Gas Lift Research Articles

A Procedure for Liquid-Assisted Gas Lift Unloading Using a Transient Flow Simulator

Summary In this paper we describe using a commercial transient multiphase-flow simulator to develop a new operational procedure for liquid-assisted gas lift (LAGL) unloading. The simulation model is used in our study to perform sensitivity analysis on the controlling parameters for the LAGL unloading operation. This simulation model is validated with experimental data from field-scale test data presented by Coutinho et al. (2018). From the simulation results and experimental data, it is possible to demonstrate how the injection of a gas/liquid mixture can significantly decrease the injection pressure for unloading operations. Different combinations of injection gas/liquid ratio are numerically tested to evaluate the effect of gas/liquid ratio on the injection pressure during the complete unloading operation. The validated model was used with a newly developed procedure for the complete unloading operation. The modeling results show that using the LAGL technique enabled us to reduce the injection pressure from 1,200 psig, when using single-phase gas in a single-point injection system, to approximately 700 psig, when injecting gas/liquid mixtures in a single-point injection system. Analyses on the effect of gas lift valve-orifice size, also presented here, show that using large orifice sizes might reduce the effect of flow friction through the gas lift valve, which directly affects the efficiency of the LAGL unloading operations.

Wind Turbine Electrical Energy Supply System for Oil Well Heating

In this article, the authors reviewed a new technology to prevent the formation of asphalt-resin-paraffin deposits by the thermal method of electrothermal impact on the oil wellbore shaft using a wind-electric installation as an autonomous power source. The advantage of this thermal stimulation technique lies in its continuous nature, which will allow keeping the clear opening of the tubing constant. The scheme of the autonomous system for down-hole electric heating of oil is presented. A tubular or induction heater can serve as an electric heating element placed in the well. The heating element of the system can be used in the wells exploited by freeflow, gas lift and mechanized methods, while its installation does not require an overhaul. The paraffin oil saturation temperature and temperature distribution over the depth of the well were defined. The amount of heat, which must be transferred to the oil mixture in the tubing in order to ensure effective operation of the well, taking into account the dynamic state of the system, is calculated. The optimal depth of the heating element's location in the well and its power was determined. The calculation of the required power for wind-electric installation to maintain the set temperature in the wellbore was performed. Having conducted the studies, it was revealed that in order to prevent the asphalt-resin-paraffin deposits formation on the tubing walls of oil wells, it is expedient to use the in-line heater, which maintains the average steady-state temperature along the wellbore and at the wellhead above the initial crystallization point of the asphaltresin-paraffin deposits. The application of the developed electrothermal system is relevant in the conditions of formation of asphalt-resin-paraffin deposits in the wellbore shaft at the fields, which do not have a connection to the centralized power grid.

Gas Lift Operations Require Accurate Predictions of Downhole Annulus Pressure

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 190929, “Gas Lift Annulus Pressure,” by Kenneth Decker, SPE, retired, and Robert P. Sutton, SPE, consultant, prepared for the 2018 SPE Artificial Lift Conference and Exhibition—Americas, The Woodlands, Texas, USA, 28–30 August. The paper has not been peer reviewed. Downhole annulus pressure is required for any gas lift design. This paper presents several methods of determining annulus pressure at depth and helps determine which method is most appropriate for specific conditions. It also provides advice on the accuracy of a combination of different critical properties and compressibility correlations, offers an alternative design technique to account for changing annulus temperature during unloading, and provides guidelines for modeling changes in annulus pressure during unloading. Introduction While many methods of computing gas pressure in a flowing environment are available, what is needed in the case of gas lift is the static annulus pressure at depth. Historically, the method of using average temperature and pressure to compute compressibility factors and assuming linear well-temperature gradients made gas lift design relatively simple. The small errors were tolerable and within the normal design safety mar-gins of operating systems with surface pressures of less than 1,500 psi. When surface injection pressures exceed 1,500 psi, calculations become more important. Computers are now used to calculate downhole annulus pressure, and the designer must trust the number that appears on the computer screen. That trust may not be warranted, depending on the method of calculation. The small errors that creep into computer calculations increase linearly as surface injection pressure increases. Additionally, the choice of which correlation to use to model the critical properties of the gas and which compressibility factor correlation to use also affect the accuracy of the calculation. As a gas lift well transitions from a geothermal to a flowing temperature profile during unloading and lifting, the annulus pressure at depth decreases despite surface injection pressure remaining unchanged. The change in annulus pressure is governed by the volume of gas present in the annulus. Reduction in gas volume decreases pressure. Traditional design techniques ignore this reality and substitute a simplified analogy of valve performance that incurs errors and misconceptions about how the annulus pressure changes during unloading. A more-detailed discussion of these issues and proposed questions for program developers is presented in the complete paper. Annulus Pressure Calculation Methods Methods of determining downhole annulus pressure include monographs, density equations used to full depth with average pressure and temperature, and density equations used in small depth increments with average temperature and pressure within the increment. An examination of one of these monographs is shown in Fig. 1. The choice of which method to use comes with limitations on the accuracy of the predicted pressure at depth.

