Introduction to Petroleum Economics explains the process of gathering data, calculating whether a project should proceed, and delivering recommendations. The author shares some helpful and informative anecdotes based on his career as a petroleum economist. SPE Journal includes fundamental research papers on all aspects of engineering for oil and gas exploration and production. Join industry experts as they explore solutions to real problems and discuss trending topics in Management and Information. SPE webinars are free to members courtesy of the SPE Foundation.
In this new book, a variety of pipeline environments are detailed along with an exploration of the challenges that require chemical or mechanical intervention. Join industry experts as they explore solutions to real problems and discuss trending topics in projects, facilities, and construction. SPE webinars are offered free to members courtesy of the SPE Foundation.
This paper presents experiences gained from several Chemical sand consolidation treatments performed in one of the field in West Africa. Success rate was 60% and there were learnings from failures. Case studies for several wells are provided to highlight the key aspect and learnings which are essential to improve the chances of any sand consolidation treatment.
Chemical Sand consolidation (SCON) treatment provides in situ sand influx control by treating the incompetent formation around the wellbore itself. The treatment consists of injecting the immediate near wellbore area of the reservoir with a fluid containing an adhesive or epoxy resins, which increases the strength of the formation without significant loss of permeability. The ideal sand consolidation system provides the highest possible resistance to sand production at the lowest impairment. However, there are many factors which generally not thought of could lead to potential job failure. Several SCON treatments have been done in the field. Of the total number of jobs conducted over time, there were some failures reported as well therefore a detailed after action review was conducted which highlighted some important factors responsible for failure. The factors responsible for the failure of these wells were found non-associated with each other. Key areas like candidate selection, well preparation prior to SCON treatment, design and modeling, SCON chemical validation and testing, job execution, well start-up post treatment were looked into details to summarize the findings. For successful SCON treatment, well preparation is very important. Well preparation conveyance method is typically coil tubing unit, bullheading or workover. Especially well preparation via either means requires extra considerations therefore some important learning will also be discussed apart from SCON treatment aspect.
The findings and learnings from these jobs were incorporated into future campaigns to maximize the success. Sand consolidation proved to be a successful means to add production gains in a low cost environment.
Shallow gas seepage was first spotted at a central processing platform offshore Malaysia in 2010, acknowledged as Platform T in this paper. Frequent monitoring of the gas seepage was performed through ROV baseline survey and a comprehensive geophysical survey was conducted to understand the characteristics of the gas seepage and to ensure that the integrity of the foundation at Platform T was not compromised. The origin of the gas could not be ascertained at that point of time.
A soil investigation campaign was performed in 2016 to study the origin of the gas seepage. Two boreholes were drilled; a composite borehole to 150m below seabed for the purpose of soil sampling and in-situ testing and a pilot hole to 155m below seabed, which was later converted to a fit-for-purpose relief well as an alternate migration path for the gas. During the soil investigation campaign, dissipation tests were performed at several layers which were potentially the source or migration path for the gas. Five soil samples were segregated for headspace test to identify the gas type which subsequently can be used to identify the origin of the gas.
Dissipation tests performed at four depth intervals indicates pore water pressure less than 20% of the vertical effective stress and appear to continue decreasing if the test had not been stopped. It was concluded that a low to negligible amount of excess pore pressure exist in clayey silt layers. Results from headspace test show presence of methane corresponding to the clayey silt layers as reported in the boring logs. The gas most likely comes from biogenic sources, feeding on organic matter in situ over a large depth range.
It is unlikely that there are large pockets of gas in the soil due to its homogeneous clayey nature and the lack of excess pore pressure in other permeable clayey silt layers encountered. Instead, it is more likely that when pore water at certain depth encounters a more permeable path, such as a borehole, it rises up through this path due to the temperature gradient in the soil. As the water rises, the pressure decreases, which could cause gases dissolved in the water to come out of solution and form bubbles. As a result, the gas will have no impact on the integrity of the foundation at Platform T.
The fit-for-purpose relief well design as well as adopting headspace testing can be used to address the shallow gas issue at Platform T in a cost-effective and efficient manner.
Cable Deployed ESPs (CD-ESPs) are foreseen as the future of ESP installations as they eliminate the need for full-fledge rig on location to perform ESP change out. One of the main challenges of performing ESP installation riglessly is the lack of mud circulation system which is used to monitor increase in fluid loss rate, indicate possible well kick and bring the well back to control in case of such emergencies. With the lack of this line of defense, there is a need to develop alternative method to ensure safe rigless ESP installation particularly when ESP components are being made-up and lowered down the well.
The first high H2S vertical well CD-ESP worldwide was trial tested in a pressurized onshore well in Saudi Arabia. The candidate well had a shut-in pressure of 390psi, H2S concentration of 1.12% and fluid loss rate of 18-24 bbl per hour (bph) for 71 pound per cubic foot (pcf) kill fluid.
Kill fluid has to be continuously supplied at a rate equivalent to the varying loss rate of the well. For this, the surface well testing equipment (required for well flow-back after ESP installation) was modified to monitor and store excess kill fluid return. The new modification allows pumping of kill fluid to continue while Blow-Out Preventer (BOP) equipment are open on top of the Christmas tree. The density of the kill fluid was monitored and maintained during the whole operation.
