ESPCP - An Economic Artificial Lift Method for an Offshore Field in Southwest Trinidad

2021 ◽  
Author(s):  
Nigel Ramkhalawan ◽  
Hamid Hassanali
Keyword(s):  
Operating Cost ◽  
Oil Price ◽  
Well Performance ◽  
Economic Success ◽  
Industry Standard ◽  
Recoverable Reserves ◽  
Artificial Lift ◽  
Actual Field ◽  
Project Life ◽  
Offshore Field

Abstract Frequent rod failures still occur in Progressive Cavity Pumped (PCP) wells with high dog-leg severities although they are fitted with adequate rod centralization. This results in well downtime and production deferrals. Offshore workovers are expensive and significantly affect operating cost (OPEX) of the operator. This study sought to evaluate the potential benefits of Electrica l Submersible Progressive Cavity Pumps (ESPCP) as an economic alternative for highly deviated wells in the offshore field in Trinidad. In this theoretical study, a screening criterion was established and four (4) candidates, all produced by surface driven PCPs, were selected. Models of ESPCP systems were developed using industry standard Progressive Cavity Pump software, parameters from the original PCP models as well as actual field well tests and production data. An economic evaluation, which integrated oil price and production rate sensitivities, was conducted using field data, including field reservoir characteristics and past well performance. The ESPCP model results suggest a cumulative increase of 567 BOPD is expected for all four wells. Using an oil price of US $45 per barrel, the analysis was conducted on all wells targeted for ESPCP conversion. Assuming a P50 oil rate, sensitivities were run to establish the minimum oil price for the project to be economically feasible. The operator's project economic success criteria were :(1) pay-out period of <2 years and (2) NPV of > US $0.15 Million considering a ten (10) year project. An integrated sensitivity analysis was performed for the entire project with varying expected production increases and fluctuating global oil prices. The simulations identified that the project will be uneconomic at a global oil price of US $20/bbl. Assuming a project life of 10 years and based on the expected production increase, the project is massively profitable, yielding an expected NPV of US $9.3 Million at US $45 per barrel with expected pay-out times between 0.63-1.8 years with investment of US $4 Million. Additional benefits anticipated include, increased well uptime and the corresponding reduction in workover costs. Another opportunity that results from the conversion to ESPCP, is the possibility of lowering the pump in the wellbore, thereby increasing the well producing life and increasing the recoverable reserves. Installation of ESPCPs, in theory, can be an economic success in an area where surface driven PCP experiences repetitive rod failures, leading to production deferrals and workover. Additionally, lowering the pump in the wellbore may be possible, thereby increasing the well producing life and increasing recoverable reserves which would not have been possible using traditional artificial lift methods.

The Forties and Brimmond Fields, Blocks 21/10, 22/6a, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 557-561 ◽  
Author(s):  
A. Carter ◽  
J. Heale
Keyword(s):  
North Sea ◽  
Low Cost ◽  
New Technology ◽  
Horizontal Wells ◽  
Oil Price ◽  
3D Seismic ◽  
Rotary Drilling ◽  
Geological Society ◽  
Recoverable Reserves ◽  
Infill Drilling

AbstractThis paper updates the earlier account of the Forties Field detailed in Geological Society Memoir 14 (Wills 1991), and gives a brief description of the Brimmond Field, a small Eocene accumulation overlying Forties (Fig. 1).The Forties Field is located 180 km ENE of Aberdeen. It was discovered in 1970 by well 21/10-1 which encountered 119 m of oil bearing Paleocene sands at a depth of 2131 m sub-sea. A five well appraisal programme confirmed the presence of a major discovery including an extension into Block 22/6 to the southeast. Oil-in-place was estimated to be 4600 MMSTB with recoverable reserves of 1800 MM STB. The field was brought onto production in September 1975. Plateau production of 500 MBOD was reached in 1978, declining from 1981 to 77 MBOD in 1999.In September 1992 a programme of infill drilling commenced, which continues today. The earlier infill targets were identified using 3D seismic acquired in 1988. Acquisition of a further 3D survey in 1996 has allowed the infill drilling programme to continue with new seismic imaging of lithology, fluids and saturation changes. The performance of the 1997 drilling showed that high step-out and new technology wells, including multi-lateral and horizontal wells, did not deliver significantly better targets than drilling in previous years.In line with smaller targets, and in the current oil price environment, low cost technology is being developed through the 1999 drilling programme. Through Tubing Rotary Drilling (TTRD) is currently seen as the most promising way of achieving a step

