Intermittent Gas Lift Research Articles

Technology Focus: Artificial Lift (October 2024)

Summer blockbuster season has passed, but it’s always nice to grab a bucket of popcorn and escape reality with a movie. Some movies even teach lessons—as in, sometimes it takes hard work and incremental improvements to advance. Chugging raw eggs, sprinting steps, and boxing meat slabs in epic training montages can be effective (Rocky), but so can optimization with computational flow dynamics. Paper IPTC 24243 shows that redesign of a jet pump sliding-sleeve coupling can considerably reduce pressure losses and increase throughput. The scientific method can even be exciting. Who doesn’t enjoy hypothesizing, experimenting, measuring, cleaning records, analyzing, and scaling up—especially if it pays off with a huge computer-generated explosion in the desert (Oppenheimer)? Paper SPE 218124 demonstrates the benefits of digitizing and analyzing operational data from electrical submersible pumps (ESPs) to improve run life and profitability. Paper OTC 34898 describes a comprehensive testing program to qualify load-bearing ESP deployment cable for corrosive conditions. Sometimes an overly precise plan draws us to the edge of our seats. The protagonist has recruited a crew of experts, rehearsed obsessively, ensured that every loose end has been tied, and yet some unknown still (temporarily) derails the vault raid (Ocean’s Eleven). Paper SPE 218028 attempts to bypass chance and minimize production interference by orchestrating a network of intermittently gas lifted wells. Is physics limiting what you can do? Then change the rules. You could move existence into a computer simulation (The Matrix) or perhaps start over with a novel material. Paper IPTC 23949 introduces fiber-reinforced thermoplastic sucker rods to accomplish more with less. Who doesn’t enjoy a quality sequel? There must be an infinite number of things that can be jumped with a car (The Fast and the Furious). Paper SPE 215010 analyzes failures of gas lift valves retrieved from subsea wells and could be considered a follow-up to paper OTC 30943, an artificial lift paper featured in 2021. Closure also can satisfy, even if it’s just the final act for a high school chemistry teacher with a side gig (Breaking Bad). With that in mind, it’s been an honor and a pleasure to pen the Artificial Lift Technology Focus page these past few years. I look forward to seeing who the directors cast next for this character. Recommended additional reading at OnePetro: www.onepetro.org. SPE 218124 Digitalizing the Management of Electric Submersible Pump Failures Through Failure Prevention and Post-Mortem Analysis Tools by Michael Ellsworth, Suncor Energy, et al. SPE 218028 Optimization of Gas-Injection Network Using Genetic Algorithm: A Solution for Intermittent Gas Lift Wells by Ankit Garg, Oil and Natural Gas Corporation, et al. IPTC 24243 Increasing Oil Production With Jet Pumps by Reducing Pressure Losses in the Jet Pump/Sliding Sleeve Coupling by J. Soria, Sertecpet, et al.

A simulation model for oil production by intermittent gas lift technology

The operating principle of the oil production by intermittent gas lift (IGL) technology and the mechanical processes occurring in it are complex with many different stages and many flows interacting with each other in each stage. This leads to many difficulties in calculating and optimizing oil well production system with IGL technology. This study develops a hydrodynamic simulation model of the flows occurring during oil production by IGL. By improving until now published hydrodynamic simulations the model in this work is developed based on changes/adjustments to be applicable for specific field conditions. Simulation of the IGL process is performed based on numerical solutions of the systems of conservation equations of mass and momentum and closure equations for each system component and each stage of the IGL process. The ordinary differential equations in the model are solved by the implicit Euler method. The simulation program has been developed and used in selecting a reasonable design of IGL technology for an oil well previously produced by the continuous gas lift (CGL). After the IGL system was installed and put into operation, the daily liquid production rate of the well increased by 91% and the measured data showed good agreement with the simulated results. The application result has initially demonstrated the applicability of the proposed model and the developed simulation program. Keywords: well; intermittent gas lift; simulation model; oil production.

