Lesson Learnt from First Application of Openhole Stand-Alone Screen OHSAS with Autonomous Inflow Control Devices AICD in Oilfield Offshore East Malaysia

2021 ◽  
Author(s):  
Catherine, Ye Tang ◽  
Kok Liang Tan ◽  
Latief Riyanto ◽  
Fuziana Tusimin ◽  
Nik Fazril Sapian ◽  
...  
Keyword(s):  
Production Rate ◽  
Gas Injection ◽  
Water Injection ◽  
Well Test ◽  
Sand Production ◽  
Natural Sand ◽  
Monitoring Method ◽  
Wellhead Pressure ◽  
Root Cause ◽  
Oil Rim

Abstract Well#1 was completed as horizontal oil producer with Openhole Stand-Alone Sandscreens (OHSAS) across a thin reservoir with average thickness of 20ft in Field B. The first Autonomous Inflow Control Device (AICD) in PETRONAS was installed to ensure balanced contribution across horizontal zones with permeability contrasts and to prevent early water and gas breakthrough. Integrated real-time reservoir mapping-while-drilling technology for well placement optimization combined with industry-leading inflow control simulator for AICD placement were opted. The early well tests post drilling showed promising results with production rate doubled the expected rate with no sand production, low water cut and lower Gas to Oil Ratio (GOR). Reservoir Management Plan (RMP) for this oil rim requires continuous gas injection into gas cap and water injection into aquifer. However, due to low gas injection uptime caused by prolonged injection facilities constraints, the well's watercut continued to increase steadily from 0% to 80% within a year of production despite prudent surveillance and controlling of production during injector's downtime. After the gas injection performance has improved, the well was beaned up as part of oil rim management for withdrawal balancing. Unfortunately, a month later, the production rate showed a sudden spike with significantly low wellhead pressure, followed by hairline leak on its choke valve and leak at Crude Oil Transfer Pump (COTP) recycle line. Sand analysis by particle size distribution (PSD) confirmed OHSAS failure, while the high gas rate from well test results confirmed AICD failure. A multidisciplinary investigation team was immediately formed to determine the root cause of the failure event. Root Cause Failure Analysis (RCFA) method was opted to determine the causes of failures, including the reanalyzing of the OHSAS and AICD completion design. The well operating strategy was also reviewed thoroughly by utilizing the well parameters trending provided in the Exceptional Based Surveillance (EBS) Process Information (PI) ProcessBook. Thorough RCFA concluded that frequent platform interruptions and improper well start-up practices have created abrupt pressure changes in the wellbore, which has likely destabilized the natural sand pack around the OHSAS and created frequent burst of sand influx across AICDs. The operating of a high gas-oil ratio (GOR) and high watercut sand prone well without pre-determined AICD sand erosion toleration envelope have also likely contributed to the failure of AICDs. The delay in detection of OHSAS failure in Well#1 due to ineffective sand monitoring method thus resulted in severe sand production which caused severe leak at its choke valve and COTP recycle line.

Optimized Reservoir Development With High-Angle Wells, El Furrial Field, Venezuela

2001 ◽  
Vol 4 (01) ◽  
pp. 26-35
Author(s):  
Richard W. Smith ◽  
Rodolfo Colmenares ◽  
Eulalio Rosas ◽  
Isaura Echeverria
Keyword(s):  
High Pressure ◽  
Production Rate ◽  
Gas Injection ◽  
Water Injection ◽  
Full Scale ◽  
Modeling Technique ◽  
High Angle ◽  
Reservoir Model ◽  
Full Field ◽  
Field Development