Optimization of gas injection allocation to increase oil production using Gbest-guided artificial bee colony algorithm

Oil comes from fossils thousands of years ago and it is natural resource that can’t be renewed. If it used continuously, the oil supplies will eventually run out. One way to optimize an oil production is by using gas lift. When the supply of the gas injection is limited, the total available gas should optimally distributed among the oil wells of the field such that the total production of oil is maximized. In this paper, Gbest-guided artificial bee colony (GABC) will became the optimization techniques while Least square is used to make the mathematical model from the correlation between gas injection and oil production. Contribution of this research is to find the fittest mathematical model and implement GABC to find the maximum value of mathematical model. The selected model is 10th order polynomial with R-square value of 1 and Sum of squares error (SSE) is 34.091. GABC will optimize the model and it will be compared to another optimization method such as Artificial bee colony (ABC). The results are GABC is better than ABC for each case with 4812.877 barrel oil per day (Bopd), 5107.873 Bopd, and 5142.156 Bopd respectively, while the best C values in GABC is 2.

Technology Focus: Artificial Lift (March 2019)

Technology Focus With all the emphasis placed on artificial-lift run-life improvement, you might wonder if there are any tricks left in that bag. I contend there is one really big secret left—and it is hiding in plain sight. That trick is to use international standards as the foundation of your reliability program. A Chinese proverb says, “The journey of a thousand miles begins with a single step.” There are many steps in the long journey toward maximizing run life, including proper installation, operation, training, surveillance, audits, service-quality reviews, teardowns, and root-cause analysis. But, the first step should be to identify the requirements for your artificial-lift system and to communicate those requirements effectively to the vendor. In many cases, this is the most challenging step, largely because operators and suppliers often speak different languages. Fortunately, international standards are there for us to bridge that language gap. The International Organization for Standardization (ISO) defines a standard as “a document that provides requirements, specifications, guidelines, or characteristics that can be used consistently to ensure that materials, products, processes, and services are fit for their purpose.” Today, the American Petroleum Institute (API) and the ISO provide such standards for electrical submersible pumps, progressing-cavity pumps, sucker-rod pumps, gas lift, and plunger lift, and API complements their standards with recommended practices that provide guidance from industry experts in the use of such technologies. A surprisingly small number of operators purchase monogrammed equipment or even reference the standards in their purchasing documents or contracts. This is unfortunate because standards can make everyone’s lives much easier, allowing operators and suppliers to speak the same language by providing consistent nomenclature, definitions, and performance ratings for equipment. Operators have greater peace of mind knowing their equipment is supported by sound engineering practices and will perform as promised. When standards are referenced in requests for proposal, vendors are able to provide responses that are more appropriate for the application, resulting in a greater chance of success in the field. Operators can also make an apples-to-apples comparison when evaluating the proposals they receive. Standards help level the playing field, enabling suppliers to segment the market more effectively. And they enable manufacturers to implement consistent, effective quality-assurance processes while avoiding the time and expense of custom solutions. So, who writes all of these standards, anyway? The short answer is that we all do. API and ISO committees are generally composed of subject-matter experts rep-resenting an equal number of operators and vendors, often from different parts of the world. You can join one of these committees to help improve a particular standard. The key to making standards work for all of us is to use them. The more we use standards in our business, the better they will become over time. Recommended additional reading at OnePetro: www.onepetro.org. SPE 190920 Visualizing Rod Design and Analysis Through the Wave Equation by Walter Phillips, 3DWellbore.com SPE 190950 Effect of Gas Lift Design in Unconventional Wells—A Delaware Basin Operator’s Perspective by Subash K. Kannan, Anadarko, et al. SPE 192511 ESP Run-Life Improvement Through Auditing of ESP Workshops by Tamer Edries, Khalda Petroleum, et al.

