Optimizing Recovery for Waterflooding Under Dynamic Induced Fracturing Conditions

Summary It is well established within the industry that water injection mostly takes place under induced fracturing conditions. Particularly in low-mobility reservoirs, large fractures may be induced during the field life. This paper presents a new modeling strategy that combines fluid flow and fracture growth (fully coupled) within the framework of an existing "standard" reservoir simulator. We demonstrate the coupled simulator by applications to repeated five-spot pattern flood models, addressing various aspects that often play an important role in waterfloods: shortcut of injector and producer, fracture containment to the reservoir layer, and areal and vertical reservoir sweep. We also demonstrate how induced fracture dimensions (length, height) can be very sensitive to typical reservoir engineering parameters, such as fluid mobility, mobility ratio, 3D saturation distribution (in particular, shockfront position), 3D temperature distribution, positions of wells (producers, injectors), and geological details (e.g., layering and faulting). In particular, it is shown that lower overall (time-dependent) reservoir transmissibility will result in larger induced fractures. Finally, it is demonstrated how induced fractures can be taken into account to determine an optimum life-cycle injection rate strategy. The results presented in this paper are expected to also apply to (part of) enhanced-oil-recovery operations (e.g., polymer flooding).

Download Full-text

The Research and Evaluation of Finely Layered Water Injection Standard in Low-Permeability Reservoirs - A Case from Block A in one Low-Permeability Reservoir

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.1073-1076.2310 ◽

2014 ◽

Vol 1073-1076 ◽

pp. 2310-2315 ◽

Cited By ~ 1

Author(s):

Ming Xian Wang ◽

Wan Jing Luo ◽

Jie Ding

Keyword(s):

Oil Recovery ◽

Water Injection ◽

Injection Pressure ◽

Injection Rate ◽

Low Permeability ◽

Reservoir Permeability ◽

Engineering Parameters ◽

The Common ◽

Common Problems ◽

Low Permeability Reservoirs

Due to the common problems of waterflood in low-permeability reservoirs, the reasearch of finely layered water injection is carried out. This paper established the finely layered water injection standard in low-permeability reservoirs and analysed the sensitivity of engineering parameters as well as evaluated the effect of the finely layered water injection standard in Block A with the semi-quantitative to quantitative method. The results show that: according to the finely layered water injection standard, it can be divided into three types: layered water injection between the layers, layered water injection in inner layer, layered water injection between fracture segment and no-fracture segment. Under the guidance of the standard, it sloved the problem of uneven absorption profile in Block A in some degree and could improve the oil recovery by 3.5%. The sensitivity analysis shows that good performance of finely layered water injection in Block A requires the reservoir permeability ratio should be less than 10, the perforation thickness should not exceed 10 m, the amount of layered injection layers should be less than 3, the surface injection pressure should be below 14 MPa and the injection rate shuold be controlled at about 35 m3/d.

Download Full-text

A Numerical Method for Computing Recovery of Oil By Hot Water Injection in a Radial System

Society of Petroleum Engineers Journal ◽

10.2118/1069-pa ◽

1965 ◽

Vol 5 (02) ◽

pp. 131-140 ◽

Cited By ~ 2

Author(s):

K.P. Fournier

Keyword(s):

Thermal Expansion ◽

Oil Recovery ◽

Viscosity Ratio ◽

Water Injection ◽

Injection Rate ◽

Heat Losses ◽

Hot Water ◽

Radial System ◽

System Equation ◽

Finite Difference Equations

Abstract This report describes work on the problem of predicting oil recovery from a reservoir into which water is injected at a temperature higher than the reservoir temperature, taking into account effects of viscosity-ratio reduction, heat loss and thermal expansion. It includes the derivation of the equations involved, the finite difference equations used to solve the partial differential equation which models the system, and the results obtained using the IBM 1620 and 7090–1401 computers. Figures and tables show present results of this study of recovery as a function of reservoir thickness and injection rate. For a possible reservoir hot water flood in which 1,000 BWPD at 250F are injected, an additional 5 per cent recovery of oil in place in a swept 1,000-ft-radius reservoir is predicted after injection of one pore volume of water. INTRODUCTION The problem of predicting oil recovery from the injection of hot water has been discussed by several researchers.1–6,19 In no case has the problem of predicting heat losses been rigorously incorporated into the recovery and displacement calculation problem. Willman et al. describe an approximate method of such treatment.1 The calculation of heat losses in a reservoir and the corresponding temperature distribution while injecting a hot fluid has been attempted by several authors.7,8 In this report a method is presented to numerically predict the oil displacement by hot water in a radial system, taking into account the heat losses to adjacent strata, changes in viscosity ratio with temperature and the thermal-expansion effect for both oil and water. DERIVATION OF BASIC EQUATIONS We start with the familiar Buckley-Leverett9 equation for a radial system:*Equation 1 This can be written in the formEquation 2 This is sometimes referred to as the Lagrangian form of the displacement equation.