Hybrid Gas-Lifting Method Optimizes High-GOR Production

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209721, “Hybrid Artificial Lift-SRP/Gas Lift for Oil Production in High-GOR Environments,” by Kuldeep Chanchlani, SPE, Ranjit Gogoi, and Sukumar Awasthi, SPE, ONGC, et al. The paper has not been peer reviewed. _ The casing gas-pressure-operated rod-lift (CGPORL) system described in the complete paper consists of a sucker rod, pump, gas-lift valves, downhole gas anchor, and tubing string. The completion was invented to save workover rig cost, reduce production deferments, and increase production efficiency in high-gas/oil-ratio (GOR) environments in marginal fields. CGPORL System Description The hybrid-lift system includes gas-lift and rod-lift modes, allowing operators to switch between two modes of artificial lift without costly workovers (Fig. 1). The key factor is the ability to isolate or communicate between the tubing and the annulus without pulling the tubing string out of the hole. Gas lift requires that the annulus should isolate tubing in order to inject gas through valves installed inside pocket mandrels, whereas rod pumps need communication between the tubing and annulus for passage of liberated free gas. Mechanism The gas-lift valve opens once annulus pressure develops over the valve-closing pressure. Once free gas is released into the tubing and the injection valve is closed, the annulus becomes a closed system. The free gas released from the downhole gas anchor gradually pressurizes the annulus until the valve opens for the next cycle. This mechanism indicates an intermittent gas-lift process in a cycle. When the well ceases to flow because of rod-lift failure, the well When the well ceases to flow because of rod-lift failure, the well will continue to flow through the annulus by keeping open the annulus valve connected to the nonreturn valve. Because of the nondevelopment of annulus pressure in case of rod-lift the CGPORL system. failure, a mobile air compressor can be used for valve unloading until the rod pump can be serviced. As the solution gas is recombined with liquid above the pump-setting depth, the hydrostatic head is relatively decreased. If the gas-lift valve is placed at a shallower depth, the drilled well length contributing to the reduction of fluid density is short. If the pump is placed at a deeper depth, annulus pressure can be high, so the gas-lift valve can be placed in a low position. Optimization for the point-of-pump setting and gas-lift-valve setting depth is required. These effects are related directly to the frequency of injection and rate, which must be examined along with economic and safety factors.

Analysis of crude oil production with gas lift methods

Some wells in the Niger Delta area are in their late production life. Water production increases with and reservoir pressure decreases to the point that the natural energy cannot sustain the production of hydrocarbon to the surface. The severity of this impact has been observed in the Niger Delta oil fields over the past years that has caused the abandonment of wells with a significant volume of hydrocarbon unrecovered. To increase production and extend the life of these wells, a gas lift project is considered. This study aimed to analyze oil production between continuous and intermittent gas lift systems based on real data obtained from two oil wells in a Niger Delta oilfield and to choose the system best suited to increase the production of the wells. To achieve this aim, a simulation study on continuous and intermittent gas lift methods was conducted using GAP and PROSPER software. The results obtained indicated that a continuous gas lift system will be suitable for a well that has a high flow rate and high GOR (well 1). For Well 2, the results indicated that an intermittent gas lift system will be suitable for a well that has lower reservoir pressure and low productivity.

Analysis of Crude Oil Production Using Gas Lift

Gas lift is used to increase production by reduction in the density of the oil column in the tubing, reduction of the flowing bottom-hole pressure which is affected by the hydrostatic pressure of the fluid column and by providing external energy to the oil. In this study an oil field in the Niger Delta was used as case study; it has a production life span of over ten years with characteristics such as high gas-oil ratio (GOR) and high reservoir pressure which makes gas lift suitable for optimizing the wells. The aim of this study is to select the gas lift method suitable for optimum production in the wells using the production modelling softwares PROSPER, and GAP. Simulation studies were conducted using data from two wells in the oil field. The performance of continuous and intermittent gas lifted performance on two wells were compared. The results indicated that continuous gas lift system will be suitable for a well that has high flow rate and high GOR. Also, intermittent gas lift system will be suitable for a well that has lower reservoir pressure and low productivity. Sensitivity analysis of water cuts, gas injection rates and well head pressures were carried out to investigate how the wells will respond to changing operating conditions such as increasing water cut, increasing gas injection rates and increasing well head pressures in the future.