Modeling and field-testing of fracturing fluid back-flow after acid fracturing in unconventional reservoirs

When the oil shale reservoir completes acid fracturing, the back-flow of fracturing fluid program is needed. In this paper, a three-dimensional model is established and the finite element analysis software is used to simulate the feasibility of gas lift back fracturing fluid in Fuyu oil shale formation after acid fracturing. The results show that when the injection pressure of FK-1 well is 8.5 MPa, the fracturing fluid can be effectively displaced. Fracturing fluid is discharged along the fracture into FK-2 well, and a few fracturing fluids overflow the pyrolysis zone along the direction of oil shale bedding. Then the experiment is carried out to verify the accuracy of numerical simulation. What's more, it is also verified that the connectivity of oil shale reservoir meets the needs of oil shale in-situ pyrolysis process.

Optimized production profile using a coupled reservoir-network model

This paper presents an integrated approach for scheduling and forecasting oil and gas production by integrating models of the entire value chain, from the reservoirs to the sales points. The methodology ensures maximum oil production at each time step of the reservoir simulator while honoring all operational constraints of the system. The proposed method is applied to a small North Sea offshore field consisting of two oil reservoirs with API gravities of 37 and 39. 3 gas-lifted wells are producing in each reservoir. They are arranged in a production network connected to a surface process. Control variables include individual well choke opening (early stage) and gas lift injection rate (later stage). The system is subject to numerous operational constraints (e.g., maximum field liquid production, maximum gas lift injection rate). The proposed solution is built in a commercial IAM platform that connects the models and orchestrates the software execution and optimization. The optimization problem is formulated as a Mixed Integer Linear Program. The well and flowline performance curves are approximated with piecewise linear functions. Results show that such an integrated approach can significantly affect the production profile (up to 15% difference against traditional “silo” approach). The proposed integrated solution is two-to-three times faster than traditional non-linear optimization methods, guarantees convergence towards the global maximum and it represents with an appropriate level of accuracy the original black-box model. This allows to run a lot of different scenarios making it a suitable tool for field development and planning optimization. The proposed method is used to optimize the field design and schedule. Optimal surface capacities are determined by brute force exploration of net present value function.

Optimization of production and lift-gas allocation to producing wells by a new developed GLPC correlation and a simple optimization method

ABSTRACTIdeally, if there is no limitation in the available resources of gas in the gas lift operation, the adequate amount of gas can be injected into the reservoir to have the highest production rate. However, the amount of available gas and the capacity of the compressors are limited and it is required to optimize the gas injection into each well to have the highest recovery. Most of the former studies have been done by complex optimization algorithms and neural networks which require programming languages and a huge amount of time. In this study, we tried to optimize the amount of the injected gas in one of the heavy oil reservoirs in the west of Iran by the use of excel solver software. Then, the results are compared with the famous methods of optimization by genetic algorithm (GA) and particle swarm optimization (PSO) algorithm. Additionally, to improve the accuracy of calculation of the amount of oil production versus the amount of gas injection to the well, the empirical correlations are modified to fit the gas lift performance curves and a new correlation is developed. The results show that the model developed by the authors have the highest accuracy in comparison to other methods. Moreover, the results show that the accuracy of excel solver software is high enough in comparison to GA and PSO algorithm.Abbreviations: ANN - Artificial Neural Network; ARE - Absolute Relative Error; BR - Bayesian Regularization; D - Day; GA - Genetic Algorithm; GLPC - Gas Lift Performance Curve; GOR - Gas Oil Ratio; IPR - Inflow Performance Relationship; LM - Levenberg–Marquardt; MD - Measured Depth; MINLP - Mixed Integer Nonlinear Programming; MMSCF - Million standard Cubic Feet; MSCF - Thousand Standard Cubic Feet; P.I - Productivity Index; ppm - parts per million; PSO - Particle Swarm Optimization; PVT - Pressure-Volume-Temperature; SQP - Sequential Quadratic Programming; SSE - Sum of Squared Errors; SST - Total Sum of Squares; SSSV - Sub Surface Safety Valve; STB - Stock Tank Barrel; TBG - Tubing; TLBO - Teaching-Learning Based Optimization; TVD - True Vertical Depth; WPC - Well Production Curve.

