Low Well Cost: Effective Cost Optimisation for Marginal Green Field Development Using Fit-for-Purpose Well Design

2021 ◽  
Author(s):  
Thivyashini Thamilyanan ◽  
Hasmizah Bakar ◽  
Irzee Zawawi ◽  
Siti Aishah Mohd Hatta
Keyword(s):  
Cost Effective ◽  
Second Phase ◽  
Sand Production ◽  
Field Development ◽  
Well Completion ◽  
Artificial Lift ◽  
Sand Control ◽  
Fit For Purpose ◽  
Reservoir Connectivity ◽  
Gas Lift

Abstract During the low oil price era, the ability to deliver a small business investment yet high monetary gains was the epitome of success. A marginal field with its recent success of appraisal drilling which tested 3000bopd will add monetary value if it is commercialized as early as possible. However, given its marginal Stock Tank Oil Initially in Place (STOIIP), the plan to develop this field become a real challenge to the team to find a fit-for-purpose investment to maximize the project value. Luxuries such as sand control, artificial lift and frequent well intervention need to be considered for the most cost-effective measures throughout the life of field ‘Xion’. During field development study, several development strategies were proposed to overcome the given challenges such as uncertainty of reservoir connectivity, no gas lift supply, limited footprint to cater surface equipment and potential sand production. Oriented perforation, Insitu Gas Lift (IGL), Pressure Downhole Gauge (PDG), Critical Drawdown Pressure (CDP) monitoring is among the approaches used to manage the field challenges will be discussed in this paper. Since there are only two wells required to develop this field, a minimum intervention well is the best option to improve the project economics. This paper will discuss the method chosen to optimize the well and completion strategy cost so that it can overcome the challenges mentioned above in the most cost-effective approach. Artificial lift will utilize the shallower gas reservoirs through IGL in comparison to conventional gas lift. Sand Production monitoring will utilize the PDG by monitoring the CDP. The perforation strategy will employ the oriented perforation to reduce the sand free drawdown limit compare to the full perforation strategy. The strategy to monitor production through PDG will also reduce the number of interventions to acquire pressure data in establishing reservoir connectivity for the second phase development through secondary recovery and reservoir pressure maintenance plan. This paper will also explain the innovative approaches adopted for this early monetization and fast track project which is only completed within 4 months. This paper will give merit to petroleum engineers and well completion engineers involved in the development of marginal fields.

A geomechanical approach for sanding risk assessment applied to three field cases for completion optimisation

2010 ◽  
Vol 50 (1) ◽  
pp. 623 ◽  
Author(s):  
Khalil Rahman ◽  
Abbas Khaksar ◽  
Toby Kayes
Keyword(s):  
Decision Making ◽  
Petroleum Industry ◽  
Cost Effective ◽  
Development Planning ◽  
Control Measures ◽  
Sand Production ◽  
Field Development ◽  
Well Completion ◽  
Sand Control ◽  
Production Prediction

Mitigation of sand production is increasingly becoming an important and challenging issue in the petroleum industry. This is because the increasing demand for oil and gas resources is forcing the industry to expand its production operations in more challenging unconsolidated reservoir rocks and depleted sandstones with more complex well completion architecture. A sand production prediction study is now often an integral part of an overall field development planning study to see if and when sand production will be an issue over the life of the field. The appropriate type of sand control measures and a cost-effective sand management strategy are adopted for the field depending on timing and the severity of predicted sand production. This paper presents a geomechanical modelling approach that integrates production or flow tests history with information from drilling data, well logs and rock mechanics tests. The approach has been applied to three fields in the Australasia region, all with different geological settings. The studies resulted in recommendations for three different well completion and sand control approaches. This highlights that there is no unique solution for sand production problems, and that a robust geomechanical model is capable of finding a field-specific solution considering in-situ stresses, rock strength, well trajectory, reservoir depletion, drawdown and perforation strategy. The approach results in cost-effective decision making for appropriate well/perforation trajectory, completion type (e.g. cased hole, openhole or liner completion), drawdown control or delayed sand control installation. This type of timely decision making often turns what may be perceived as an economically marginal field development scenario into a profitable project. This paper presents three case studies to provide well engineers with guidelines to understanding the principles and overall workflow involved in sand production prediction and minimisation of sand production risk by optimising completion type.