Technology Focus: Artificial Lift (October 2021)

What, a second artificial lift focus feature this year? What’s going on? Well, maybe I can answer your questions with another round of questions: Do you know how many of your organization’s wells are artificially lifted? Or, more importantly, do you know what fraction of your production volumes are dependent on artificial lift? I would wager that the percentages are higher than you would expect, and I encourage you to seek out that information and share it. Share it with your asset team, share it with other asset teams, share it with other functions, share it with your management, shout it from the rooftops! Seriously, though, this information can be quite useful to you and your organization. Did you ever wonder if someone else could be struggling with the same artificial lift selection, installation, operation, or reliability challenges that you are? The answer you’re looking for may be in the SPE archives, or it may be just down the road with a colleague in a different part of the region, country, or world. Do you have a novel new technique, system, or invention that you want to try out? Why not leverage the knowledge that others in your company could also benefit from? Maybe they would even like to participate and strengthen your pilot with a broader range of test conditions. Do you need more personnel or technical or financial support for artificial lift in your asset? Show precisely what those electrical submersible pumps (ESPs), rod pumps, gas-lift valves, and plungers (among others) are lifting to the flowline. Sometimes a step back to a higher-level view can motivate and reinforce the people behind the day-to-day efforts to extend the time between failures and chase optimum performance. I’m certain that you are now a (possibly unwilling) expert at videoconferencing. That’s why I would like to encourage you to attend the 2021 SPE Electric Submersible Pumps Symposium, to be held 4–8 October in The Woodlands, Texas. Of course, the technical presentations will be well worth it, but you may gain even more value from the networking, collaboration, and idea generation that happens between the events listed in the program. Not an ESP person? Do gas and sand separators, power cables, advanced materials, and downhole sensors apply to other lift methods or well systems in general? How about applied artificial intelligence, reliability studies, and predictive analytics? Maybe they don’t for you right now, but they could. I hope to see you there. Recommended additional reading at OnePetro: www.onepetro.org. SPE 201153 - Intermittent Gas Lift for Liquid-Loaded Horizontal Wells in Tight Gas Shale Reservoirs by Daniel David Croce, Colorado School of Mines SPE 202668 - Insert Sucker Rod Surface-Controlled Subsurface Safety Valve: A Step Ahead To Improve the Well Integrity for Sucker Rod Artificial Lift Retrofitting by Salvatore Pilone, Eni, et al. SPE 201136 - New Stage of Rodless Artificial Lift Operation: The First Field Application of Submersible Motor Cable Plug With Electric Submersible Progressing Cavity Pump in CNPC by Shijia Zhu, China National Petroleum Corporation, et al.

Application of machine learning algorithms to predict tubing pressure in intermittent gas lift wells

Tubing pressure at gas injection depth in intermittent wells is one of the most critical parameters for production engineers to evaluate the performance of the system. However, monitoring of the tubing pressure is not usually carried out in real time. It has been realized that the generally used correlations are not effective enough due to complexity of the intermittent process which involve many parameters and assumptions to develop such equations. The focus of this study is to utilize machine learning (ML) algorithms to develop a model that can accurately predict tubing pressure in artificial intermittent gas lift wells. intelligent algorithms built on the field data provide a solution that is easy to use and universally applicable to the complex problems. Various non-linear regression ML methods are employed in this study, namely, Decision Tree-regression (DT), Random Forest-regression (RF) and K Nearest Neighbors-regression (KNN). All the tubing pressures obtained from ML models were compared with the actual values to ensure the effectiveness of the work. The developed models show that it can predict the pressure with more than 99.9% accuracy. This is an interesting result, as such outcome accuracy has not been reported usually in the open literature.