A Dynamic Extremum Seeking Scheme Applied to Gas Lift Optimization

Abstract This paper presents the application of a data-driven optimization scheme using transient measurements to a gas-lift optimization problem. Optimal operation of a gas-lifted field involves controlling the marginal gas-oil ratio (mGOR), which is the steady-state gradient of the oil rate from the gas lift injection rate. In this paper we apply a dynamic extremum seeking scheme to estimate the marginal GOR online using transient measurements, which is based on identifying a local linear dynamic model around the current operating point instead of a local linear static model. By doing so, we can use the transient measurements and effectively remove the time-scale separation between the plant dynamics and the perturbation signal, that is typically required in the classical extremum seeking scheme. This results in significantly faster convergence to the optimum compared to classical extremum seeking scheme. The effectiveness of the proposed method is demonstrated using simulation results for a single gas lifted well, as well as a network of gas lifted wells.

Integrated Gas Lift Completion String for Ultra-Deep Reservoir

Kenjiyak Oilfield, in Kazakhstan, is an ultra-deep oil reservoir of low porosity and ultra-low permeability, causing a myriad of technical problems when produced with conventional gas lift string. To address these problems, an integrated gas lift completion string has been developed. The completion string integrates fracturing, drainage and gas lift processes, and is capable of accomplishing multiple operations of zonal fracturing, quick flowback, reservoir protection, retrieving and gas lift production, etc., in one trip. This paper introduces the structure and working principles of this string, structural and performance characteristics of the key supporting tools. Meanwhile, it analyses the retrievable gas lift mandrel and drillable-retrievable packer. 47 wells' field application showed this completion string's maximum application was 4,287.63m, the maximum working pressure was 68MPa, the maximum single well daily yield was about 130t and the average drainage duration was 3 days, presenting significant operation performances. The integrated gas lift completion string is expected to provide strong technical support for oil production with low cost and high efficiency, thereby accelerating the development of overseas oilfields.

Valve nozzle shape effect on gas lift system performance

Experiments were carried out using conical, bevelled entrance, bullet and orifice gas lift valve nozzle shapes with port diameter of 5 to 12 mm to study the effect of gas lift valve nozzle shape on the continuous flow gas lift system efficiency. A nitrogen-glycerin with nitrogen injection rate of 0.033 to 0.167 L/s flow through 50 mm diameter transparent vertical pipe and 3 m height to simulate a continuous flow gas lift system. Taylor bubble length and liquid produced mass were measured. The flow pattern was observed and the image was recorded using digital single-lens reflex camera. It was found that only slug flow occurred and gradual conical nozzle shape enlargement reduced the energy loss within the valve. The overall results show that conical nozzle produced the highest efficiency due to the less energy losses within the valve nozzle and most stable gas flow achieved in the fluid column pipe. [Received: December 24, 2015; Accepted: June 6, 2017]

СИСТЕМА АВТОМАТИЗАЦИИ ДЛЯ ПОВЫШЕНИЯ ЭФФЕКТИВНОСТИ РАБОТЫ СКВАЖИН ПРИ ГАЗЛИФТНОЙ ЭКСПЛУАТАЦИИ

The paper deals with the problem of automation of one of the methods of mechanized production - gas lift wells operation. The main advantages of this method of operation are its low cost, work with high gas content, simplicity of the design of deep equipment, fast repair in cattle, minimal power consumption and control and automation of the extraction process at the expense of the Gazlift process control system. This complex is designed to control the process of gas-lift oil production by remote control, as well as the collection and processing of information from primary transducers, the ability to control actuators that provide optimal performance of wells, as well as the ability to quickly change the mode of operation of wells.

