Development of API 11D1 and API 19AC Validation Grade V0 Barrier-Qualified Gravel Pack System for Troll Phase 3 Big-Bore, High-Rate Gas Completions on the Norwegian Continental Shelf

2021 ◽  
Author(s):  
Aaron C Hammer ◽  
Tom D Gonzalez ◽  
Herb P Dhuet ◽  
Hege Andresen ◽  
Siv Merete M Sunde ◽  
...  
Keyword(s):  
Pressure Drop ◽  
System Development ◽  
Gas Production ◽  
High Rate ◽  
Phase 3 ◽  
Reduced Pressure ◽  
Well Design ◽  
Open Hole ◽  
Gas Tight ◽  
Gravel Pack

Abstract The Troll Phase 3 (TP3) wells were designed to enable high gas rates and sand free production for an expected lifetime of 40 years with a minimum pressure drop. By taking reservoir and production properties into account, open-hole gravel pack (GP) sand screens in the lower completion and big bore tubing in the upper completion were selected. To further reduce the pressure loss in the well, reduce rig time and cost, and reduce deployment risks, eliminating the intermediate completion was proposed. Traditionally, an intermediate completion is required to serve as a gas-tight barrier for running of the upper completion, mainly due to historical limitations of the GP extension (GP sleeve) not being a barrier qualified to API 19AC Validation grade V0 (referred to as V0 hereafter) after pumping sand slurry through it (post-erosion). An extensive qualification program was completed to qualify the GP system to API 11D1 and API 19AC V0 for use as a gas-tight barrier post-erosion. This allows the GP system to serve as a primary barrier while installing the upper completion and temporarily abandoning the well. The GP packer was qualified to API 11D1 V0 with the additional requirement to perform entire qualification in as-rolled casing and including a plug-in-tailpipe load case. The GP sleeve provided the most technically challenging requirements: a full-scale erosion test, immediate closure of the sleeve after pumping operation, followed by API 19AC Annex A V0 validation. Challenges were encountered trying to meet the rigorous V0 (zero bubble) acceptance criteria post-erosion. A significantly different approach was developed to achieve gas-tight performance in debris-laden environments. The new design successfully passed the post-erosion API 19AC V0 qualification to the full rating of the GP sleeve. The GP system development and qualification enabled the industry-first V0 post-erosion GP system for Equinor, which eliminates the need for an intermediate completion. This state-of-the-art gravel pack system enabled the simplified high gas rate, big-bore well design, not previously possible given well barrier considerations. The reduced pressure drop across the lower completion is expected to yield a higher gas production rate for the 40 years expected well life, contributing significant value to the TP3 project.

Comprehensive Transient Modeling of Sand Production in Horizontal Wellbores

SPE Journal ◽  
2007 ◽  
Vol 12 (04) ◽  
pp. 468-474 ◽  
Author(s):  
Alireza Nouri ◽  
Hans H. Vaziri ◽  
Hadi Arbi Belhaj ◽  
M. Rafiqul Islam
Keyword(s):  
Numerical Model ◽  
Significant Proportion ◽  
Horizontal Wells ◽  
Gas Production ◽  
Operating Conditions ◽  
High Rate ◽  
Sand Production ◽  
Predictive Tool ◽  
Sand Control ◽  
Gravel Pack

Summary Installing sand control in long horizontal wells is difficult and particularly challenging in offshore fields. It is, therefore, imperative to make decisions with regard to the most optimum completion type objectively and based on reliable assessment of the sanding potential and its severity over the life of the well for the intended production target. This paper introduces a predictive tool that forecasts not only the initiation of sanding, but also its rate and severity in real time. A series of well-documented experiments on a large-size horizontal wellbore was simulated using a finite difference numerical model. The model accounts for the interaction between fluid flow and mechanical deformation of the medium, capturing various mechanisms of failure. The model allows capturing the episodic nature of sanding and the resulting changes in the geometry and formation consistency and behavior within the sand impacted regions. Sand detachment is simulated by removal of the elements that are deemed to have satisfied the criteria for sanding based on considerations of physics, material behaviour and laws of mechanics. The proposed numerical model is designed to account for many of the factors and mechanisms that are known to influence sanding in the field and as such can be used as a practical tool for predicting the frequency and severity of sand bursts and changes in operating conditions that can be considered for mitigating or managing such problems. The model shows reasonable agreement with the experimental results in terms of borehole deformation and sanding rates. The model correctly predicted initiation of shear failure from the sides of the borehole and its propagation to the boundaries of the sample. It was further seen that the propagation of the shear failed zone resulting from sand production agreed well with the numerical pattern of failure growth upon removal of elements satisfying the sanding criteria. The approach and concepts used are considered suitable for application to field problems involving horizontal wells. Introduction A significant proportion of the future oil and gas production is expected to come from sand-prone reservoirs, many of which are offshore. While these reservoirs are highly prolific they are complex to develop and manage. Typical cost of completing a major offshore well exceeds $100 million and these wells are expected to remain productive for 20 years and longer. The control of solids production in these high-rate wells over the life of the well is a challenge and requires a good understanding of the mechanical behavior of the formation under a variety of conditions. Various options are available, ranging from placing active sand control, such as gravel pack and frac pack, to natural completion, such as a cased and perforated hole. Objectivity is required in choosing the correct completion type, which must account for the production strategy and natural changes in the reservoir such as changes in the stress state, permeability, and multiphase flow, including water cut. Once the completion type is chosen, it must be operated optimally to maximize production while maintaining efficiency and longevity. For instance, in sand-control completions, operations must be tailored to mitigate generation and transport of fines that can cause plugging of the gravel pack and lead to screen erosion, whereas in natural completions, the emphasis would be in preventing formation sand production or keeping it under the tolerance that can be handled by the facility. Utilization of a reliable sand production prediction tool is essential in selecting the optimum completion technique and optimization of the operational conditions.