Wireline Retrievable ESP Deployment: Observation, Challenges and Intervention

2021 ◽  
Author(s):  
Fadzlan Suhaimin ◽  
Nasir Oritola ◽  
Bo Jun Fang ◽  
Hing Kheong Cheong ◽  
Yung Khiong Chan
Keyword(s):  
High Risk ◽  
Selection Process ◽  
Cost Advantage ◽  
Value Proposition ◽  
Pilot Performance ◽  
Operating Period ◽  
Artificial Lift ◽  
Start Up ◽  
Offshore Field ◽  
Gas Lift

Abstract The Offshore Field X Project comprises of greenfield scope to expand the Waterflood scheme towards delivering the peak production levels similar to those achieved in the 1990s. Although various artificial lift systems have been successfully deployed in Brunei Shell Petroleum, offshore ESP installation, especially on this scale, is a first and a new journey for the company and its Offshore Assets in which gas lift was predominantly the artificial lift method. The first offshore ESP well was only installed and kicked off in 2017 as part of the Field X Project. As wells are located offshore, cost, resources and logistics remain a challenge for well interventions. With a high workover cost associated with conventional ESP change out, a technology trial was embarked upon to install wireline retrievable ESP systems. A total of 4 out of the 22 ESP wells were approved to be installed and completed with wireline retrievable ESP system on a pilot basis. The business goal was to prove the production deferment reduction and cost advantage for a failed ESP replacement. A critical selection process was followed as well as FAT/industry benchmarking in order to land on WRESP decision for the pilot. System installation and commissioning of the wells was completed by June 2019, however a series of start-up problems were encountered, leading to an intervention requirement to rectify 1 well. Job planning for this intervention was not straight forward and was classified as a high-risk job requiring regulator's approval. Rigorous logistics planning, integration of various vendors, detailed workflow analysis, intervention equipment stack up and modifications were among the planning scope conducted. This paper captures details of the deployment value proposition, case success definition and challenges faced in ensuring all the installed WRESPs are up and running to enable the pilot performance proper evaluation. As no full workover has been executed yet due to the limited operating period, a lifecycle comparison between WL retrievable and conventional ESPs has not been done yet. Once sufficient performance data is available, a detailed study will be conducted to assess the performance of the WRESP system. This analysis will then conclude the technology trial and may change the future of ESP wells in BSP and Shell global.

A New Model for Evaluation of Horizontal Well in Bottom Water Reservoirs

2013 ◽  
Vol 411-414 ◽  
pp. 486-491
Author(s):  
Yue Dong Yao ◽  
Yun Ting Li ◽  
Yuan Gang Wang ◽  
Ze Min Ji
Keyword(s):  
Oil Recovery ◽  
Field Data ◽  
Horizontal Well ◽  
Bottom Water ◽  
Interaction Analysis ◽  
Evaluation Model ◽  
Water Reservoir ◽  
Well Performance ◽  
Water Reservoirs ◽  
Actual Field

It is the aim of this research to describe the horizontal well performance in different conditions, this paper firstly introduces 13 dimensionless variables to describe the influence factors of horizontal well performance in bottom water reservoir and calculates the range of all the variations from low to high level by making a statistics of the actual field data of the 23 horizontal wells, then establishes the oil recovery model with response surface method using a 3 level-13 variables Box-Behnken design (BBD) . Based on the evaluation model, single factor sensitivity and interaction analysis between any two factors are carried out. Finally, research on horizontal well in typical bottom water reservoirs indicates that the values calculated by the new evaluation model fit the actual field data, which proves that the evaluation model can provide criteria for the design or optimization of horizontal well development in a bottom water reservoir.

Comparison of SCR Field Response With Analytical Predictions

2011 ◽  
Author(s):  
Yiannis Constantinides ◽  
Jen-hwa Chen ◽  
Lee Tran ◽  
Prahlad Enuganti ◽  
Mike Campbell
Keyword(s):  
Structural Response ◽  
Field Measurements ◽  
Design Parameters ◽  
Element Analysis ◽  
Steel Catenary Riser ◽  
Analysis And Design ◽  
Industry Standard ◽  
Fea Modeling ◽  
Actual Field ◽  
Deepwater Risers

Design of deepwater risers involves the use of multiple conservative design parameters to account for the uncertainty in the understanding of the behavior of complex structures. As the oil industry moves into deeper and harsher waters, the design tolerances are getting stretched. Chevron has been monitoring the structural response of a deepwater Gulf of Mexico steel catenary riser (SCR) to improve the understanding of riser behavior and to evaluate the existing analysis and design methodologies against actual field measurements. The following paper presents a selected set of results from benchmark of SCR response in storm conditions against analytical predictions, based on industry standard methodologies. The predictions are based on a finite element analysis (FEA) modeling of the riser structure with empirically formulated models for hydrodynamics and soil-structure interaction. Predicted riser response in terms of accelerations and stresses along the length are compared against field measurements showing good overall agreement.