Summary The El Furrial field is one of Venezuela's major field assets and is operated by PDVSA (Petroleos de Venezuela, S.A.), the national oil company. Its current production of more than 450,000 BOPD makes it a giant oil field. Development of the field, which has an average reservoir depth of approximately 15,000 ft, is in its mature stages owing to implementation of high-pressure gas injection. PDVSA has consistently followed a forward planning approach related to reservoir management. Using high-angle deviation drilling techniques allows development wells to be strategically located by penetrating the reservoir at high angles to optimize production rate, extend well life, increase reserves per well, reduce operating expenses, and reduce total field development costs. A reservoir model was constructed and simulated with detailed reservoir stratigraphy to determine realistic potential of high-angle wells (HAW's). Five wells had been drilled as of June 2000, and the first four wells have proved the effectiveness of the design. The philosophy, modeling technique, well design considerations, problems encountered, well results, and economic criteria provide a clear understanding of the risk of this technology not previously used at this depth in Venezuela. The result was the first HAW in the deep, challenging environment of eastern Venezuela. Results show that optimization objectives can be attained with HAW's, mainly increasing per-well production rate, maximizing per-well recovery, and extending the breakthrough time of gas or water from pressure maintenance and enhanced oil recovery projects. Well results indicate that the geological and simulation modeling technique is reliable and accurate. A pilot program shows that HAW technology provides major advantages to increase production rate and reduce the overall number of wells needed to reach production objectives. However, the project also has experienced a number of unexpected drilling problems.1 The costs associated with the total project are significant, but more importantly, this program becomes very attractive because of the long-term benefits of decreased water-cut related to current water injection; decreased gas breakthrough owing to high-pressure gas injection, and fewer wells required to meet production goals. Technical contributions include the following:The modeling technique of applying detailed stratigraphy to a full-scale reservoir model is accurate if performed with the appropriate objectives in mind.The application of state-of-the-art drilling techniques to attain high angles at deep drilling depth is possible; however, drilling problems caused by formation instability require more study and experience.This method can be applied to other fields in the eastern Venezuelan basin currently under, or planned to be under, enhanced recovery programs and development programs. Introduction The El Furrial field is one of several giant fields found northwest of Maturin, Venezuela, in what is described as the El Furrial thrust trend (location shown in Fig. 1). The field was discovered in 1986 with the FUL-1 well, which established production from the Naricual formation. A late 1996 study, using a full-field simulation model of the El Furrial field, showed that problems associated with gas or water breakthrough in producing wells from high-pressure gas injection and water injection can be reduced with this technology. The potential to reduce problems comes from drilling infill wells at a high angle between the advancing gas and water fronts. High-pressure gas injection was started in 1998 and was justified, in part, by this work and other associated studies. The field produces from two formations, the Naricual and Los Jabillos, giving a total gross thickness of more than 1,500 ft. The primary 1,200-ft-thick Naricual formation is divided into three major stratigraphic sequences - the Superior (upper), Medio (middle), and Inferior (lower). Net-to-gross ratio is typically 80%. Philosophy PDVSA has consistently maintained reservoir models through the years to aid in reservoir management.2 To date, eight full-field and numerous sector-simulation models have been built. Optimization of the field began in 1996. During the study, it was noted that predictions of conventional vertical infill wells drilled into the structure had short production lives because of water or gas breakthrough. The review identified the possibility of placing well trajectories between the advancing water and gas fronts. One benefit was that the production rate from new wells could be increased; this indicated that the number of development wells could be reduced, saving investment costs. Thus, the following objectives were determined.Define optimization alternatives of the El Furrial field well-development scheme. The use of nonconventional well completions such as vertical large interval single completions (LISC) and high-angle completion (HAC) wells may present a higher potential for meeting production needs at a lower total development cost.Define the most reasonable completion configuration for new wells in El Furrial field. It is probable that the entire Naricual acts as a single reservoir unit, with at least partial vertical communication existing in the majority of the field caused by fault juxtaposition and limited fractures associated with faults. Therefore, single completions in all of Naricual Superior and Medio, or Naricual Medio and Inferior, may present viable completion alternatives.Provide technical support to the Venezuelan Ministry of Mines and Energy, which approves operation philosophy, development, and completion practices. The HAW program was different from the previous accepted philosophy, so technical support was necessary to permit the FUL-63 pilot test well. High-Angle Wells This work was split into two parts. The first was an evaluation of HAC wells as an alternative to current vertical-well strategies. This includes the possible alternative of LISC completions for all of Naricual Superior and Medio. The second was additional simulation cases to test the potential development plan with only HAC wells in a full-scale reservoir model.

scholarly journals Multi-Objective Gas Lift Optimization using Elitist Non-Dominated Sorting Genetic Algorithm (NSGA-II)