Cable Thru Downhole Insert Safety Valve: A New Paradigm

2021 ◽  
Author(s):  
Kuswanto Kuswanto ◽  
Oka Fabian ◽  
Orient B Samuel ◽  
Mohd Yuzmanizeil B Yaakub ◽  
Chua Hing Leong ◽  
...  
Keyword(s):  
Safety Valve ◽  
Cost Effective ◽  
Submersible Pump ◽  
New Paradigm ◽  
Reservoir Properties ◽  
Technology Application ◽  
Artificial Lift ◽  
Water Cut ◽  
The Right ◽  
Gas Lift

Abstract The B Field is located in the South China Sea, about 45 KM offshore Sarawak, Malaysia, in a water depth approximately 230 ft. Its structure is generally regarded as a gentle rollover anticline with collapsed crest resulting from growth faulting. The reservoirs were deposited in a coastal to shallow marine with some channels observed. Multiple stacked reservoirs consist of a series of very thick stacked alternating sandstone and minor shale layers with differing reservoir properties. The shallow zones are unconsolidated, and the wells were completed with internal gravel packs. Wells in B Field mostly were completed in multi-layered reservoirs as dual strings with SSDs and meant to produce as a commingled production. The well BX is located within B Field and designed as oil producer well with a conventional tubing jointedElectrical Submersible Pump (ESP) system which was installed back in 2008. Refer to figure 1, the initial completion schematic is 3-1/2″ single string that consist of the single production packer, gas lift mandrel, tubing retrievable Surface Controlled Subsurface Safety Valve (SCSSV) and ESP. The production packers equipped with the feed thru design to accommodate the ESP cable and the gas vent valve as part of the ESP completion design. The gas lift mandrel was installed in the completion string as a backup artificial lift method to receive the gas lift and orifice valve in the event of the conventional ESP failed. Hence the well still able to produce by introducing the gas thru the annulus to activate the gas lift valve. Eventually throughout the end of the the field life, the well would depend on the ESP system for the primary lifting method due to gas lift depth limitation and the gas supply. The conventional ESP failed after seven years of operation which is above the average ESP lifetime. The well last produced at a flow rate with 28 % water cut, however the well is not at the end of the field life. Based on the economical study with the right technology and cost efficient approach, the well still economicaly profitable. The Thru Tubing (TT) ESP technology is approached as cost effective solution compare to fully well workover. Despite a couple of operational challenges, for example, setting the cable hanger, maintaining downhole barrier requirement, the Thru Tubing Electrical Submersible Pump Cable Deployed (TTESP CD) and Cable Thru Insert Safety Valve (CT-ISV) was successfully installed. Several post-installation findings have uncovered some problems which are requiring some additional technical and operation improvement for future similar applications. This paper will highlight the deployment of the Cable Thru Insert Safety Valve (CT-ISV) that was successfully installed as pilot, which is the first application in the world, and also highlights the success, lesson learnt and improvement for future requirement for the CT-ISV application as one of the solution for retrofitting completion application without jeopardizing the well integrity. This achievement is collaboration between Company and service partner as the technology and deployment under the proprietary scope. Further technology application, the replication of this insert safety valve was conducted and successfully deployed on other three wells.

Artificial Lift Optimization for Shallow Carbonate Magwa and Ostracod Formations with Massive Propped Fractures

2021 ◽  
Author(s):  
Nasser AlAskari ◽  
Muhamad Zaki ◽  
Ahmed AlJanahi ◽  
Hamed AlGhadhban ◽  
Eyad Ali ◽  
...  
Keyword(s):  
Production Performance ◽  
Shallow Depth ◽  
Production Rates ◽  
Field Development ◽  
Artificial Lift ◽  
Geological Conditions ◽  
Fracture Fluid ◽  
Reservoir Potential ◽  
Gas Lift