Multiphase gas compression to boost unconventional production and reserves

Hydraulic fracturing has significantly increased well inflow performance in unconventional reservoirs, enabling their economic development. This improved inflow performance has opened up the possibility of leveraging further reserves and production gains through artificial lift or similar production enhancement techniques. A ‘multiphase compressor’ has been developed with differentiating characteristics:compression ratios of up to 40:1 (an order of magnitude greater than conventional compressors), ability to handle a broad range of multiphase conditions, and significant operational flexibility. This makes it very well suited for deployment in unconventional reservoirs at the wellhead, either on its own in a multiphase boosting capacity or in conjunction with other forms of artificial lift (such as gas lift, plunger lift, and potentially downhole pumping). The multiphase compressor has been deployed in the field on naturally flowing wells, and wells with plunger lift. Production rate increases of up to 300% were achieved, and production was maintained in wells that would have otherwise loaded up and died. Wells were unloaded by reducing wellhead flowing pressures to atmospheric pressure at the compressor suction – similar to flowing the well into an ‘open topped’ tank. The multiphase compressor demonstrated a very broad operating range and the ability to handle slug flow conditions. Further applications to be tested include gas lift and downhole pumping in shale wells, gas wells that have received fracture hits and require clean up from invaded fracture fluids, and coal seam gas production. Multiphase compression has significant potential to increase both production and reserves from unconventional reservoirs and wells.

Valve nozzle shape effect on gas lift system performance

Valve nozzle shape effect on gas lift system performance

Multiple‐model sliding mode observer for an artificial gas lift system

AbstractArtificial gas lift is widely used in the oil industry to enhance oil recovery. Active feedback control of this process would lead to its stabilization, that in some operating modes may otherwise be unstable, and to the increase of oil production. However, the control strategies are normally constrained to the use of the surface‐measured process variables. The use of down‐hole measurements would improve the performance of the control system but is technically hardly feasible due to the necessity of placing instruments in harsh conditions. The use of state observation might be a feasible alternative to the down‐hole measurements. Recent development of a new accurate model of the artificial gas lift process enables us to increase accuracy of observation due to the account of pressure and density distribution along the well depth. Besides, a new approach to a nonlinear model treatment proposed in the present paper leads to a high computational efficiency of the observer for the gas lift. The paper presents an approach to the design of a novel sliding mode observer for the gas lift process. The observer uses multiple linearized models representing deviations from a set of equilibrium points. These models are then incorporated to produce estimates for the gas lift process variables. The approach is supported by simulations.

The Critical Investigation on Essential Parameters to Optimize the Gas Lift Performance In “J” Field Using Prosper Modelling

The declining reservoir, oil production and pressure depletion with the well being produced, the results of the investment of the well will also decrease. For that there needs to be energy that can help to lift the fluid to the surface.
 One of the artificial lift methods that can be used is a gas lift. Gas lift is a method commonly used when there is a natural gas source as an injection gas supply. The selection of the artificial lift method is based on several considerations, namely the reservoir conditions, fluid conditions, well conditions, conditions on the surface, availability of electricity, availability of gas, and sand problem. The influential parameters in the selection of gas lifts include: Productivity Index (PI), Gas Liquid Ratio (GLR), depth of the well and driving mechanism from the reservoir.
 The Gas Lift that the production optimization wants to do is the injection system in a Continuous Gas Lift. Used in wells that have a high Productifity Index value. Where in the LB field to be analyzed, the Productifity Index value is 2.0 bpd / psi.
 This study intends to optimize a gaslift well performance as an effort to maximize the results of well production.
 Based on the research that has been done using Prosper Modeling on the “J” field, the following conclusions are obtained the effect of pressure and viscosity on the gas lift well flow rate in this condition can be said to be efficient, because the conditions / pressure given at temperatures below 300 F can reach the miscible condition and from the results of determining the optimal conditions to get the best well performance, obtain an optimal liquid rate of 1829.4 STB / D with an oil rate of 36.6 STB / D.
 
 Keywords: Gas lift, Optimization, Immiscible Pressure, Viscosity

Distributed Temperature Sensing Monitoring of Well Completion Processes in a CO₂ Geological Storage Demonstration Site.

The Distributed Temperature Sensing (DTS) profiles obtained during well completion of a CO2 monitoring well were analyzed to characterize each well completion process in terms of temperature anomalies. Before analysis, we corrected the depth by redistributing the discrepancy, and then explored three temperature calibration methods. Consequently, we confirmed the depth discrepancy could be well corrected with conventional error redistribution techniques. Among three temperature calibration methods, the conventional method shows the best results. However, pointwise methods using heat coil or in-well divers also showed reliable accuracy, which allows them to be alternatives when the conventional method is not affordable. The DTS data revealed that each well completion processes can be characterized by their own distinctive temperature anomaly patterns. During gravel packing, the sand progression was monitorable with clear step-like temperature change due to the thermal bridge effect of sand. The DTS data during the cementing operation, also, clearly showed the progression up of the cement slurry and the exothermic reaction associated with curing of cement. During gas lift operations, we could observe the effect of casing transition as well as typical highly oscillating thermal response to gas lifting.