2019 ◽  
Vol 8 (4) ◽  
pp. 9737-9740
Keyword(s):  
Production Rate ◽  
Production Cost ◽  
Gas Injection ◽  
Oil Production ◽  
Injection Rate ◽  
Nsga Ii ◽  
Wellhead Pressure ◽  
Multi Objective ◽  
The Cost ◽  
Gas Lift

In petroleum industry, gas lift optimization is the most important for evaluating the reservoir. By improving the gas lift operation we can save money and time which we spend on the reservoir for effective production. The mainly accepted scenario of gas lift is to maximize production by using minimized cost infrastructure. If the production rate is increased, then the cost of oil production also increases due to the increase in surface facilities and increase in cost of gas compression to higher pressures. The production rate and production cost during gas lift are mutually conflicting in nature i.e., if anyone desires to increase the oil production rate, then at the same time it is difficult to minimize the cost of production. Therefore, this is an ideal candidate for multi-objective optimization study, where production rate needs to maximized while minimizing the cost of production. The oil production rate is calculated using nodal analysis of inflow performance and outflow performance curve while the production cost is calculated using the brake horsepower requirement of the compressor. Oil production rate during a gas lift operation can be defined as a function of various factors like (i) depth of gas injection, (ii) gas injection rate (iii) gas lift injection pressure, (iv) wellhead pressures, (v) bottom hole pressure, (vi) tubing size, (vii) surface choke size/wellhead pressure. Production cost mainly depends on the cost of gas compression which further depends on the pressure up to which gas has to be compressed in the annulus so that the gas lift valve at the bottom of the well opens. The opening of gas lift valve depends on the bottom hole pressure in the tubing i.e. the density of mixture present inside the tubing. The multi-objective gas lift optimization is carried out using multi-objective evolutionary algorithms (EAs) that use non-dominated sorting called elitist non-dominated sorting genetic algorithm (NSGA-II). In this project, we aim to find the optimum values of the decision parameters i.e. gas injection rate and wellhead pressure, for which oil production rate would be maximized while minimizing the cost of oil production.

A New Method of Fall-Off Test in Water Injection Well in Tahe Oilfield

2013 ◽  
Vol 807-809 ◽  
pp. 2508-2513
Author(s):  
Qiang Wang ◽  
Wan Long Huang ◽  
Hai Min Xu
Keyword(s):  
Water Injection ◽  
Injection Well ◽  
Well Test ◽  
Well Bore ◽  
Residual Oil ◽  
Injection Wells ◽  
Oil Saturation ◽  
Tahe Oilfield ◽  
Fitting Method ◽  
Front Radius

In pressure drop well test of the clasolite water injection well of Tahe oilfield, through nonlinear automatic fitting method in the multi-complex reservoir mode for water injection wells, we got layer permeability, skin factor, well bore storage coefficient and flood front radius, and then we calculated the residual oil saturation distribution. Through the examples of the four wells of Tahe oilfield analyzed by our software, we found that the method is one of the most powerful analysis tools.

Transforming Water Injection Process With Real Time Automation

2021 ◽  
Author(s):  
Muhammad Zakwan Mohd Sahak ◽  
Eugene Castillano ◽  
Tengku Amansyah Tuan Mat ◽  
Maung Maung Myo Thant
Keyword(s):  
Oil Recovery ◽  
Capital Investment ◽  
Water Injection ◽  
Optimal Operation ◽  
Near Miss ◽  
Injection System ◽  
Injection Technique ◽  
Manual Operation ◽  
Injection Process ◽  
Oil Rim

Abstract For mature fields, water injection is one of the widely deployed techniques to ensure continuous oil recovery from the reservoir by maintaining the reservoir pressure, oil rim and pushing the oil from injection to production wells. Thus, it is critical to ensure a continuous and reliable operation of water injection to have consistent and sustainable rate. This paper demonstrates the new approach, utilizing automation and digital technology providing operational improvement and reduction in unplanned production deferment (UPD). One of the methods to effectively manage the water injection operation is via automation of injection process, especially since most of the water injection facilities still rely heavily on manual operation. First, a discussion on typical water injection technique is discussed. Challenges and sub-optimal operation of water injection processes within the company and industry are analysed. Then, the designing of a fully automated water injection system, such as equipment availability and constraints in matching and responding to well injection requirement are demonstrated. While an immediate adoption of process automation to mature assets may be faced with challenges such as system readiness, hardware availability, capital investment and mindset change, a step-by-step approach such as guided operation and semi-auto operation is explored as preparation prior to a full automation roll-out. With the shift from manual operation reliance to automation, the response time to process changes is improved leading to reduction in near-miss and trip cases, and minimum unplanned deferment.

