HVPS did not improve volumetric sweep efficiency based on the injection and production data. Gel treatment to improve the volumetric conformance of the four injection wells resulted in all the injection wells showing increased of injection pressure from approximately 3000 psi to 3600 psi while injecting at a constant rate of approximately 2,000 bb/day/well. Injection profiles from each of the injection well ILTs showed increased injection into lower-capacity zones and decreased injection into high-capacity zones. Inter-well tracer testing showed delayed tracer breakthrough at the center SA-0561 production well from each of the four injection wells after gel placement. SA-0561 produced average daily produced temperature increased from approximately 40°C to over 50°C. SA-0561 oil cuts increased up to almost 12% from negligible oil sheen prior to gel treatments. Gel treatment improved volumetric sweep efficiency in the SAMA SAP pilot area.

Understanding the Plugging Performance of HPAM-Cr (III) Polymer Gel for CO2 Conformance Control

SPE Journal ◽  
2020 ◽  
Author(s):  
Xindi Sun ◽  
Baojun Bai ◽  
Ali Khayoon Alhuraishawy ◽  
Daoyi Zhu
Keyword(s):  
Pressure Gradient ◽  
Low Permeability ◽  
Far Field ◽  
Polymer Gel ◽  
Co2 Flooding ◽  
High Permeability ◽  
Conformance Control ◽  
Gel Treatment ◽  
Plugging Performance ◽  
Breakthrough Pressure

Summary With the demand for conformance control in carbon dioxide (CO2) flooding fields, hydrolyzed polyacrylamide-chromium [HPAM-Cr (III)] polymer gel has been applied in fields for CO2 conformance control. However, the field application results are mixed with success and failure. This paper is intended to understand the HPAM-Cr (III) polymer gel plugging performance in CO2 flooding reservoirs through laboratory experiments and numerical analysis. We conducted core flooding tests to understand how the cycles of CO2 and water affect the HPAM-Cr (III) polymer gel plugging efficiency to CO2 and water during a water-alternating-gas (WAG) process. Berea Sandstone cores with the permeability range of 107 to 1225 md were used to evaluate the plugging performance in terms of residual resistance factor and breakthrough pressure, which is the minimum pressure required for CO2 to enter the gel-treated cores.We compared the pressure gradient from the near-wellbore to far-field with the gel breakthrough pressure, from which we analyzed under which conditions the gel treatment could be more successful. Results show that HPAM-Cr (III) polymer gel has higher breakthrough pressure in the low-permeability cores. The polymer gel can reduce the permeability to water much more than that to CO2. The disproportionate permeability reduction performance was more prominent in low-permeability cores than in high-permeability cores. The gel resistance to both CO2 and brine significantly decreased in later cycles. In high-permeability cores, the gel resistance to CO2 became negligible only after two cycles of water and CO2 injection. Because of the significant reduction of pressure gradient from near-wellbore to far-field in a radial flow condition and the dependence of breakthrough pressure on permeability and polymer concentration, we examined hypothetical reservoirs with no fractures, in which impermeable barriers separated high- and low-permeability zones and in which the gel was only placed in the high-permeability zone. We considered two scenarios: CO2 breaking through the gel and no CO2 breakthrough. No breakthrough represents the best condition in which the gel has no direct contact and can be stable in reservoirs for long. In contrast, the breakthrough scenario will result in the gel’s significant degradation and dehydration resulting from CO2 flowing through the gel, which will cause the gel treatment to fail.

Reservoir Simulation of Variable Bubble-Point Problems

1976 ◽  
Vol 16 (01) ◽  
pp. 10-16 ◽  
Author(s):  
L.K. Thomas ◽  
W.B. Lumpkin ◽  
G.M. Reheis
Keyword(s):  
Reservoir Simulation ◽  
Water Injection ◽  
Material Balance ◽  
Point Problem ◽  
Time Step ◽  
Bubble Point ◽  
Free Gas ◽  
Flow Equations ◽  
Gas Saturation ◽  
Surrounding Areas

Abstract This paper presents the development of a general beta reservoir simulator that will model conventional (fixed bubble-point) problems as well as problems involving a variable bubble point, such as gas injection projects above the original bubble point and water injection projects resulting in a collapsing gas saturation, Provisions are included for allowing the pressure to cross the bubble point with the same relative ease as in a conventional simulator. Example problems are presented to demonstrate the utility of the model for gas and water injection problems. problems Introduction Many reservoir simulation problems involve treating a variable bubble point throughout the reservoir. For example, when gas is injected into an undersaturated reservoir, gas will go into solution, increasing the bubble point of the oil. As this oil moves away from the injector, the bubble point of surrounding areas also may increase point of surrounding areas also may increase because of mixing. During waterfloods of saturated reservoirs, the gas saturations in regions near the injectors frequently reduce to zero at pressures below the original bubble point. Thus, the bubble point will vary areally throughout the field. point will vary areally throughout the field.Recent publications have discussed certain aspects of the variable bubble-point problem. Most of these papers contain only a brief discussion of this problem. Ridings discusses the need for allowing saturation pressure to vary continuously throughout the reservoir as long as there is free gas associated with the oil. In the model presented by Cook et al., free gas saturation is monitored for saturated systems and the bubble point is set equal to the prevailing reservoir pressure when the gas saturation in a cell disappears. Bubble points for undersaturated cells are allowed to change because of the entrance of free gas and mixing. Spilletta et al. assume that a cell that is saturated or undersaturated at the beginning of a time step will remain so throughout the time step. They then solve their saturation equations for water and gas saturations. The bubble point of any undersaturated cell is adjusted to account for nonzero gas saturation, and the water saturation is modified to conserve oil. Steffensen and Sheffield devote their paper to the reservoir simulation of a collapsing gas saturation during waterflooding. In their model, blocks that have a free gas saturation at the beginning of a time step and have zero or negative gas saturations at the end of a time step are detected, and the bubble points for these cells are set equal to the estimated pressure where Sg reduced to zero. Gas saturation for these blocks is set equal to zero and S is set to 1 - S . The oil saturation in adjacent saturated grid blocks is then adjusted so that oil material balance is maintained. Mixing caused by flow between undersaturated blocks is neglected. This paper presents a comprehensive analysis of modeling variable bubble-point problems.* It treats the specific problems of simulating gas injection above the bubble point as well as waterflooding depleted reservoirs. It differs from previously reported work by accounting for the effect of bubble-point change on computed pressure change during a time step. Also, provisions are included that allow the pressure to cross the bubble point with the same relative ease as in a conventions! simulator In regard to waterflooding, mis paper differs from the work of Steffensen and Sheffield in mat it allows for bubble-point changes caused by mixing. DEVELOPMENT OF FLOW EQUATIONS To simulate the variable bubble-point problem, the expansion of the flow equations above the bubble point must include the effects of pressure and bubble point on fluid properties. Also, special consideration must be given to cells passing through the bubble point if both pressure and material-balance errors are to be eliminated. SPEJ P. 10

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