Download Full-text

A Nine-Point, Finite-Difference Reservoir Simulator for Realistic Prediction of Adverse Mobility Ratio Displacements

Society of Petroleum Engineers Journal ◽

10.2118/5734-pa ◽

1979 ◽

Vol 19 (04) ◽

pp. 253-262 ◽

Cited By ~ 50

Author(s):

J.L. Yanosik ◽

T.A. McCracken

Keyword(s):

Finite Difference ◽

Oil Recovery ◽

Mobility Ratio ◽

Spot Pattern ◽

Oil Saturation ◽

Grid Systems ◽

Displacement Front ◽

Grid Orientation ◽

Recovery Performance ◽

Reservoir Simulator

Abstract Reservoir simulators based on five-point difference techniques do not predict the correct recovery performance for unfavorable mobility-ratio, piston-type performance for unfavorable mobility-ratio, piston-type displacements. For a developed five-spot pattern, the predicted performance depends on the grid orientation predicted performance depends on the grid orientation (parallel or diagonal) used. This paper discusses the development and testing of a nine-point, finite-difference reservoir simulator. Developed five-spot-pattern flood predictions are presented for piston-type displacements predictions are presented for piston-type displacements with mobility ratios ranging from 0.5 to 50-0. We show that the predicted fronts are realistic and that very little or no difference exists between the results of parallel and diagonal grids. The maximum difference in the recovery curves is less than 1.5 %. The nine-point-difference method is extended to any grid network composed of rectangular elements. Results for two example problems - a linear flood and a direct line-drive flood - indicate the extension is correct. The techniques discussed here can be applied directly in the development of any reservoir simulator. We anticipate that the greatest utility will be in the development of simulators for the improved oil-recovery processes that involve unfavorable mobility ratio processes that involve unfavorable mobility ratio displacements. Examples are miscible flooding, micellar/ polymer flooding (water displacing polymer), and direct polymer flooding (water displacing polymer), and direct steam drive. Introduction Miscible displacement oil-recovery methods often are characterizedby a large viscosity ratio between the oil and its miscible fluid andby a very low immobile oil saturation behind the displacement front. These conditions represent an unfavorable mobility-ratio, piston-type displacement. They differ from a conventional piston-type displacement. They differ from a conventional gas drive, where a substantial mobile oil saturation remains behind the displacement front. Reservoir simulators based on five-point, finitedifference techniques do not predict the correct performance for unfavorable mobility-ratio, piston-type performance for unfavorable mobility-ratio, piston-type displacements. Results of an areal simulation for a developed five-spot flood depend on the grid orientation (diagonal or parallel, Fig. 1). Grid orientation significantly influences the predicted recovery performance and displacement front positions. performance and displacement front positions. A nine-point, finite-difference reservoir simulator is described. Predictions of piston-type displacements in a developed five-spot pattern are presented for mobility ratios ranging from 0.5 to 50. We show that the predicted fronts are realistic and that very little or no predicted fronts are realistic and that very little or no difference exists between the results of parallel and diagonal grid orientations. A formulation of the nine-point, finite-difference technique applicable to any rectangular grid network is presented. Results for two example two-dimensional presented. Results for two example two-dimensional problems, a linear flood, and a direct line-drive flood problems, a linear flood, and a direct line-drive flood indicate that the formulation is correct for nonsquare grid networks. Background Grid-orientation effects for five-point reservoir simulators were demonstrated by Todd et al. They studied two developed five-spot grid systems - a diagonal grid and a parallel grid. These grid systems are shown in Fig. 1. parallel grid. These grid systems are shown in Fig. 1. The diagonal grid represents a quarter of a five-spot pattern, with grid lines at 45 degrees to a line connecting the pattern, with grid lines at 45 degrees to a line connecting the injector and producer. The parallel grid represents one-half of a five-spot pattern, with grid lines either parallel or perpendicular to the lines connecting the parallel or perpendicular to the lines connecting the injector-producer pads. SPEJ P. 253

Download Full-text

Experimental Study on Enhanced Oil Recovery by Nitrogen-Water Alternative Injection in Reservoir with Natural Fractures

Geofluids ◽

10.1155/2021/6653399 ◽

2021 ◽

Vol 2021 ◽

pp. 1-9

Author(s):

Xiang Li ◽

Yuan Cheng ◽

Wulong Tao ◽

Shalake Sarulicaoketi ◽

Xuhui Ji ◽

...