Abstract Objectives/Scope: The Magwa and Ostracod formations are tight and highly fractured carbonate reservoirs. At shallow depth (1600-1800 ft) and low stresses, wide, long and conductive propped fracture has proven to be the most effective stimulation technique for production enhancement. However, optimizing flow of the medium viscosity oil (17-27 API gravity) was a challenge both at initial phase (fracture fluid recovery and proppant flowback risks) and long-term (depletion, increasing water cut, emulsion tendency). Methods, Procedures, Process: Historically, due to shallow depth, low reservoir pressure and low GOR, the optimum artificial lift method for the wells completed in the Magwa and Ostracod reservoirs was always sucker-rod pumps (SRP) with more than 300 wells completed to date. In 2019 a pilot re-development project was initiated to unlock reservoir potential and enhance productivity by introducing a massive high-volume propped fracturing stimulation that increased production rates by several folds. Consequently, initial production rates and drawdown had to be modelled to ensure proppant pack stability. Long-term artificial lift (AL) design was optimized using developed workflow based on reservoir modelling, available post-fracturing well testing data and production history match. Results, Observations, Conclusions: Initial production results, in 16 vertical and slanted wells, were encouraging with an average 90 days production 4 to 8 times higher than of existing wells. However, the initial high gas volume and pressure is not favourable for SRP. In order to manage this, flexible AL approach was taken. Gas lift was preferred in the beginning and once the production falls below pre-defined PI and GOR, a conversion to SRP was done. Gas lift proved advantageous in handling solids such as residual proppant and in making sure that the well is free of solids before installing the pump. Continuous gas lift regime adjustments were taken to maximize drawdown. Periodical FBHP surveys were performed to calibrate the single well model for nodal analysis. However, there limitations were present in terms of maximizing the drawdown on one side and the high potential of forming GL induced emulsion on the other side. Horizontal wells with multi-stage fracturing are common field development method for such tight formations. However, in geological conditions of shallow and low temperature environment it represented a significant challenge to achieve fast and sufficient fracture fluid recovery by volume from multiple fractures without deteriorating the proppant pack stability. This paper outlines local solutions and a tailored workflow that were taken to optimize the production performance and give the brown field a second chance. Novel/Additive Information: Overcoming the different production challenges through AL is one of the keys to unlock the reservoir potential for full field re-development. The Magwa and Ostracod formations are unique for stimulation applications for shallow depth and range of reservoirs and fracture related uncertainties. An agile and flexible approach to AL allowed achieving the full technical potential of the wells and converted the project to a field development phase. The lessons learnt and resulting workflow demonstrate significant value in growing AL projects in tight and shallow formations globally.

Implications of accurate geomechanical modelling and systematic core testing for sanding evaluation and sand control decisions – a case study from Perth Basin

2020 ◽  
Vol 60 (1) ◽  
pp. 267
Author(s):  
Sadegh Asadi ◽  
Abbas Khaksar ◽  
Mark Fabian ◽  
Roger Xiang ◽  
David N. Dewhurst ◽  
...  
Keyword(s):  
Management Strategies ◽  
Mechanical Tests ◽  
Well Test ◽  
Sand Production ◽  
Gas Field ◽  
Stress Regime ◽  
Full Field ◽  
Field Development ◽  
Sand Control ◽  
Rock Mechanical Properties

Accurate knowledge of in-situ stresses and rock mechanical properties are required for a reliable sanding risk evaluation. This paper shows an example, from the Waitsia Gas Field in the northern Perth Basin, where a robust well centric geomechanical model is calibrated with field data and laboratory rock mechanical tests. The analysis revealed subtle variations from the regional stress regime for the target reservoir with significant implications for sanding tendency and sand management strategies. An initial evaluation using a non-calibrated stress model indicated low sanding risks under both initial and depleted pressure conditions. However, the revised sanding evaluation calibrated with well test observations indicated considerable sanding risk after 500 psi of pressure depletion. The sanding rate is expected to increase with further depletion, requiring well intervention for existing producers and active sand control for newly drilled wells that are cased and perforated. This analysis indicated negligible field life sanding risk for vertical and low-angle wells if completed open hole. The results are used for sand management in existing wells and completion decisions for future wells. A combination of passive surface handling and downhole sand control methods are considered on a well-by-well basis. Existing producers are currently monitored for sand production using acoustic detectors. For full field development, sand catchers will also be installed as required to ensure sand production is quantified and managed.

Sand Handling Solutions Through the Use of Low Geometric Index Progressing Cavity Pumps, La Hocha Field, Colombia

2021 ◽  
Author(s):  
Jorge Alberto Martinez Lozano ◽  
Ediberto Cruz Torres ◽  
Nadia Maoly Hernandez Castro ◽  
Jorge Alberto Coronel Avila ◽  
Tim Soltys ◽  
...  
Keyword(s):  
Oil And Gas ◽  
High Efficiency ◽  
Cost Effective ◽  
Helix Angle ◽  
Field Application ◽  
Sand Production ◽  
Cross Sectional ◽  
Positive Displacement ◽  
Geometry Design ◽  
Artificial Lift

Abstract A solution for extend run life with no intervention in a high sand cut and high viscous fluid application for La Hocha field (Huila, Colombia) is presented through the installation of Progressing Cavity Pumps (PCP) designed with aggressive geometries including low rotor swept angle and minimum geometry index concepts. This application has 100-300 BFPD flow rate, sand cut up to 40%, 16°API fluid and 850 cp @ 100°F. This document shows the methodology applied in the selection of well candidates with high frequency of interventions due pump failures associated to sand production and well sanded. The effect of the PCP geometry design, cross sectional area, pitch length, helix angle, pump fit, and elastomer were evaluated consistently as selection criteria in order to verify their impact on PCP run life for sand production applications. The document aims to validate the PCP theoretical design principles with the statistic and results gathered from field during the past 3 years in La Hocha field application. The "Fat Boy project" resulted in less intervention, well services, minimizing production delays and associated costs. The project started on mid-2012, due to successful results has been expanded and nowadays represents the 85 percent of the wells in La Hocha field. This is all part of a combined effort looking for reliable and cost-effective solutions for challenging applications. Progressing Cavity Pumps are used in a variety of oil and gas applications where their beneficial characteristics such as positive displacement, high efficiency, low internal shear rates and pulseless flow provide advantages over other artificial lift systems. PC pumps are available in several geometries which determine their suitability for specific applications assuring optimal performance and extended run life.