Reliability Software to Design New Generating Plants

2004 ◽  
Author(s):  
J. K. August ◽  
Krishna Vasudevan ◽  
W. H. Magninie
Keyword(s):  
Failure Modes ◽  
Operating Cost ◽  
Commercial Production ◽  
Equipment Failure ◽  
Plant Design ◽  
Economic Success ◽  
Maintenance Costs ◽  
Defining System ◽  
System Requirements ◽  
And Control

Engineers design plants with overall income and operating cost objectives in mind. Defining system requirements, component functions, and failure modes, they discern risks that drive design. Maintenance costs get considered as an afterthought. Misunderstanding significant equipment failure modes greatly changes profitability. Improving certainty of plant economic success requires reducing the risk of unknown failures. Unanticipated operating restrictions can hobble commercial production. Avoiding unanticipated problems sustains predictable costs and operations. Relational software can reduce economic operating risk during plant design to project and control operating risks and maintenance costs.

scholarly journals Generalized Extreme Value Statistics, Physical Scaling and Forecasts of Oil Production in the Bakken Shale

Energies ◽  
2019 ◽  
Vol 12 (19) ◽  
pp. 3641 ◽  
Author(s):  
Wardana Saputra ◽  
Wissem Kirati ◽  
Tadeusz Patzek
Keyword(s):  
Oil Production ◽  
Extreme Value ◽  
Gas Production ◽  
Extreme Value Statistics ◽  
Well Performance ◽  
Generalized Extreme Value ◽  
Potential Wells ◽  
Well Production ◽  
Industry Standard ◽  
Decline Curve

We aim to replace the current industry-standard empirical forecasts of oil production from hydrofractured horizontal wells in shales with a statistically and physically robust, accurate and precise method of matching historic well performance and predicting well production for up to two more decades. Our Bakken oil forecasting method extends the previous work on predicting fieldwide gas production in the Barnett shale and merges it with our new scaling of oil production in the Bakken. We first divide the existing 14,678 horizontal oil wells in the Bakken into 12 static samples in which reservoir quality and completion technologies are similar. For each sample, we use a purely data-driven non-parametric approach to arrive at an appropriate generalized extreme value (GEV) distribution of oil production from that sample’s dynamic well cohorts with at least 1 , 2 , 3 , ⋯ years on production. From these well cohorts, we stitch together the P 50 , P 10 , and P 90 statistical well prototypes for each sample. These statistical well prototypes are conditioned by well attrition, hydrofracture deterioration, pressure interference, well interference, progress in technology, and so forth. So far, there has been no physical scaling. Now we fit the parameters of our physical scaling model to the statistical well prototypes, and obtain a smooth extrapolation of oil production that is mechanistic, and not just a decline curve. At late times, we add radial inflow from the outside. By calculating the number of potential wells per square mile of each Bakken region (core and noncore), and scheduling future drilling programs, we stack up the extended well prototypes to obtain the plausible forecasts of oil production in the Bakken. We predict that Bakken will ultimately produce 5 billion barrels of oil from the existing wells, with the possible addition of 2 and 6 billion barrels from core and noncore areas, respectively.