Keyword(s):

Oil Recovery ◽

Gas Injection ◽

Water Injection ◽

Injection Pressure ◽

Injection Rate ◽

Water Flooding ◽

Orthogonal Experimental Design ◽

Fractured Reservoir ◽

Natural Fractures ◽

Nitrogen Injection

The production of a low permeability reservoir decreases rapidly by depletion development, and it needs to supplement formation energy to obtain stable production. Common energy supplement methods include water injection and gas injection. Nitrogen injection is an economic and effective development method for specific reservoir types. In order to study the feasibility and reasonable injection parameters of nitrogen injection development of fractured reservoir, this paper uses long cores to carry out displacement experiment. Firstly, the effects of water injection and nitrogen injection development of a fractured reservoir are compared through experiments to demonstrate the feasibility of nitrogen injection development of the fractured reservoir. Secondly, the effects of gas-water alternate displacement after water drive and gas-water alternate displacement after gas drive are compared through experiments to study the situation of water injection or gas injection development. Finally, the reasonable parameters of nitrogen gas-water alternate injection are optimized by orthogonal experimental design. Results show that nitrogen injection can effectively enhance oil production of the reservoir with natural fractures in early periods, but gas channeling easily occurs in continuous nitrogen flooding. After water flooding, gas-water alternate flooding can effectively reduce the injection pressure and improve the reservoir recovery, but the time of gas-water alternate injection cannot be too late. It is revealed that the factors influencing the nitrogen-water alternative effect are sorted from large to small as follows: cycle injected volume, nitrogen and water slug ratio, and injection rate. The optimal cycle injected volume is around 1 PV, the nitrogen and water slug ratio is between 1 and 2, and the injection rate is between 0.1 and 0.2 mL/min.

Download Full-text

Impact of injection rate on transient oil recovery under mixed-wet conditions: a microfluidic study

E3S Web of Conferences ◽

10.1051/e3sconf/20198904002 ◽

2019 ◽

Vol 89 ◽

pp. 04002 ◽

Cited By ~ 3

Author(s):

Magali Christensen ◽

Xanat Zacarias-Hernandez ◽

Yukie Tanino

Keyword(s):

Oil Recovery ◽

Strong Dependence ◽

Water Injection ◽

Microfluidic Channel ◽

Early Time ◽

Packed Bed ◽

Injection Rate ◽

End Effects ◽

Oil Saturation ◽

End Point

Lab-on-a-chip methods were used to visualize the pore-scale distribution of oil within a mixed-wet, quasi-monolayer of marble grains packed in a microfluidic channel as the oil was displaced by water. Water injection rates corresponding to microscopic capillary numbers between Ca = 5 × 10-8 and 2 × 10-4 (Darcy velocities between 0.3 and 1100 ft/d) were considered. As expected, early-time water invasion transitions from stable displacement to capillary fingering with decreasing Ca, with capillary fingering observed at Ca ≤ 10-5. End-point oil saturation decreases with Ca over the entire range of Ca considered, consistent with the canonical capillary desaturation curve. In contrast, Sor derived from approximate numerical simulations using reasonable Pc(Sw) do not display a strong dependence on Ca. These results suggest that the Ca dependence of end-point oil saturation is largely due to capillary end effects which, under conditions considered presently, affect the entire length of the packed bed.

Download Full-text

The Perspective of Novel Chemical Tracer Technology in Reservoir Surveillance and Hydrodynamic Modelling for More Efficient Hydrocarbon Recovery

10.2118/205678-ms ◽

2021 ◽

Author(s):

Nadir Husein ◽

Evgeny Aleksandrovich Malyavko ◽

Ruslan Rashidovich Gazizov ◽

Anton Vitalyevich Buyanov ◽

Aleksey Aleksandrovich Romanov ◽

...

