Assessment and Optimization of Waterflooding Performance in a Hydrocarbon Reservoir

2021 ◽  
Author(s):  
Miracle Imwonsa Osatemple ◽  
Adekunle Tirimisiyu Adeniyi ◽  
Abdulwaha Giwa
Keyword(s):  
Oil Recovery ◽  
Net Present Value ◽  
Research Work ◽  
Optimization Procedure ◽  
Base Case ◽  
Present Value ◽  
Recovery Method ◽  
Flow Rates ◽  
Hydrocarbon Reservoir ◽  
Secondary Recovery

Abstract In order to properly meet up with the ever-increasing demand for petroleum products worldwide, it has become increasingly necessary to produce oil and gas fields more economically and efficiently. Waterflooding is currently the most widely used secondary recovery method to improve oil recovery after primary depletion. A crucial component required to conduct an efficient waterflooding operation is an optimal production setting, most especially with respect to the amount of water involved. This research work has been carried out to develop a model that can be used to maximize oil recovery and minimize water production with the least amount and number of waterflood variables in order to minimize the secondary recovery investment cost. The gradient-based approach to optimize the production and net present value (NPV) from a waterflood reservoir using the flow rates or bottom hole pressures of the production wells as the controlling factors with the use of smart well technology was applied. In this approach, a variant of the optimal switching time technique was used in the optimization process to equalize the arrival times of the waterfront at multiple producers, thereby increasing the cumulative oil production. The optimization procedure involved maximizing the objective function (NPV) by adjusting a set of manipulated variables (flow rates). The optimal pressure profile of the waterflood scenario that gave the maximum NPV was obtained as the solution to the waterflood problem. The proposed optimization methodology was applied to a waterflood process carried out on a reservoir field developed by a five-spot recovery design in the Niger Delta area of Nigeria, which was used as a case study. The forward run was carried out with a commercial reservoir oil simulator. The results of the waterflood optimization revealed that an increase in the net present value of up to 9.7% and an increase in cumulative production of up to 30% from the base case could be achieved.

Undersaturated Hydrocarbon Reservoir Waterflooding: A simulation Approach to Performance Assessment

2021 ◽  
Author(s):  
Adekunle Tirimisiyu Adeniyi ◽  
Miracle Imwonsa Osatemple ◽  
Abdulwahab Giwa
Keyword(s):  
Oil Recovery ◽  
Net Present Value ◽  
Oil Production ◽  
Base Case ◽  
Present Value ◽  
Sweep Efficiency ◽  
Recovery Method ◽  
Solution Approach ◽  
Hydrocarbon Reservoir

Abstract There are a good numbers of brown hydrocarbon reservoirs, with a substantial amount of bypassed oil. These reservoirs are said to be brown, because a huge chunk of its recoverable oil have been produced. Since a significant number of prominent oil fields are matured and the number of new discoveries is declining, it is imperative to assess performances of waterflooding in such reservoirs; taking an undersaturated reservoir as a case study. It should be recalled that Waterflooding is widely accepted and used as a means of secondary oil recovery method, sometimes after depletion of primary energy sources. The effects of permeability distribution on flood performances is of concerns in this study. The presence of high permeability streaks could lead to an early water breakthrough at the producers, thus reducing the sweep efficiency in the field. A solution approach adopted in this study was reserve water injection. A reverse approach because, a producing well is converted to water injector while water injector well is converted to oil producing well. This optimization method was applied to a waterflood process carried out on a reservoir field developed by a two - spot recovery design in the Niger Delta area of Nigeria that is being used as a case study. Simulation runs were carried out with a commercial reservoir oil simulator. The result showed an increase in oil production with a significant reduction in water-cut. The Net Present Value, NPV, of the project was re-evaluated with present oil production. The results of the waterflood optimization revealed that an increase in the net present value of up to 20% and an increase in cumulative production of up to 27% from the base case was achieved. The cost of produced water treatment for re-injection and rated higher water pump had little impact on the overall project economy. Therefore, it can conclude that changes in well status in wells status in an heterogenous hydrocarbon reservoir will increase oil production.