scholarly journals Sensor-Based Safety Performance Assessment of Individual Construction Workers

Sensors ◽  
2018 ◽  
Vol 18 (11) ◽  
pp. 3897 ◽  
Author(s):  
JeeWoong Park ◽  
Yong K. Cho ◽  
Ali Khodabandelu
Keyword(s):  
Risk Model ◽  
Tracking System ◽  
Field Tests ◽  
Safety Performance ◽  
Worker Safety ◽  
Well Test ◽  
Construction Sites ◽  
Monitoring Method ◽  
Safety Issues ◽  
Automated Method

Over the last decade, researchers have explored various technologies and methodologies to enhance worker safety at construction sites. The use of advanced sensing technologies mainly has focused on detecting and warning about safety issues by directly relying on the detection capabilities of these technologies. Until now, very little research has explored methods to quantitatively assess individual workers’ safety performance. For this, this study uses a tracking system to collect and use individuals’ location data in the proposed safety framework. A computational and analytical procedure/model was developed to quantify the safety performance of individual workers beyond detection and warning. The framework defines parameters for zone-based safety risks and establishes a zone-based safety risk model to quantify potential risks to workers. To demonstrate the model of safety analysis, the study conducted field tests at different construction sites, using various interaction scenarios. Probabilistic evaluation showed a slight underestimation and overestimation in certain cases; however, the model represented the overall safety performance of a subject quite well. Test results showed clear evidence of the model’s ability to capture safety conditions of workers in pre-identified hazard zones. The developed approach presents a way to provide visualized and quantified information as a form of safety index, which has not been available in the industry. In addition, such an automated method may present a suitable safety monitoring method that can eliminate human deployment that is expensive, error-prone, and time-consuming.

Study of Sand Production Using Geomechanical and Hydro-Mechanical Models

2018 ◽  
Vol 876 ◽  
pp. 181-186
Author(s):  
Son Tung Pham
Keyword(s):  
Production Rate ◽  
Mechanical Model ◽  
Failure Criteria ◽  
Sand Production ◽  
Geomechanical Model ◽  
Strength Failure ◽  
Rate Versus ◽  
Mechanical Models ◽  
Rock Mechanical Properties ◽  
Bottomhole Pressure

Sand production is a complicated physical process depending on rock mechanical properties and flow of fluid in the reservoir. When it comes to sand production phenomenon, many researchers applied the Geomechanical model to predict the pressure for the onset of sand production in the reservoir. However, the mass of produced sand is difficult to determine due to the complexity of rock behavior as well as fluid behavior in porous media. In order to solve this problem, there are some Hydro – Mechanical models that can evaluate sand production rate. As these models require input parameters obtained by core analysis and use a large empirical correlation, they are still not used popularly because of the diversity of reservoirs behavior in the world. In addition, the reliability of these models is still in question because no comparison between these empirical models has been studied. The onset of sand production is estimated using the bottomhole pressure that makes the maximum effective tangential compressive stress equal or higher than the rock strength (failure criteria), which is usually known as critical bottomhole pressure (CBHP). Combining with Hydro – Mechanical model, the main objective of this work aims to develop a numerical model that can solve the complexity of the governing equations relating to sand production. The outcome of this study depicts sand production rate versus time as well as the change of porosity versus space and time. In this paper, the Geomechanical model coupled with Hydro – Mechanical model is applied to calibrate the empirical parameters.

scholarly journals Investigation of Oil Recovery in Fractured Carbonate Rock by

2016 ◽  
Vol 6 (1) ◽  
pp. 14
Author(s):  
H. Karimaie ◽  
O. Torsæter
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Co2 Injection ◽  
Recovery Method ◽  
Asmari Limestone ◽  
Fractured Carbonate ◽  
Efficient Recovery ◽  
Live Oil ◽  
Non Equilibrium