Keyword(s):

Oil Recovery ◽

Continuous Production ◽

Economic Effect ◽

Water Injection ◽

Injection Rate ◽

Reservoir Pressure ◽

Entire Area ◽

Field Development ◽

Oil Companies ◽

Maintenance System

Abstract Today, efficient field development cannot be managed without proper surveillance providing oil companies with important geological and engineering information for prompt decision-making. Once continuous production is achieved, it is necessary to maintain a consistently high level of oil recovery. As a rule, a reservoir pressure maintenance system is extensively implemented for this purpose over the entire area because of decreasing reservoir pressure. At the same time, it is important to adjust the water injection to timely prevent water cut increasing in production wells, while maintaining efficient reservoir pressure compensation across the field. That is why it is necessary to have a relevant inter-well hydrodynamic model as well as to quantify the water injection rate. There are many ways to analyse the efficiency of the reservoir pressure maintenance system, but not all of them yield a positive, and most importantly, a reliable result. It is crucial that extensive zonal production surveillance efforts generate a significant economic effect and the information obtained helps boost oil production. Thus, the main objective of this paper is to identify a method and conduct an effective study to establish the degree of reservoir connectivity and quantify the inter-well parameters of a low permeability tested field.

Download Full-text

Simulation Study of Allied In-Situ Injection and Production for Enhancing Shale Oil Recovery and CO2 Emission Control

Energies ◽

10.3390/en12203961 ◽

2019 ◽

Vol 12 (20) ◽

pp. 3961

Author(s):

Haiyang Yu ◽

Songchao Qi ◽

Zhewei Chen ◽

Shiqing Cheng ◽

Qichao Xie ◽

...

Keyword(s):

Oil Recovery ◽

Co2 Emission ◽

Gas Injection ◽

Water Injection ◽

Oil Production ◽

Injection Rate ◽

Oil Reservoirs ◽

Shale Oil ◽

Shale Oil Reservoirs

The global greenhouse effect makes carbon dioxide (CO2) emission reduction an important task for the world, however, CO2 can be used as injected fluid to develop shale oil reservoirs. Conventional water injection and gas injection methods cannot achieve desired development results for shale oil reservoirs. Poor injection capacity exists in water injection development, while the time of gas breakthrough is early and gas channeling is serious for gas injection development. These problems will lead to insufficient formation energy supplement, rapid energy depletion, and low ultimate recovery. Gas injection huff and puff (huff-n-puff), as another improved method, is applied to develop shale oil reservoirs. However, the shortcomings of huff-n-puff are the low sweep efficiency and poor performance for the late development of oilfields. Therefore, this paper adopts firstly the method of Allied In-Situ Injection and Production (AIIP) combined with CO2 huff-n-puff to develop shale oil reservoirs. Based on the data of Shengli Oilfield, a dual-porosity and dual-permeability model in reservoir-scale is established. Compared with traditional CO2 huff-n-puff and depletion method, the cumulative oil production of AIIP combined with CO2 huff-n-puff increases by 13,077 and 17,450 m3 respectively, indicating that this method has a good application prospect. Sensitivity analyses are further conducted, including injection volume, injection rate, soaking time, fracture half-length, and fracture spacing. The results indicate that injection volume, not injection rate, is the important factor affecting the performance. With the increment of fracture half-length and the decrement of fracture spacing, the cumulative oil production of the single well increases, but the incremental rate slows down gradually. With the increment of soaking time, cumulative oil production increases first and then decreases. These parameters have a relatively suitable value, which makes the performance better. This new method can not only enhance shale oil recovery, but also can be used for CO2 emission control.

Download Full-text

RESERVOIR SIMULATION IN THE MEREENIE FIELD

The APPEA Journal ◽

10.1071/aj85037 ◽

1986 ◽

Vol 26 (1) ◽

pp. 428

Author(s):

B.F. Towler

Keyword(s):

Oil Recovery ◽

Reservoir Simulation ◽

Water Injection ◽

Gas Oil ◽

The North ◽

Stock Tank ◽

Bottom Hole Flowing Pressure ◽

Steep Decline ◽

Oil Rim ◽

Reservoir Simulator

The Mereenie Field in the Amadeus Basin was discovered in 1964 and contains an estimated 240 million barrels of oil and 480 billion (USA) cubic feet of gas in three formations. The field commenced production at 1500 barrels of oil per day from seven wells in September 1984. The structure is large and elongated and the oil in the permeable sands appears as a rim round the structure. This paper describes a reservoir simulation study initiated to evaluate the recovery of oil from wells sited on the north and south flanks of the anticline where the steep dips cause the oil rim to become very narrow.Ten studies were made on a 21 × 15 cell pattern model using a three phase semi-implicit black oil reservoir simulator. The ten runs compared oil recovery and gas/oil ratio as a function of formation dip, bottom hole flowing pressure, gas injection and water injection. These showed that the flank wells could be expected to recover 300 000 stock tank barrels of oil from primary and secondary operations which represents about 25 per cent of the oil in place for wells sited on half mile spacings. However the wells will experience high gas/oil ratios and a steep decline in oil rate.

