Re-Engineering Existing Pipelines in Western Canada

2006 ◽  
Author(s):  
Michael F. Hallihan
Keyword(s):  
Oil And Gas ◽  
Flow Direction ◽  
Gas Production ◽  
Western Canada ◽  
Operating Pressure ◽  
Oil And Gas Production ◽  
Well Completion ◽  
Service Conditions ◽  
Pipeline Design ◽  
Common Situation

The pipeline infrastructure throughout Western Canada is extensive, with more than 350,000 km in Alberta alone. As the profitability of oil and gas production swings, so too does the utilization of the pipeline infrastructure. During the 1990’s, the economics of some oil and gas production was marginal and the associated pipelines were under utilized. In particular, upstream producers deactivated several under utilized pipelines. Deactivated lines were blocked in, others purged and isolated, while others were completely abandoned. The profitability of oil and gas production has improved steadily since 1999 and the industry has pursued the reactivation of many of these pipelines. In several cases, the diligence of the pipeline operator during economically tight periods was less than desirable with respect to both of these functions. Poor economics also impaired the development and preservation of good pipeline design and maintenance records. The retention of the existing records was further impaired by the numerous corporate divestments and acquisitions that occurred over the past fifteen years. The lack of good quality pipeline records has hampered efforts to reactivate many pipelines. Another feature of our economic environment is the production of alternate zones from an existing well that was previously uneconomic. These zones often produce fluids significantly different than the original well completion and may not be consistent with the design of the original pipeline. This requires re-engineering of the pipeline for the new service. The most common situation is changing from one substance to another, however, changing the maximum operating pressure, changing the design temperature or changing the flow direction may also be required. The objective of this paper is to describe some of the specific challenges in reactivating dormant pipelines and re-engineering pipelines for new service conditions. The focus of this paper will be with respect to pipelines built to CSA Z183, Z184 or Z662 standards and the Alberta Pipeline Regulation.

Laboratory-Scale Investigation of the Utilisation of Multiple Flat-Fan Nozzles in Descaling Petroleum Production Tubing

2021 ◽  
Author(s):  
Kabir Hasan Yar'Adua ◽  
Idoko Job John ◽  
Abubakar Jibril Abbas ◽  
Salihu M. Suleiman ◽  
Abdullahi A. Ahmadu ◽  
...  
Keyword(s):  
High Pressure ◽  
Oil And Gas ◽  
Gas Production ◽  
Oil And Gas Production ◽  
Scale Removal ◽  
Petroleum Production ◽  
Well Completion ◽  
Water Jets ◽  
Well Integrity ◽  
Injection Pressures

Abstract Despite the recent wide embrace of mechanical descaling approaches for cleaning scales in petroleum production tubings and similar conduits with the use of high-pressure (HP) water jets, the process is still associated with downhole backpressure and well integrity challenges. While the introduction of sterling beads to replace sand particles in the water recorded high successes in maintaining well completion integrity after scale removal in some recent applications of this technique, it is, unfortunately, still not without questions of environmental degradation. Furthermore, the single nozzle, solids-free, aerated jetting descaling technique – recently published widely – is categorized with low scale surface area of contact, low descaling efficiency and subsequent high descaling rig time. The modifications to mechanical descaling techniques proposed in this work involve the use of three high-pressure flat fan nozzles of varying nozzles arrangements, standoff distances and injection pressures to remove soft scale deposits in oil and gas production tubings and similar circular conduits. This experiment provides further insights into the removal of paraffin scales of various shapes at different descaling conditions of injection pressures, stand-off distances and nozzle arrangements with the use of freshwater. The results obtained from this study also show consistency with findings from earlier works on the same subject.