Influence of oil field production life on optimal CO2 flooding strategies: Insight from the microscopic displacement efficiency

2021 ◽  
Author(s):  
Anna Chernova ◽  
Andrey Afanasyev ◽  
Anna Andreeva
Keyword(s):  
Oil Recovery ◽  
Optimal Strategy ◽  
Net Present Value ◽  
Gas Injection ◽  
Oil Field ◽  
Displacement Efficiency ◽  
Present Value ◽  
Recovery Method ◽  
Gas Flooding ◽  
Injection Rates

<p>We investigate the influence of the microscopic displacement processes on optimal gas flooding strategies. We couple a 1-D compositional reservoir model with an economic model of the flooding to assess profitability of the strategies. In general, we aim at the net present value maximisation, although the oil recovery and CO<sub>2 </sub>storage efficiencies are also estimated. Under certain assumptions, we reduce the number of parameters controlling selection of optimal strategy to just a few dimensionless quantities characterising both physical and economic processes. We show that the production life of oil fields should not be fixed in optimisation studies, especially at low oil prices. A significantly larger net present value can be achieved by varying the reservoir lifetime in addition to the injection rates and volumes and other well controls. Herewith, the optimal strategy can differ from that in the case of a presumed production time. We conclude that waterflooding is the optimal recovery method if the injection rate is low, whereas gas (WAG) flooding applied as a primary method and followed by waterflooding is most optimal for large injection rates. Gas flooding applied as the tertiary recovery method is most optimal for an intermediate range of the rates. In the latter case, gas injection should begin much earlier than water breaks through to producing wells. Finally, we investigate how oil price influences the range of parameters suitable for gas injection.</p><p>The authors acknowledge funding from the Russian Foundation for Basic Research under grant # 20-31-80009.</p>

scholarly journals Economical assessment of an investment related to the establishment of a new farrowing place and pig-rearing building

2019 ◽  
Vol 7 (1-2) ◽  
pp. 115-120
Author(s):  
Brigitta Zsótér ◽  
Ágnes Milojev
Keyword(s):  
Net Present Value ◽  
Research Work ◽  
The State ◽  
Point Of View ◽  
Bank Credit ◽  
Internal Rate Of Return ◽  
Present Value ◽  
Payback Time ◽  
Pig Farm ◽  
The Given

In our research work we aimed at carrying out an economical assessment of an investment and development of substantial volume. The examined project was completed at a pig-farm during which a new farrowing place and pig rearing building were built, as well as the renovation of the existing pig-farm. All of them were financed partly from the firm’s own source, partly from a non-repayable aid granted by the state, and finally from a credit granted by a commercial bank. The term of the credit is 10 years and the return of the investment expected by the investors is 8%, so we carried out our calculations according to these data. We examined the three possible ways of financing the investment from the economical point of view, as a result we proposed three hypotheses. Our hypotheses are: Hypothesis 1 (Case „A”): The investment will be financially recovered within the examined period of 10 years if it is financed from the firm’s own source, the state grant and the bank credit. Hypothesis 2 (Case „B”): The investment can be economically completed within the given period of time if the project meets the costs from the firm’s own source and the credit. Hypothesis 3 (Case „C”): The investment will be economically accomplished within the examined 10 years provided the firm finances the project from their own source and the state grant. In our calculations we used the net present value (NPV), the internal rate of return (IRR), the payback time (PB), the discounted payback time (DPB) and the profitability index (PI) as economy indicators. We carried out our calculations regarding 10 years to be able to compare the results since the term of the granted credit is 10 years, too.  

scholarly journals Compositional Modeling for Optimum Design of Water-Alternating CO2-LPG EOR under Complicated Wettability Conditions

2015 ◽  
Vol 2015 ◽  
pp. 1-9 ◽  
Author(s):  
Jinhyung Cho ◽  
Sung Soo Park ◽  
Moon Sik Jeong ◽  
Kun Sang Lee
Keyword(s):  
Interfacial Tension ◽  
Mole Fraction ◽  
Oil Recovery ◽  
Net Present Value ◽  
Numerical Study ◽  
Present Value ◽  
Compositional Simulation ◽  
Maximum Enhancement ◽  
Tension Reduction ◽  
Improved Oil Recovery

The addition of LPG to the CO2stream leads to minimum miscible pressure (MMP) reduction that causes more oil swelling and interfacial tension reduction compared to CO2EOR, resulting in improved oil recovery. Numerical study based on compositional simulation has been performed to examine the injectivity efficiency and transport behavior of water-alternating CO2-LPG EOR. Based on oil, CO2, and LPG prices, optimum LPG concentration and composition were designed for different wettability conditions. Results from this study indicate how injected LPG mole fraction and butane content in LPG affect lowering of interfacial tension. Interfacial tension reduction by supplement of LPG components leads to miscible condition causing more enhanced oil recovery. The maximum enhancement of oil recovery for oil-wet reservoir is 50% which is greater than 22% for water-wet reservoir. According to the result of net present value (NPV) analysis at designated oil, CO2, propane, and butane prices, the optimal injected LPG mole fraction and composition exist for maximum NPV. At the case of maximum NPV for oil-wet reservoir, the LPG fraction is about 25% in which compositions of propane and butane are 37% and 63%, respectively. For water-wet reservoir, the LPG fraction is 20% and compositions of propane and butane are 0% and 100%.