Optimisation of Artificial Lifts Using Prosper Nodal Analysis for BARBRA-1 Well in Niger Delta

Hydrocarbon exploration basically requires effective drilling and efficient overpowering of frictional and viscosity forces. Normally, frictional power losses occur in deep well systems and it is essential to analyse each component of any well system to determine where exactly pressure is lost, and this can be done using Nodal Analysis. In this study, nodal analysis has been carried out with the use of PROSPER, a software for well performance, design and optimisation. Artificial lifts can then be used to solve the problem of frictional power losses. To increase the production of Barbra 1 well in the Niger Delta and hence extend its functional life, we have applied nodal analysis. Modelling results for three artificial lift methods; continuous gas lift, intermittent gas lift and electrical submersible pump were found to be 1734.93 bbl/day, 451.50 bbl/day and 2869 bbl/day respectively. The output from the well performance without artificial lift was 1370.99 bbl/day by applying Darcy’s model. Meanwhile, the output from the well without artificial lift is 89.90 bbl/day when aided with productivity index (PI) entry, the normal model for intermittent gas lift. Hence, from the comparative analysis of the results obtained from this study, it was deduced that when artificial lifts are employed, the well output increases significantly from 1370.99bbl/day to 2869 bbl/day (electrical submersible pump). This study concludes that wells such as Barbra 1 are good candidates for artificial lift, and this is evidenced by increasing productivity.
 Keywords: Production optimisation, nodal analysis, prosper simulator and barbra well.

A Mathematical Model of Intermittent Gas Lift in Elevation-Production Operation with Line-Pack and Line-Drafting Phenomena in a Gas Line

This paper discusses a transient model of the intermittent gas lift technique in an oil well. The model is developed in the gas line, in the tubing-casing annulus, and the tubing. The line-pack and line-drafting phenomena in the gas line are considered in the model. A numerical approach will be used to solve the mathematical model that represents fluid flow during intermittent gas lift injection. The dynamics of important variables in the intermittent gas lift are investigated and analyzed to determine the best production strategy for intermittent gas lift. The variables are film thickness and velocity, slug height and velocity, and gas height and velocity. The relationships between surface injection control parameters (gas injection pressure and gas injection rate) and the velocity and height of film, gas, and liquid are shown in one cycle of the gas lift intermittent process. The higher the gas injection pressure, the faster the gas injection velocity, and the thinner the film thickness in the tubing. In order to obtain clean tubing from film thickness, the gas injection pressure needs to be optimized, which will lead to maintaining compressor discharge pressure availability. Detailed observation of the dynamic performance inside the tubing production well will give the optimum oil production rate for oil wells under a gas lift intermittent production strategy for field application.

Computational fluid dynamic (CFD) simulation of pilot operated intermittent gas lift valve

To design an efficient intermittent gas-lift installation, reliable information is needed in the performance of all process components, from the outer boundary of the reservoir to the surface separators. The gas lift valve is the one critical component that affects the design of the whole system. In intermittent producing system, the pilot gas-lift valve is extremely used to control the point of compressed gas entry into the production tubing and acts as a pressure regulator. A novel approach using computational fluid dynamics simulation was performed in this study to develop a dynamic model for the gas passage performance of a 1-in., Nitrogen-charged, pilot gas-lift valve. Dynamic performance curves were obtained by using Methane as an injection gas with flow rates reaching up to 4.5 MMscf/day. This study investigates the effect of internal pressure, velocity and temperature distribution within the pilot valve that cannot be predicted in the experiments and mathematical models during the flow-performance studies. A general equation of the nonconstant discharge coefficient has been developed for 1-inch pilot valve to be used for further calculation in the industry without using CFD model. The developed model significantly reduces the complexity of the data required to calculate the discharge coefficient.