Sand Production Management

1999 ◽  
Vol 122 (1) ◽  
pp. 29-33 ◽  
Author(s):  
Mamdouh M. Salama
Keyword(s):  
Flow Rate ◽  
Production Management ◽  
Input Parameter ◽  
Cost Effective ◽  
Sand Production ◽  
Sand Erosion ◽  
Sand Control ◽  
Important Input ◽  
Control Procedures ◽  
Critical Components

Sand production may be inevitable in many fields that have a relatively low formation strength. Sand erosion and settling predictions and sand monitoring are important elements of any effective sand production management strategy. Sand erosion predictions are used to establish tolerable sand production rates, and, thus, well productivity, and to develop cost-effective inspection frequency for critical components. Prediction of critical flow rate to prevent sand settling is important for flowlines that are not designed for pigging. Quantitative sand monitoring is essential in verifying the effectiveness of sand control procedures and in generating an important input parameter for erosion and sand settling predictions. This paper presents equations for predicting sand erosion rate and sand settling flow rate, and assesses the accuracy of these equations. In addition, the paper presents an assessment of the sensitivity of commercially available nonintrusive acoustic and intrusive electrical resistance sand monitors. [S0195-0738(00)00201-6]

Auto-Gas Lift and Smart Well Completion Challenges to Extend Well Life and Running Toward Cost Effective Program, Field Case Study

2015 ◽  
Author(s):  
Abdalla Elbarbary ◽  
Gehad Mahmoud ◽  
Abdulraman Bahrom ◽  
Mohamed El Gebaly ◽  
Zeid Mohamed ◽  
...  
Keyword(s):  
Cost Effective ◽  
Field Case ◽  
Well Completion ◽  
Effective Program ◽  
Gas Lift

Value of Managing the Subsurface Risks and Uncertainties in the Project Execution; A Successful Case History in Merakes Green Gas Field Development

2021 ◽  
Author(s):  
Dian Kurniawan ◽  
Gabriela Carrasquero ◽  
Edo Richardo Daniel ◽  
Kurnia Wirya Praja ◽  
Elisa Spelta ◽  
...  
Keyword(s):  
Data Acquisition ◽  
Reservoir Characterization ◽  
Quantitative Description ◽  
Mitigation Strategies ◽  
Sand Production ◽  
Gas Field ◽  
Field Development ◽  
Extensive Evaluation ◽  
Sand Control ◽  
The Way

Abstract Implementing a proactive approach with comprehensive reservoir characterization, risks identification and mitigation are key elements that have to be deeply investigated before the project execution for achieving the optimum results in field development. A tremendous result on the seismic driven field development and synergy with a fast track development concept in Merakes green gas field has been achieved. In this paper, the conceptual and methodologies are described in the way of managing the subsurface risks and uncertainties during the planning and execution phase. A suitable example in Merakes field development which classified as "appraisal while developing", since the remaining risks still exist during development campaign, is presented. By having only two exploration wells with limited data, a robust upfront reservoir characterization and modeling were quite challenging to provide a reliable image of the subsurface condition. The enhancement on the way of constructing an integrated reservoir study prior to the field development is considered an essential requirement that has to be done before the project execution. A comprehensive approach that maximizes the integration of Geology, Geophysics and Reservoir Engineering disciplines and brings out the reservoir risk quantification has been considered as a basis and strategic driver for both subsurface quantitative description and de-risking of development wells locations. Focusing on the subsurface risk criticality, the compartmentalization, rock facies quality, gas-water contact depth and sand production were considered as the main critical aspects that could impact the final success. Preserving mitigation strategies and adapting development flexibility concept have been prepared to overcome such subsurface unexpected conditions. A description of the well placement strategy which widely open to be optimized during the drilling campaign was allowed and brought benefits in mitigating the compartmentalization risk. The readiness of an adequate and comprehensive data acquisition program including log data acquisition, coring and well testing in the development wells has been prepared. Moreover, a sidetrack contingency plan has been also considered for a key-well in case of worse than expected results. With know-how and experiences on the nearby field development, an extensive evaluation of water and sand production risks was derisked by selecting smart completion and sand control technologies. A holistic integration between subsurface, drilling, petroleum, facilities disciplines is considered of paramount importance in development projects. The awareness of the field's risks and uncertainties allows maximizing efforts in following up the drilling phase promptly adapting the data acquisition plan to the effective level of residual uncertainty and related development risk. Eventually the good match between the expected scenario and the actual well results allowed to cancel most of the costly data acquisition plans which contributed to a positive impact on the project cost and time-saving.