The purpose of the three experiments described in this paper is to investigate the efficiency of secondary andtertiary gas injection in fractured carbonate reservoirs, focusing on the effect of equilibrium gas,re-pressurization and non-equilibrium gas. A weakly water-wet sample from Asmari limestone which is the mainoil producing formation in Iran, was placed vertically in a specially designed core holder surrounded withfracture. The unique feature of the apparatus used in the experiment, is the capability of initializing the samplewith live oil to obtain a homogeneous saturation and create the fracture around it by using a special alloy whichis easily meltable. After initializing the sample, the alloy can be drained from the bottom of the modified coreholder and create the fracture which is filled with live oil and surrounded the sample. Pressure and temperaturewere selected in the experiments to give proper interfacial tensions which have been measured experimentally.Series of secondary and tertiary gas injection were carried out using equilibrium and non-equilibrium gas.Experiments have been performed at different pressures and effect of reduction of interfacial tension werechecked by re-pressurization process. The experiments showed little oil recovery due to water injection whilesignificant amount of oil has been produced due to equilibrium gas injection and re-pressurization. Results alsoreveal that CO2 injection is a very efficient recovery method while injection of C1 can also improve the oilrecovery.

scholarly journals Optimasi Intermittent Gas lift Pada Sumur AB-1 Lapangan Brownfield

2018 ◽  
Vol 2 (1) ◽  
pp. 32
Author(s):  
Mia Ferian Helmy
Keyword(s):  
Pressure Gradient ◽  
Production Rate ◽  
Flow Rate ◽  
Oil Recovery ◽  
Gas Injection ◽  
Production Method ◽  
Production Flow ◽  
Injection Volume ◽  
Artificial Lift ◽  
Gas Lift

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%.

Resin Squeeze Operation to Successfully Seal Micro-Channels and Eliminate Sustained Casing Pressure of a Sour Gas Well

2021 ◽  
Author(s):  
Ying Wang ◽  
Xin Zheng ◽  
Li Li ◽  
Jianbo Yuan ◽  
Minh Vo ◽  
...  
Keyword(s):  
Good Condition ◽  
Water Injection ◽  
Injection Rate ◽  
Gas Well ◽  
Wellhead Pressure ◽  
Low Viscosity ◽  
Resin Injection ◽  
Micro Channels ◽  
Sustained Casing Pressure ◽  
Sour Gas

Abstract This paper describes the successful resin squeeze operation to seal off a micro-annulus between the 7" and 9-5/8" casings on a sour gas well located in Sichuan Basin, China. Integrated plug and abandonment were also essential to eliminate the risk of potential H2S exposure presented to the residents around this area. Resin, as a new alternative sealing technology, was technically evaluated, laboratory tested, and then chosen for squeezing into a micro-annulus to stop gas migration for its solids-free and low-viscosity properties compared to a conventional cement. The squeeze job was designed by taking the casing yield strength as the pressure limit (Confirmed by caliper log the casing was in good condition) and determining the resin pumping volume based on estimated resin squeeze volume and the remaining resin plug length. A "Braden-head" squeeze method was selected considering the low injection rate observed during the water injection test. Both stage-up and stage down squeezing techniques (hesitation squeeze of increasing and decreasing wellhead pressure stage by stage) were performed to maximize the injected volume of the resin sealant. A total of 800 L of 9.16 lb/gal resin was placed into a 4 ft milled interval, and 50 L were successfully squeezed into the 7" × 9-5/8" casing annulus. An operational learning was that resin injection is greatly improved during the stage-down process while keeping the casing annulus open. Evidence that the micro-annulus leak path had been sealed was an observation of 0 psi on the 7" × 9-5/8" casing annulus after resin fully set. The method of locating the optimal spot to squeeze resin involved noise logging to analyze for a potential gas source in the annulus. The post job results confirmed that resin acts effectively as an annular barrier in the repair of gas leaks in the small volume situations where micro-annulus exists in the cement sheath. For large voids such as inside 7" casing, a combination of cement plug plus mechanical barrier is recommended to be placed directly above resin plugs to complete permanent plug and abandonment of the wellbore.

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