Towards 1 Million Barrels Oil Per Day in 2030: Visual Analytics for Artificial Lift Performance Optimization in Indonesia

2021 ◽  
Author(s):  
Achmad Rocky Falach ◽  
Ageng Warasta ◽  
Alfandra Ihsan ◽  
Amalia Kusuma Dewi ◽  
Heri Safrizal ◽  
...  
Keyword(s):  
Performance Optimization ◽  
Visual Analytics ◽  
Production Efficiency ◽  
Operating Cost ◽  
Evaluation Process ◽  
Oil Wells ◽  
Point Of View ◽  
Production Volume ◽  
Artificial Lift ◽  
Evaluation Time

Abstract One of the strategies to achieve Indonesia's main goal to produce one million barrels oil per day in 2030 is to maintain existing production volume. The key of maintain the existing production is to optimize artificial lift performance used in oil wells, because 96% of oil wells in Indonesia had installed artificial lifts and their performance will significantly affect the production decline rate. This approach aims to create a simple data visualization from macro perspective, to evaluate the artificial lift performance of all oil wells in Indonesia and to find a solution to optimize their performance. This method is started by collecting the main parameters that describes the artificial lift performance such as artificial lift type, historical run life, historical operating cost, production rate, reservoir depth, type of fluid as well as additional issues from each field in Indonesia. After the data is gathered, the next step is to cluster the usage of various artificial lifts in Indonesia, which have similarities such as area, crude type, depth, rate, and operational problems, in terms of comparison between the optimum case and non-optimum one. Finally, from the non-optimum one, it will be evaluated on more detailed programs for further optimization. This evaluation process is carried out by visualizing all the data gathered using some informative dashboards. The digitalization is expected to help the improvement of evaluation time and to support decision processes. By implementing this method, several success cases were demonstrated in 2020, like optimizing Sucker Rod Pump (SRP) component in one of the fields in Sumatra, with the gain around 120 BOPD, Gas lift and SRP to Electric Submersible Pump (ESP) conversion in one of the fields in Kalimantan with 160 BOPD production outcome, switching normal ESP rate to lower rate ESP which resulted from double run life compared with the previous one, and also conversion from SRP to HPU that can extend its run life, while creating cost efficiency. From those results, it shows the benefit of the dashboards created for artificial lift optimization, especially from Government point of view. Furthermore, there are around 50 wells that will be evaluated in detail for optimization program. The visual analytics of the dashboards, for example, will help the evaluation process all at once providing positive impacts on artificial lift optimalization program. In the future, we hope that these dashboards could be developed further, by combining the implementation of machine learning, like fuzzy logic methods or neural network, to enhance the operator performance and to improve production efficiency toward the achievement of one million barrels oil per day in 2030.

What’s the Best Friction Reducer? You Need To Figure It Out Yourself

2021 ◽  
Vol 73 (10) ◽  
pp. 27-30
Author(s):  
Stephen Rassenfoss
Keyword(s):  
Chemical Reactions ◽  
Performance Testing ◽  
Good Method ◽  
Well Performance ◽  
Oil Companies ◽  
Industry Standard ◽  
Well Design ◽  
Reservoir Conditions ◽  
The Many ◽  
Friction Reducer

Friction reducers are expected to play critical roles in fracturing, some better than others. Shale producers are belatedly realizing that there are many variables that can alter the performance of these chemicals used to reduce the power needed to hydraulically fracture a reservoir, and in higher doses, to thicken fluid, making it possible to deliver proppant more efficiently. There are wells that can justify paying more for a friction reducer formulated to stand up to difficult chemical challenges, and others that cannot. But there is no guide that describes how these key additives perform. Those who do evaluations will realize that a lot of details about friction reducers are proprietary and no industry standard provides guidance about the information needed to thoroughly assess their compatibility with reservoir conditions. “There hasn’t been a really good method to quantitatively evaluate friction reducers and what they do,” said Paul Carman, the completion fluid advisor for ConocoPhillips, who has not figured out what that method might be. Recently, Occidental Petroleum took a stab at answering the question with a paper discussing its evaluation of friction-reducer performance. It’s not a short answer. The paper delivered at the Unconventional Resources Technology Conference (URTeC) does not offer names of the products tested, how many were tested at any stage of the process, or details that might identify top performers (URTeC 5249). Those who dig deeper and ask fracturing experts will learn that the best friction reducer will depend on the job. And money, time, and research are required to gather the data needed for informed decision making. When Occidental began working on a system to evaluate friction reducers, they found little had been written on how to do it, said Nancy Zakhour, Occidental’s well design lead, a coauthor of the paper. There was a general paper from Shell on well chemical evaluation but little else. That shows how oil companies have come to rely on others to do performance testing. The shale business has not shown much interest in chemical performance until recently. Greater attention has turned to the many details that can incrementally improve shale well performance and to the research showing how friction reducers perform badly due to chemical reactions in some wells. These are not the only additives that may be affected by chemical reactions during and after fracturing. But friction reducers have grabbed the most attention because they do a couple important jobs.

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