Corrosion and Wear Resistant Boronizing for Tubulars and Components Used Down-Hole

2021 ◽  
Author(s):  
Roger Machado ◽  
Paola Andrea de Sales Bastos ◽  
Danny Daniel Socorro Royero ◽  
Eugene Medvedovski
Keyword(s):  
Oil And Gas ◽  
Chemical Vapour ◽  
Protective Layer ◽  
Gas Production ◽  
Operating Conditions ◽  
Material Loss ◽  
Oil And Gas Production ◽  
Dimensional Changes ◽  
Wear And Corrosion ◽  
Service Conditions

Abstract Components and tubulars in down-hole applications for oil and gas production must withstand severe wear (e.g. erosion, abrasion, rod wear) and corrosion environments. These challenges can be addressed through boronizing of steels achieved employing chemical vapour deposition-based process. This process permits protection of the entire working surfaces of production tubulars up to 12m in length, as well as various sizes of complex shaped components. The performance of these tubulars and components have been evaluated in abrasion, erosion, and corrosion conditions simulating the environment and service conditions experienced in down-hole oil and gas production. Harsh service conditions are very common in the oil industry and the combination of abrasion, friction-induced wear, erosion, and corrosion environments can be quite normal in wells producing with the assistance of artificial lift methods. The boronized steel products demonstrated significantly higher performance in terms of material loss when exposed to harsh operating conditions granting a significant extension of the component service life in wear and corrosion environments. As opposed to many coating technologies, the boronizing process provides high integrity finished products without spalling or delamination on the working surface and minimal dimensional changes. Successful application of tubulars and components with the iron boride protective layer in oil and gas production will be discussed and presented.

An Outright Success in Oil and Gas Production Arise from Surface Facility Modification – Story of Ujung Pangkah Field

2021 ◽  
Author(s):  
Ameria Eviany ◽  
Ifani Ramadhani ◽  
Cio Mario ◽  
Anang Nugrahanto ◽  
Harris Pramana ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Gas Production ◽  
Critical Surface ◽  
Operating Pressure ◽  
Suction Pressure ◽  
Pressure System ◽  
Oil And Gas Production ◽  
Wellhead Pressure ◽  
Pressure Depletion ◽  
Gas Lift

Abstract The two most common challenges on the oil and gas production today are the flowing production under natural pressure depletion and the surface facility capacity limitation. Ujung Pangkah field is no exception regarding finding a method to overcome this problem. It compelled to embolden many strategies to ensure the continuity of oil and gas production. Production enhancement initiatives were delivered through both Subsurface and Surface sides. SAKA Energi Indonesia, as the operator of Pangkah PSC, proved that Surface Modification approach increased the oil and gas production. Historically, gas lift injection dependency in all production wells force a continuous operation of Gas Lift Compressor (GLC) unit to supply gas lift. However, GLC as a production backbone is no longer sustainable, it has reached its maximum limit and unable to fulfil the gas lift rate requirement for all wells. Furthermore, the changing flowing conditions – low gas feeding - from wells are relatable to most of the critical surface equipment. Considering all the challenges faced in Ujung Pangkah field, SAKA developed initiatives on MP Compressor and GLC configuration by performing compressors restaging. The equipment modifications started out with restaging the MP Compressor (MPC) that led to MP Separator operating pressure reduction – from 22 barg down to 16 barg. Pressure changes on MP Separator also directly affected the GLC system since it works on the same pipeline header. Technical assessment analysis for other corresponding equipment were performed to verify if each of the equipment's operating boundary could accommodate lower pressure at the facility. Compressor restaging has direct and indirect impacts. The direct impacts are decrease in suction pressure, increase in gas lift rates, and decrease in flowing of suction pressure due to the pressure at wellhead. The indirect impact is production gain from wells by lowering the wellhead pressure. Particularly in the pressure depletion case, this initiative could extend the lifetime of the wells. Production gain was quantified after compressor restaging and pressure system lower to 16 barg. The gain from this method was 3 MMscfd and ~400 BOPD.