scholarly journals Optimization of ionic concentrations in engineered water injection in carbonate reservoir through ANN and FGA

2021 ◽  
Vol 76 ◽  
pp. 13
Author(s):  
Leonardo Fonseca Reginato ◽  
Lucas Gomes Pedroni ◽  
André Luiz Martins Compan ◽  
Rodrigo Skinner ◽  
Marcio Augusto Sampaio
Keyword(s):  
Oil Recovery ◽  
Net Present Value ◽  
Ionic Composition ◽  
Water Injection ◽  
Ionic Concentration ◽  
Carbonate Reservoir ◽  
Wettability Alteration ◽  
Injection System ◽  
Recovery Method ◽  
Natural Rock

Engineered Water Injection (EWI) has been increasingly tested and applied to enhance fluid displacement in reservoirs. The modification of ionic concentration provides interactions with the pore wall, which facilitates the oil mobility. This mechanism in carbonates alters the natural rock wettability being quite an attractive recovery method. Currently, numerical simulation with this injection method remains limited to simplified models based on experimental data. Therefore, this study uses Artificial Neural Networks (ANN) learnability to incorporate the analytical correlation between the ionic combination and the relative permeability (Kr), which depicts the wettability alteration. The ionic composition in the injection system of a Brazilian Pre-Salt benchmark is optimized to maximize the Net Present Value (NPV) of the field. The optimization results indicate the EWI to be the most profitable method for the cases tested. EWI also increased oil recovery by about 8.7% with the same injected amount and reduced the accumulated water production around 52%, compared to the common water injection.

scholarly journals 1,2—Propanediol Production from Glycerol Derived from Biodiesel’s Production: Technical and Economic Study

Energies ◽  
2021 ◽  
Vol 14 (16) ◽  
pp. 5081
Author(s):  
Juan B. Restrepo ◽  
Carlos D. Paternina-Arboleda ◽  
Antonio J. Bula
Keyword(s):  
Net Present Value ◽  
Reaction Scheme ◽  
Primary Objective ◽  
Raw Material ◽  
Biodiesel Production ◽  
Base Case ◽  
Economic Potential ◽  
Economic Study ◽  
Present Value ◽  
Input Variables

For every nine tons of produced biodiesel, there is another ton of glycerol as a byproduct. Therefore, glycerol prices dropped significantly worldwide in recent years; the more significant biodiesel production is, the more glycerol exists as a byproduct. glycerol prices also impact the biodiesel manufacturing business, as it could be sold according to its refinement grade. The primary objective of this work was to evaluate the economic potential of the production of 1,2-propanediol derived from the biodiesel produced in Colombia. A plant to produce 1,2-propanediol via catalytic hydrogenation of glycerol in a trickle-bed reactor was designed. The plant comprised a reaction scheme where non-converted excess hydrogen was recycled, and the heat generated in the reactor was recovered. The reactor effluent was sent to a separation train where 98% m/m purity 1,2-propanediol was attained. Capital and operational costs were estimated from the process simulation. The net present value (NPV) and the modified internal return rate (MIRR) of the plant were used to assess the viability of the process. Their sensitivity to key input variables was evaluated to find the viability limits of the project. The economic potential of the 1,2-propanediol was calculated in USD 1.2/kg; for the base case, the NPV and the MIRR were USD 54.805 million and 22.56%, respectively, showing that, for moderate variations in products and raw material prices, the process is economically viable.

Comparing the Benefits of Monitoring Versus Preemptive Replacement or Repair

2005 ◽  
Author(s):  
Joel Woodcock ◽  
Laurent P. Houssay
Keyword(s):  
Net Present Value ◽  
Financial Analysis ◽  
Monitoring Program ◽  
Frequency Component ◽  
Base Case ◽  
Maintenance Strategy ◽  
Present Value ◽  
Component Level ◽  
Effects Of Aging ◽  
The Impact

Today, utilities are faced with many equipment maintenance decisions, including whether to implement periodic replacement or to begin an inspection or condition monitoring program. Determination of an optimum maintenance strategy can be difficult because of the financial implications and the probabilistic aspect of the aging process. The Proactive Aging Management (PAM) Tool is a program that can be implemented by utilities to achieve maintenance optimization. PAM supports the decision making process by providing a financial analysis that assesses the impact of outage, inspection, repair and replacement costs together with the effects of aging on the failure rates of a particular component. PAM evaluates the present value of each maintenance strategy and optimizes maintenance parameters such as replacement date or inspection frequency. Component level models in PAM allow the system engineer to determine the best maintenance strategy for a given component. This paper describes an application of PAM that compares the options of inspection or proactive replacement to a base case run-to-failure strategy. The net present value (NPV) over the life of the plant is the metric by which strategies are compared. The NPV is generated for several combinations of inspection and proactive replacement costs. The results provide insight on the optimum choice based on the respective relative costs of each strategy.