The operation started by bullheading with one and a half wellbore volume. The well performance was monitored and then kill fluid rate was increased gradually to measure the loss rate of the well. Pumping of kill fluid was highly coordinated during the main installation phases of the CD-ESP: surface make-up of ESP assembly in sections, run in hole with cable to target depth and the final make-up of the cable hanger.
The returns of any excess kill fluid could be measured by the modified surface testing package. Pumping rate of kill fluid was highly correlated with Tubing Casing Annulus (TCA) pressure since the volume of fluid in the annulus changed (due to the small contraction/expansion of the seal bore assembly).
While the pump was inside the well, pumping kill fluid caused significant increase of weight reading. The pump (5.62") acted like a piston inside the (6.275") ID of the 7" tubing causing high weight values.
At one point during the operation, the loss rate of the well increased dramatically. This caused negative readings on pressure gauges of the wellhead (loss rate was higher than maximum pump supply).
The paper presents a novel comprehensive well killing measures for rig-less CD-ESP installation. To assure the safe conduct of future operations, the paper also shows lessons learnt and contingency measures for unexpected events during the operation.
Since the mid-1980s, advances in coiled tubing (CT) modelling software have enhanced operational efficiency, reduced technical risks, expanded the acceptable operating envelope and improved well intervention success rates. Until relatively recently, models were the steady-state type. Since 2010 dynamic modelling for CT operations has been utilized. This paper, focusing exclusively on transient modelling, incorporates unpublished novel case histories showing pre-job optimization and post-job investigations. The focus is on showing the simulation advantages of transient versus steady-state conditions.
The transient model predicts the changes over time resulting from varying pumped and produced fluid rates, varying fluid types, two-phase relationships, location of solids, location of the CT and the wellhead choke size. Equations for the conservation of mass and momentum and a unified drift-flux model, valid for all flow regimes, are included in the model. Based on experimental testing on a full-scale flow loop, a critical gas flow velocity model was developed. It has been validated against published case histories and results of other transient models primarily developed for pipeline operations.
Several case histories are presented, showing phenomena that cannot be captured by steady-state CT models. First, a review of two cases of post-job investigations are presented: a re-calculation considering multiple well pressures and fluid content changes, to confirm that the CT weight was accurately recorded prior to an operational incident; and a re-calculation of a solids cleanout operation where incorrect execution resulted in stuck CT. Second, a review of two cases of pre-job analysis includes the modelling the switching of a tool with respect to time instead of pressure (required because high nitrogen rates mask surface pressure indications of downhole changes); and the modelling of a complex situation where the client requested an optimized dewatering operation with only a small volume of nitrogen available. Finally, cases of optimizing solids cleanout removal with multiple changes in fluid rheology are reviewed.
Three prior papers (
Othman, Anis Izzuddin (Upstream) | Zaki, Shazana Bt. M. (PETRONAS Carigali Sdn Bhd) | Naharindra, Adhi (PETRONAS Carigali Sdn Bhd) | Riyanto, Latief (PETRONAS Carigali Sdn Bhd) | Yahia, Zaidil B. (PETRONAS Carigali Sdn Bhd) | Govinathan, Kesavan (Halliburton) | Kristanto, Tutus (Halliburton) | Yeo, Kim Teng (Halliburton)
Field A, an oil field located in Peninsular Malaysia, was completed in 2007 with an initial production of 6,000 BOPD and managed to reach a peak production of 15,000 BOPD the same year, with a water cut of 15%. Toward the end of 2014, a decrease in production was observed with an increase in water cut to 85%. Coupled with high water cut, some of the wells experienced sand production issues. Most of the wells were completed with either standalone screens or without any sand control methods. After a few years in production, the sand-producing wells were shut-in to help prevent damage to surface facilities.
Two idle oil wells, Wells 1 and 2, were identified and efforts were made to reactivate them. High costs can be associated with remedial mechanical sand control to work over a well, so a chemical consolidation treatment using solvent-based resin was identified as a less expensive solution for remedial sand control for these wells.
Chemical sand consolidation using solvent-based epoxy resin was tested in a laboratory using produced sand samples from the selected wells and showed good results. The chemical consolidation treatments for Wells 1 and 2 were designed based on these results. Before treatment was performed for either well, Well 2 was replaced with Well 3 because of a gas supply shortage, which affected total field production. In October and November 2015, Wells 1 and 3 were intervened and chemical sand consolidation was executed on both wells. After the treatment, Wells 1 and 3 were brought back on production. Sand production for Well 1 was below the threshold limit of 15 pounds per thousand barrels (pptb). However, the performance of Well 3 did not meet expectations.
This paper describes the process of treatment design and execution for the chemical sand consolidation of Wells 1 and 3 and explains the workflow used during the design stage. Coiled tubing isolation technique and bullhead treatment technique are discussed together with lessons learned from Wells 1 and 3 in terms of designing chemical sand consolidation treatments for future applications.
Total’s Laggan Tormore project claimed the International Petroleum Technology Conference (IPTC) Excellence in Project Integration Award at the 10th IPTC in Bangkok, Thailand. The IPTC Excellence in Project Integration Award highlights projects that have demonstrated distinction throughout the entire value chain, and are equivalent in value to at least USD 500 million. Past winners have included both international and national oil companies. Taken into account are projects that exemplify strong teamwork, solid geoscience knowledge, reservoir and production engineering expertise, outstanding facilities engineering practices, a strong commitment to health, safety, and the environment, and advocate innovative and people-oriented human resource policies and community programs.