Fraccing forum

2016 ◽  
Vol 56 (1) ◽  
pp. 51
Author(s):  
Maxwell Williamson
Keyword(s):  
Hydraulic Fracture ◽  
Oil And Gas ◽  
South Australia ◽  
Gas Production ◽  
Scientific Practices ◽  
The European Union ◽  
Oil And Gas Production ◽  
Well Completion ◽  
The Us ◽  
Hydraulic Fracture Stimulation

There have been 13 major inquiries completed during the past few years that have addressed the issue of hydraulic fracture stimulation (fraccing) in Australia. There are two inquiries due to report before mid-2016; namely in SA (Natural Resources Committee, Parliament of South Australia, 2015), and the Senate Inquiry (Parliament of Australia, 2015). These inquiries are in addition to many others conducted in overseas jurisdictions including various states of the US, Canada, and in countries in the European Union, including the UK. Concerns are usually concluded around ensuring there is a proper regulatory environment to confirm that the use of fraccing is conducted using international best practices, and the risk to the environment is minimised. In each and every responsible inquiry the conclusion has been that there is no scientific or public policy reason that would justifiably prevent the use of fraccing as a pre-well completion stimulation technique. This paper attempts to synthesise basic data about fraccing—why the ability to fracture stimulate wells is no longer a luxury but a necessity in deep oil and gas production—to convey factual information and summarise the results of inquiries in Australia to date. Comparisons between hydraulic fracture stimulation operations and results in the US and Australia are intended to provide comfort that some of the potentially more intense (massive) hydraulic fracture stimulation operations routinely conducted in the US (and Canada) on an individual well basis are not contemplated in the immediate future in Australia. The scale of North American fraccing activities may bear little resemblance to what may be proposed or occur in Australia owing to fundamental differences in geology, basin stress regimes, infrastructure, and cost and logistics, among other factors. The author’s conclusion is that fraccing in Australia can and will be carried out in a sphere of safety and regulation that many other countries are likely to aspire to copy. It would, however, be foolish to suggest hydraulic fracturing operations are not without some risk, as with many industrial and other daily activities, but the risks can be managed or mitigated with sound engineering and scientific practices. This is irrespective of the messages by opponents of hydraulic fracture stimulation in oil and gas wells. The modern practice of fraccing has been used now for more than 65 years, albeit with increasing scale commensurate with technological advances, which has caught the public’s imagination. Indeed, the results of inquiries have given no credence to demonising the technology.

Experimental Study of Pipe Pulling Through Settled Barite

2019 ◽  
Author(s):  
Ali Taghipour ◽  
Torbjørn Vrålstad ◽  
Ragnhild Skorpa ◽  
Mohammad Hossain Bhuiyan ◽  
Jan David Ytrehus ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Drilling Fluid ◽  
Gas Production ◽  
Solid Particles ◽  
Cement Slurry ◽  
Oil And Gas Production ◽  
Field Development ◽  
Steel Pipes ◽  
Well Completion ◽  
Side Track

Abstract Wells are essential in oil and gas production and construction of them is one of the main cost drivers for field development. It is normally needed to drill and construct new wells from existing fields during most of the production time. In order to reduce costs one can re-use parts of existing wells when they are no longer efficient. This is done in offshore fields also when there is limitation for new wells due to capacity of the subsea template. Through tubing drilling is a method to drill a side track through the wellbore tubulars. However, this will normally result in a smaller and less effective well completion. Removing parts of the casing section and drill a larger size sidetrack is an option to provide a new full-size wellbore. Removing the 9 5/8” casing through the settled particle in the annulus can be challenging. The wellbore annulus is normally filled with old drilling fluid, displacing fluid and/or cement slurry. The solid particles of these annular fluids are settled during years of shut-in and make it difficult to move the casing sections. There are several techniques for pulling the casing section, but there is a lack of knowledge of some of the key mechanism causing the resistance in these operations. In order to study and address the dominating effects in these operations, down-scaled laboratory tests are performed. The experiments reported here are performed by pulling steel pipes through the settled barite in the annulus. The pipes used in the tests are down-scaled from typical casing sizes with and without collars. The barite slurry compacted inside the annulus have different hydrostatic and pore pressures. When the pipe is pulled the required mechanical force is measured. Results show that the single most significant factor causing resistance when pulling the tubulars is the collars outside the pipe. Furthermore, it is identified that the pore pressure improves the mobility of the settled particle around the collar. In total these results provide improved understanding on the dominating factors during pulling pipes from a packed annulus.

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