DIGITAL OIL FIELDS - INTELLIGENT WELLS AND PLATFORMS

The demand for oil and gas at present is very huge across the globe. The forecast is that this demand is going to shoot-up only and it would be a huge burden on the Oil & Gas Operators to produce more and meet the demand. Most of the offshore platforms around the world are Normally Unmanned Installation (NUI) type with the sole purpose to produce the maximum from the reservoir and send the produce to onshore for processing. NUI philosophy is normally to have minimum facilities to reduce trips to the platforms due to HSE reasons and reduce cost of such trips. It is a huge challenge to sustain production at around the same rate as in the beginning and for a longer duration. Some of the major factors remain unknown if the wells are conventional type without any feedback mechanism. Intelligence added to the wells in offshore platforms do a lot of wonder. Operators get equipped with loads of information with which they can maximize the production, cut down on the water production, cut down on the volume of gas being used for gas lift process, reduce manual intervention, cut down on the risks involved in an offshore environment, reduce OPEX significantly etc. The CAPEX will obviously be higher compared to a traditional configuration, however, the benefits are aplen- ty in the long run.

Design and Economic Evaluation of the ESP and Gas Lift on the Dead Oil Well

Owing to the increasing water cut and decreasing in reservoir pressure of the well, the oil production of the well has seized and the well has become dead. This research study evaluates the implementation of the artificial lift methods ESP and Gas Lift- economically and technically on the well by using the production performance software (PROSPER) and economical yardsticks (NPV and ROI). The theory, design, production forecast, capital and operating expenditures of the electric submersible pump and gas lift are discussed for the appropriate selection of any of two options. The PROSPER software is used as the simulation tool for the design and production forecasting of the ESP and Gas Lift based. The ESP and Gas Lift methods have been simulated for the design and production forecast by entering the reservoir and completion inputs in the software. Subsequently, the software has been simulated to run on different sensitivities of the variables such as water cut, wellhead pressure setting depth, operating frequency and gas injection rates to check the production rates at different scenarios. Having performed the production performance simulation on the selected artificial lift methods, the methods have been investigated by capital budget-ing. In capital budgeting, the capital and operating expenditures of both lift methods were evaluated by determining their discounted value (NPV) and re-turn on investment (ROI). The prime objective of the research is to accomplish maximum production rates and profitability by selecting the most appropriate artificial lift method for the well; as a consequence it is concluded that the suitable artificial lift method for a well can be selected by applying the simulation and economical schemes.

Operational strategy of high rate anaerobic digester with mixed organic wastes: effect of co-digestion on biogas yield at full scale

ABSTRACTThe present research work is aimed at providing an economically feasible solution for the farmers to exploit the mixed organic wastes (MOW) as resources for the generation of biogas based electrical power and utilize the same for irrigation purpose to reduce the dependence on electricity board. A full scale biomethanation plant has been installed based on anaerobic gas lift reactor (AGR) technology to analyse, understand the operational parameters of anaerobic digestion and assess the performance of a high rate biomethanation plant by co-digesting the MOW such as poultry litter (PL), cattle manure (CM) and napier grass (NG) at ambient temperature. The biomethanation plant was incorporated with inline pre and post-processing unit assembly. The plant was fed with 1000 kg of MOW per day having 250 kg of total solids, about 178–200 kg of volatile solids and operated continuously for 52 weeks under ambient temperature. Electrical power generated (84.5–104 kWh/day) from biogas (65–80 m3/day) containing methane (40–48 m3/day) was used for operating the water pumps for agricultural purpose and the digestate (115–130 kg/day) was exploited as organic manure for growing crops in the same field. Napier grass was grown in the same land and other feedstocks were procured from the nearby area at the cost of $10–$15 per ton. Around 6 acres of land was being cultivated using the biogas based power generated from the MOW that was being used for growing vegetables and maize.