Download Full-text

A Field Pilot of Waterflooding Conformance Control in Tight Oil Reservoir with Biotechnology

10.2118/206358-ms ◽

2021 ◽

Author(s):

Songyuan Liu ◽

Xiaochun Jin ◽

Deji Liu ◽

Hao Xu ◽

Lidong Zhang ◽

...

Keyword(s):

Oil Recovery ◽

Water Injection ◽

Vertical Direction ◽

Cost Effective ◽

Injection Rate ◽

Recovery Factor ◽

Tight Oil ◽

Index Test ◽

Indigenous Bacteria ◽

Water Cut

Abstract Traditional Microbial Enhanced Oil Recovery (MEOR) technology assumes the oil recovery is increased by the biosurfactant generating by the subsurface bacteria. However, we identified that increased recovery factor is mainly contributed by stimulating the indigenous bacteria to plug the preferred waterflooding channels, which was proved at laboratory and some high-permeable oilfield, but never implemented in the waterflooding of tight oilfield. This paper presents a comprehensive study on Bio-diversion technique by stimulating indigenous bacteria covering lab research and filed operation lasting 18 months. The lab research comprised: (1) feasibility research using modified recipe and field sample on the stimulation of indigenous microorganisms; and (2) Evaluation of effectiveness of the stimulation based on lab results. A field pilot, consisting of 10 injectors, 10 producers, injecting and producing from multi-zones, reservoir temperature is about 160 F, permeabilities range from 30 md to over 100 md, daily water injection rate is about 2,000 BWPD, pre-treatment water cut is over 90%. It is observed that the water cut has decreased from 98% to 80% gradually (3-6 months after injection). Besides, the water injection index test indicates that the injection profile becomes more evenly after 9 months of microbial nutrient injection because the stimulated bacteria reduce the permeability of more permeable zones and reduce the permeability heterogeneity in the vertical direction. Sharing the field results with the industry may inspire the operators to consider one alternative environmentally friendly and cost-effective approach to increase the recovery factor of tight oil reservoirs. From the technical viewpoint, the field pilot proves that the major mechanisms of MEOR is sweeping the unswept oil by injecting the microbial nutrient to the reservoir to stimulate the indigenous bacteria to block the preferred waterflooding channels.

Download Full-text

Investigation of Significance of Critical Components in Optimization of WAG Injection Processes under Uncertainty

10.2118/spe-169940-ms ◽

2014 ◽

Author(s):

C.. Temizel ◽

S.. Purwar ◽

A.. Agarwal ◽

A.. Abdullayev ◽

K.. Urrutia ◽

...

Keyword(s):

Oil Recovery ◽

Large Fraction ◽

Water Injection ◽

Sweep Efficiency ◽

Improved Oil Recovery ◽

Injection Process ◽

Water Alternating Gas ◽

Gas Flooding ◽

Reservoir Simulator ◽

Wag Injection

Abstract Water alternating gas (WAG) injection has been widely used for the last 50 years throughout the world. The typical improved oil recovery (IOR) potential for WAG injection compared with water injection is 5 to 10%. It was originally intended to improve sweep efficiency during gas flooding, with intermittent slugs of water and gas designed to follow the same route through the reservoir. Mechanisms in WAG injection include microscopic effects, particularly in cases where three-phase flow and hysteresis are important for the IOR effect. Injection of gas usually aids an ongoing waterflood, and finding technical and commercial methods to reduce gas costs would be useful. Water injection alone tends to sweep the lower parts of a reservoir, while gas injected alone sweeps more of the upper parts of a reservoir because of gravitational forces. Gas represents a large fraction of the total cost, making WAG injection an expensive method. Thus, optimizing WAG injection is not only crucial in terms of recovery but also economics, especially where gas is expensive and/or limited. In this study, the significance of key components in a WAG injection process on SPE's 5th Comparative Solution Project (CSP) is presented that models the WAG process through a pseudo-miscible formulation by means of coupling a full-physics reservoir simulator with commercial optimization and uncertainty software. The results are analyzed and presented in a comparative manner by means of tornado charts showing the significance of each decision and uncertainty variable.

Download Full-text