Imperatives for Implementing Gas-Lifting for Fields with Sand Control: OT Field Experience

2021 ◽  
Author(s):  
Kingsley Iheajemu ◽  
Erasmus Nnanna ◽  
Somtochukwu Odumodu
Keyword(s):  
Control Mechanism ◽  
The Other ◽  
Control Mechanisms ◽  
Sand Production ◽  
Stable Production ◽  
Sand Control ◽  
Open Hole ◽  
Gravel Pack ◽  
Production Problems ◽  
Gas Lift

Abstract Unconsolidated sandstone formations are normally completed with one form of sand control or the other. The aim is to manage sand production as low as reasonably practicable and protect well and surface equipment from possible loss of containment. There are about 8 broad types of sand control namely; internal gravel pack, external gravel pack, chemical sand consolidation (SCON), open-hole expandable sand screen, cased-hole expandable sand screen, stand-alone screen, pre-packed screen and frac & pack. Gas-lifting targets to increase pressure drawdown required for wells to produce by injecting gas at a pre-determined depth using gas-lift valves installed in the tubing. Whereas gas-lift design targets to optimize the gas-lift injection to ensure stable production, the associated drawdown may challenge the operating envelope of the sand control mechanism in place. The OT field has been in production for about 50 years and has been on gas-lift for about 20 years. There have also been occasional sand production problems in the field; some of which occur in gas-lifted wells. This paper will highlight the outcome of a study that investigated the performance of various sand control mechanisms under gas-lift production and present observed trends to serve as guide in maximizing the performance of such gas-lifted wells with sand control mechanism.

First Successful Application of Digital Intelligent Artificial Lift DIAL System in Dual Strings in B Field Applying Lessons Learnt from its First Pilot Application in Different Field in Same Offshore Malaysia

2021 ◽  
Author(s):  
Suman Kumar ◽  
Mohamad Sazwan Ismail ◽  
Nurfarah Izwana Salleh ◽  
Amirul Adha Amsidom ◽  
M Haziq M Ghazali ◽  
...  
Keyword(s):  
Risk Assessment ◽  
Failure Analysis ◽  
Electrical Signal ◽  
Learning Curves ◽  
Well Completion ◽  
Scope Test ◽  
Lessons Learnt ◽  
Artificial Lift ◽  
The World ◽  
Gas Lift

Abstract There are five wells planned to be drilled in B field infill campaign starting Q3 2020 - Q1 2021 as per development plan. Two wells are planned to be installed with Digital Intelligent Artificial Lift (DIAL) system, which one in single string completion and another one in dual string completion. This paper will mainly describe on the DIAL application in dual strings completion in B field. The DIAL system has circumferential 3 active orifice valves to open/ close selectively or in combination, which is communicated and operated through TEC cable from surface remotely. Given that this will be the second DIAL system installation in the world, a back up gas lift mandrel (GLM) will be installed to mitigate the risk in case the DIAL system fails to work due to any unprecedented reason so that conventional gas lift valve can be installed in GLM and gas lift operations can be commensed. The world's first DIAL installation in dual strings was completed in a different field offshore Malaysia in Q2 2020. During well completion and system installation, all the DIAL units in short string were functioning well, however there were some issues initially observed in Continuity Resistance (CR) inconsistent reading during run in hole completion and then total failure was observed in long string after its installation based on CR test, TDR (Time Domain Refractometer) test, and Scope Test due to unprecedented technical issue which affected the downhole cable to receive and send electrical signal to operate DIAL valves. The risk assessment has been conducted with associated parties based on the failure analysis and lessons learnt from the first DIAL application in dual strings in order to implement mitigation plan and proceed with DIAL application in B field. This step is very crucial to build the learning curves as well as improve the operator's understanding on for future DIAL application in dual strings. This paper will summarize the DIAL tool functionality and its design, failure analysis & lessons learnt from other field offshore Malaysia, and risk assessment & mitigation plan carried out for the DIAL application in dual strings in B field. It marks the second application in the world at present & first successful DIAL application in dual strings worldwide presently.

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