Computational fluid dynamic (CFD) modelling of transient flow in the intermittent gas lift

A computational fluid dynamics model (CFD) is developed for intermittent gas lift techniques. The simulation is conducted for a test section of 18 m vertical tube with 0.076 m in diameter using air as injection gas and oil as a formation fluid. The results obtained from the CFD model are validated with the experiment results from the literature. The current study shows that computational modeling is a proven simulation program for predicting intermittent gas lift characteristics and the transient flow parameters that are changing with time and position in the coordinate system. The model can predict the slug velocity behavior for different injection pressure. The slug velocity profile shows three regions; the first region is the rapid acceleration at the initial time of injection, the second region shows the nearly constant velocity until the slug reaches the surface and the third region is again the rapid acceleration when the liquid starts to produce. Also, the results obtained from this model show that as the gas injection pressure increases, the liquid slug velocity increase, and the region of the constant velocity decrease. The effect of the injection time on the liquid production rate has been studied for two different gas injection pressures of 40 psig and 50 psig. The developed model shows that more than 50% of the liquid production is coming from after flow period.

A method for comparison of lifting effects of plunger lift and continuous gas lift

Abstract As a kind of intermittent gas lift, the plunger lift can replace the continuous gas lift in a certain period of time to improve the lifting efficiency. However, the working system of plunger lift is different from that of continuous gas lift, so their lifting effects cannot be compared intuitively. In this paper, taking Zhanaroal oilfield as an example, an experiment to compare the lifting effects of plunger lift and continuous gas lift was designed. Taking the gas consumption under the same liquid lifting volume as the starting point, the stable lifting conditions of them were firstly determined; then, based on the experimental data under the stable lifting conditions, their gas consumption under the same liquid lifting volume was calculated; the lifting effects of them under different liquid volumes were compared, and the feasibility of replacing continuous gas lift with plunger lift in the study block was confirmed; moreover, two wells tested have achieved good effect.

Intermittent Gas Lift Used in Hydrate Mitigation and Flare Reduction in Algeria

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191542, “Hydrate Mitigation and Flare Reduction Using Intermittent Gas Lift in Hassi Messaoud, Algeria,” by Ala Eddine Aoun, SPE, Faouzi Maougal, and Lahcene Kabour, Sonatrach, and Tony Liao, SPE, Brahim AbdallahElhadj, and Sabrina Behaz, Halliburton, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. Hassi Messaoud is a mature oil field with more than 1,100 production wells. Approximately half of the wells are natural flow and the other half use continuous gas lift (CGL) with concentric (CCE) strings. To reduce the usage of the high volume of lift gas, intermittent gas lift (IGL) was selected in a pilot project to evaluate its applicability in the field for wells characterized by high gas/oil ratio (GOR) and without continuous concurrent water injection (with lift gas) to dissolve salt•deposited•downhole. Production Overview Field production began in 1957. During the first 20 years, all production wells were naturally flowing; in 1980, gas lift was introduced into the field development and has remained the only artificial-lift method. Electrical submersible pumping systems have been introduced into the field recently. Of the production wells, 795 are flowing while 376 are shut in for a variety of reasons. Among the flowing production wells, 409 are naturally flowing and 386 are artificial-lift wells. Production fluids are processed by 25 separator stations throughout the field. Gas usually is compressed first at the satellite level; then, at the central processing facilities, the gas is further compressed to the pressure required for injection into the reservoir. Water is treated by the addition of surfactants. The treated water is pumped into the water-injection network to be used in both reservoir-pressure maintenance and salt wash in wells. In the field’s first years, the oil-production rate increased quickly as the number of wells grew. Since 2007, oil production has declined quickly in naturally flowing wells. The steady increase in oil production from gas-lift wells offset the fast production decline in the full field. However, the oil production from gas-lift wells has leveled off during the past 2 years, while the production from naturally flowing wells recovered slightly. The gas lift wells contribute approximately 40% of the field production. Combined Gas Network for•Reservoir Gas Injection and Gas Lift A specific challenge of the Hassi Messaoud field operation is the highly complex gas network, in which the gas-lift network is attached to the gas- injection network for reservoir-pressure maintenance. The gas lift was grown organically out of the reservoir gas-injection network. Initially, when only a small number of wells needed gas lift, this approach might have been cost- effective, but the increasing number of gas-lift wells meant that different methods had to be•considered.