The Triangle "U" Sussex Unit - A Case History Comparing Two Chemical Enhanced Waterflood Methods

1998 ◽  
Vol 1 (06) ◽  
pp. 545-550 ◽  
Author(s):  
J.E. Smith ◽  
Dan Larsen
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Rocky Mountain ◽  
Water Source ◽  
Cationic Polymer ◽  
Injection Wells ◽  
Recovery Method ◽  
Secondary Recovery ◽  
Permeable Rock

Summary The Triangle "U" unit is located in Campbell County, Wyoming, in the Powder River basin. The field produces mainly from the Sussex A sandstone, with completions and limited production from the Sussex B. The flood recovered 12.8% original oil in place (OOIP) on primary before the waterflood, which began in March 1981. The Sussex A is relatively tight, with an average permeability of 15 md and porosity of 13.5%. The rock contains swelling and migrating clays, and the initial injection water source was fresh, leading to concerns about long-term injectivity. To stabilize clays, two different processes were applied. Earlier injection wells were treated with a combination of potassium chloride (KCl) and cationic polymer. Later injection wells were treated with potassium hydroxide (KOH). A recent comparison of long-term performance of the two groups of injection wells shows that the wells treated with KOH injected 476,437 bbls/porosity-ft more water than the wells treated with cationic polymer, in 1.4 years less time. This is an 83% increase in cumulative water injection. After KOH, all injection wells were put on a low concentration of imbibition agent to maximize in-depth penetration of water into low permeable rock. Cumulative oil recovery through March 1997 is 36.4% OOIP, compared to the original waterflood projection of 26.6% OOIP. A total of 37.7% pore volume (PV) water has been injected, and the water/oil ratio (WOR) is currently 0.71, for a fairly efficient flood in this tight, dirty sandstone. Introduction The Triangle "U" unit produced 12.8% OOIP on primary before initiation of a waterflood. Several methods of secondary recovery were considered for this reservoir. Gas injection was not feasible because of limited supplies, and micellar injection was too expensive and risky. Waterflood susceptibility testing in cores showed favorable displacement of oil by water, making this the most appropriate secondary recovery method. The waterflood was projected to recover an additional 13.8% OOIP. Polymer flooding was not considered, because the mobility ratio was favorable and the reservoir was relatively tight, with an average permeability of 15 md. There were two basic challenges to waterflooding. First, there was concern that clays would limit injectivity over time. Also, the rock exhibited a permeability variation of 0.65, which could lead to bypassing of recoverable oil as water tended to establish channels through more permeable rock. Clays can exacerbate channeling. SPE 53007 was revised for publication from paper SPE 39937, first presented at the 1998 SPE Rocky Mountain Regional/Low Permeability Reservoirs Symposium, Denver, Colorado, 5-8 April.

scholarly journals Effect of Stand Structure and Number of Sample Trees on Optimal Management for Scots Pine: a Model-Based Study

Forests ◽  
2018 ◽  
Vol 9 (12) ◽  
pp. 750 ◽  
Author(s):  
Anssi Ahtikoski ◽  
Jouni Siipilehto ◽  
Hannu Salminen ◽  
Mika Lehtonen ◽  
Jari Hynynen
Keyword(s):  
Objective Function ◽  
Sample Size ◽  
Scots Pine ◽  
Net Present Value ◽  
Stand Structure ◽  
Objective Function Value ◽  
Sample Sizes ◽  
Present Value ◽  
Individual Tree ◽  
Recovery Method

This study presents an attempt to discover the effect of sample size on the financial outcome derived by stand-level optimization with individual tree modeling. The initial stand structure was altered to reflect sparse, average, and dense Scots pine (Pinus sylvestris L.) stands. The stands had varying numbers of stems but identical weighted median diameters and stand basal areas. The hypothetical Weibull diameter distributions were solved according to the parameter recovery method. The trees were systematically sampled with respect to the tree basal area corresponding to sample sizes of 10, 20, or 40 trees. We optimized the stand management with varying numbers of sample trees and with varying stand structures and compared the optimal solutions with respect to the objective function value (maximum net present value) and underlying management schedule. The results for the pine stands in southern and central Finland indicated that the variations in the objective function value relating to sample size were minor (<2.6%) in the sparse and average stand densities but exceeded 3% in the dense stands. Generally, the stand density is not always known, and thus, we may need to generalize the average density for all cases in question. This assumption, however, resulted in overestimations with respect to the optimal rotation period and financial performance in this study. The overestimations in the net present value decreased along with the increasing sample size, from 22% to 14% in the sample sizes of 10 and 40 trees, respectively.

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