Chamber Gas Lift in Horizontals

Summary In this paper we highlight a pilot project in which chamber gas lift was installed in two unconventional horizontal wells. Chamber gas lift, a combination of deep gas lift and intermittent gas lift, allows for an efficient, closed completion with the cyclic injection of high-pressure gas, which expands and rapidly displaces fluid at high velocity from deep in the well. Development of the system was a collaboration internally and in conjunction with the vendor to install what was historically a vertical-well assembly through the curve section and into a horizontal wellbore. The chamber assembly was successfully designed, sourced, manufactured, installed, and operated. To modify the design from vertical to horizontal applications, components were custom-designed to maintain a sealed chamber. Components deemed most likely to fail are replaceable by slickline intervention. Results indicate a sustained lower downhole pressure than the previous intermittent-gas-lift system, an increase in production, and a good chamber-sweep efficiency.

Optimasi Intermittent Gas lift Pada Sumur AB-1 Lapangan Brownfield

Gas lift is one of the artificial lift method that has mechanism to decrease the flowing pressure gradient in the pipe or relieving the fluid column inside the tubing by injecting amount of gas into the annulus between casing and tubing. The volume of injected gas was inversely proportional to decreasing of flowing pressure gradient, the more volume of gas injected the smaller the pressure gradient. Increasing flowrate is expected by decreasing pressure gradient, but it does not always obtained when the well is in optimum condition. The increasing of flow rate will not occured even though the volume of injected gas is abundant. Therefore, the precisely design of gas lift included amount of cycle, gas injection volume and oil recovery estimation is needed. At the begining well AB-1 using artificial lift method that was continuos gas lift with PI value assumption about 0.5 STB/D/psi. Along with decreasing of production flow rate dan availability of the gas injection in brownfield, so this well must be analyze to determined the appropriate production method under current well condition. There are two types of gas lift method, continuous and intermittent gas lift. Each type of gas lift has different optimal condition to increase the production rate. The optimum conditions of continuous gaslift are high productivity 0.5 STB/D/psi and minimum production rate 100 BFPD. Otherwise, the intermittent gas lift has limitations PI and production rate which is lower than continuous gas lift.The results of the analysis are Well AB-1 has production rate gain amount 20.75 BFPD from 23 BFPD became 43.75 BFPD with injected gas volume 200 MSCFPD and total cycle 13 cycle/day. This intermittent gas lift design affected gas injection volume efficiency amount 32%.

Совершенствование расчета периодического газлифта

Совершенствование расчета периодического газлифта

Applications of line-pack model of gas flow in intermittent gas lift injection line

Intermittent gas lift is one of injection techniques for mature wells with low-productivity. This technique has two periods i.e. shut-in and production periods. During shut-in period the choke is closed, and the gas flows from the compressor into the gas-line. Furthermore, production period takes place when the choke is open to allow the gas flows into the tubing-casing. This process is similar to line-pack and line-draft in transient gas flow. It is known that the upstream choke pressure should be high enough to lift the oil. Hence, it is very important to control the shut-in period. In this paper, a line-pack model for an intermittent gas lift is constructed. The model is used to predict high-pressure performance at the upstream choke. Moreover, the model is compared with field data from literature. The effect of opened-closed choke to the pressure and the gas rate is analyzed. Sensitivity analysis with respect to gas-line length, gas rate, discharge pressure, and duration of shut-in are shown. The results show that the pressure at the upstream choke can be estimated as well as the duration of shut-in which are critical in increasing the pressure. This model is important for avoiding production operation failure.

Intermittent gaslift flows in vertical pipes

The paper presents the study results of intermittent gaslift. vertical flows using both experiment and theoretical models. To study the influence of medium thermophysical characteristics on the process efficiency, two gas-liquid systems are used in the experiments. The obtained results show that there is a critical gas injection volume, less than that the liquid slug cannot reach the top of the tubing. Correlations for prediction of liquid entrainment in gas core are also shown for two presented gas-liquid systems. Amodified dynamical model was developed. The model consists of a system of differential equations. The resulting system of equations is numerically solved. The numerical code is verified by using experimental data and calculation data of the other authors. Finally, the effects of system parameters are studied.

MODELING AND PERFORMANCE ASSESSMENT OF INVERTED INTERMITTENT GAS LIFT

The Intermittent Gas Lift (IGL) is an artificial lift method for petroleum production suitable for producing wells from depleted or low productivity reservoirs. In order to enhance the well production, many variants of the conventional IGL have been developed and used worldwide. One of these variants, the Inverted IGL (IGL-I), consists of removing the gas lift valve and reversing the flow paths inside the well: gas is injected through the tubing whereas liquid is lifted through the casing annulus. The oil production is believed to increase with the IGL-I due to the larger annulus storage capacity, at the expense of higher injected gas volumes. Despite of its potential for practical applications, the IGL-I has not been covered by the literature. Aiming to surmount such gap in the literature, this paper presents a model for the dynamical behavior of the IGL-I wells. The complexity emerged from the IGL-I cyclic operation is assessed through a simultaneous and coupled simulation scheme, comprising a variable set of non-linear algebraic equations and non-linear time-differential equations for the flow of oil and gas throughout the injection, transfer, elevation, production, decompression and loading stages of each cycle. The simulator provides the engineer with a valuable tool to investigate the well behavior of several IGL cycles. Based on the observed results, the designer may propose practical recommendations regarding the IGL-I design and operation.

MEOR in Northwest Peru

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 94934, "Biotechnology Application to EOR in Talara Offshore Oil Fields, Northwest Peru" by A. Maure, Microbes Inc., and A.A. Saldana, SPE, and A.R. Juarez, SPE, Petro-Tech Peruana S.A., prepared for the 2005 SPE Latin American and Caribbean Petroleum Engineering Conference, Rio de Janeiro, 20–23 June. Seven producing wells in the Providencia and Lobitos fields of Block Z-2 in the Talara basin were selected to evaluate a biotechnology approach for enhanced oil recovery (EOR). The microbial-EOR (MEOR) candidates produce from faulted reservoirs by intermittent gas lift methods. The oils are paraffinic and present good candidates for biotreatability. Because of operational reasons not directly related to MEOR, the complete inoculation program was concluded in only four of the original seven wells. Biotechnology Biotechnology methods are founded in the use of sophisticated enzyme biochemistry to accelerate redox reactions that involve different hydrocarbon compounds. MEOR technology in the upstream sector is based on the systematic inoculation of producers and/or injectors with specific microbial systems, biocatalyzers, and nutrients. The pulsing program pursues as its primary goal the colonizing of the porous medium of the oil-bearing zones. The second objective is to control enzymatic reactions at water/oil interfaces in the producing formation to modify oil mobility by producing low-molecular-weight solvents and biosurfactants. Organic geochemistry methods monitor the stability and efficiency of these bioreactions. Producer Wells. Producer wells are treated by periodically pumping microbial batches downhole to reach the near-wellbore porous space. The microbial effect in treated wells benefits production in two ways. It removes organic damage occurring near the wellbore of the perforated interval to open nonproductive zones containing oils with a heavier and pseudoplastic behavior. This effect produces a high peak oil rate for a limited time. These treatments can produce permanent rheological effects by the compositional alteration that occurs at a larger colonization radius. This effect is the most important MEOR objective because this improvement is sustainable for a long period if a proper microbial inoculation schedule is continued. Injector Wells. In injector wells, the treatment uses the injected water as a carrier to introduce microorganisms and passive substances into active streamtubes of flooded space for target layers. Compared to the producer treatments, the advantage of treating injectors is a larger size of colonized zones with longer residence times. Biocracking. Biocracking is based on a systematic way to alter n-alkane compositional profiles in oils. The use of enzyme biochemistry accelerates the redox reactions involving linear hydrocarbons. Heavy paraffinic compounds can be transformed into shorter ones by the enzymatic action of repetitive cycles, which are assisted by symbiotic microorganisms and specific nutrients. By alternating aerobic/facultative hemicycles with strictly anaerobic, the time-coordinated action of selected groups of microorganisms in oxidant and reductive environments results in a substantial shift in oil compositional profile.