Troll Phase 3: The Next Step for a Groundbreaking Giant

2021 ◽  
Author(s):  
Bjørn Laastad ◽  
Knut Ellevog ◽  
Roger Oen Jensen ◽  
Torstein Tveit ◽  
Eirik Torgrimsen ◽  
...  
Keyword(s):  
Pressure Drop ◽  
Value Creation ◽  
Value Chain ◽  
Production System ◽  
Phase 3 ◽  
Gas Field ◽  
Reduced Pressure ◽  
Final Design ◽  
Subsea Production System ◽  
Selection Phase

Abstract An important driver for maximizing value creation for the Troll Phase 3 gas project offshore Norway was to identify means to reduce the pressure drop in the value chain from the reservoir to the onshore terminal. Using a design-to-cost approach in the concept selection phase, this has affected design of the wells, subsea production system, pipeline and the new inlet separator on the Troll A platform; all of which have been designed to preserve the energy from the reservoir as much as possible. The final design has enabled a significant increase of the project value by accelerated gas deliveries, reduction of the energy consumption and thus lowering the CO2 emissions. Calculations show that 1 bar pressure drop in the Troll Phase 3 value chain increases the project NPV (8%, pretax) with approx. 45 Million USD and reduces the power consumption by 11 GWh/year. The well tubing size was increased to 9 5/8", reducing the required number of wells by ~40%. Factoring both wells and subsea facilities, this optimized well concept alone represents a total cost saving of nearly 300 million USD. The project has piloted a modification to the Vertical X-Mas Tree (VXT) design featuring an increase from 5 1/8" to a 7" production wing outlet to minimize the pressure drop across the subsea production system. This VXT design has become the new company standard for gas field developments. The big bore wells and subsea production system design also ensures acceptable gas velocities in the late production phase with low reservoir pressure. The total reduced pressure drop obtained through these and other measures is estimated to 19 bar, realizing a project NPV improvement of approx. 850 million USD (8%, pretax).

Sand Free Production Success Through Proven Technology Enabler from An Untapped Heterogeneous Reservoir Zone Utilizing Gravel Pack Replacement Methodology

2020 ◽  
Author(s):  
Y. Anggoro
Keyword(s):  
Oil And Gas ◽  
Erosion Resistance ◽  
Cost Effective ◽  
High Rate ◽  
Screen Design ◽  
Sand Control ◽  
Rules Of Thumb ◽  
Production Success ◽  
Control Technologies ◽  
Gravel Pack

The Belida field is an offshore field located in Block B of Indonesia’s South Natuna Sea. This field was discovered in 1989. Both oil and gas bearing reservoirs are present in the Belida field in the Miocene Arang, Udang and Intra Barat Formations. Within the middle Arang Formation, there are three gas pay zones informally referred to as Beta, Gamma and Delta. These sand zones are thin pay zones which need to be carefully planned and economically exploited. Due to the nature of the reservoir, sand production is a challenge and requires downhole sand control. A key challenge for sand control equipment in this application is erosion resistance without inhibiting productivity as high gas rates and associated high flow velocity is expected from the zones, which is known to have caused sand control failure. To help achieve a cost-effective and easily planned deployment solution to produce hydrocarbons, a rigless deployment is the preferred method to deploy downhole sand control. PSD analysis from the reservoir zone suggested from ‘Industry Rules of Thumb’ a conventional gravel pack deployment as a means of downhole sand control. However, based on review of newer globally proven sand control technologies since adoption of these ‘Industry Rules of Thumb’, a cost-effective solution could be considered and implemented utilizing Ceramic Sand Screen technology. This paper will discuss the successful application at Block B, Natuna Sea using Ceramic Sand Screens as a rigless intervention solution addressing the erosion / hot spotting challenges in these high rate production zones. The erosion resistance of the Ceramic Sand Screen design allows a deployment methodology directly adjacent to the perforated interval to resist against premature loss of sand control. The robust ceramic screen design gave the flexibility required to develop a cost-effective lower completion deployment methodology both from a challenging make up in the well due to a restrictive lubricator length to the tractor conveyancing in the well to land out at the desired set depth covering the producing zone. The paper will overview the success of multi-service and product supply co-operation adopting technology enablers to challenge ‘Industry Rules of Thumb’ replaced by rigless reasoning as a standard well intervention downhole sand control solution where Medco E&P Natuna Ltd. (Medco E&P) faces sand control challenges in their high deviation, sidetracked well stock. The paper draws final attention to the hydrocarbon performance gain resulting due to the ability for choke free production to allow drawing down the well at higher rates than initially expected from this zone.

Well Design Specificities For Shallow Gas Production Of Tunu Field.

2010 ◽  
Author(s):  
Samir Oumer ◽  
Hafidh Taufiqurrachman ◽  
Marie-Pascale Perruchot ◽  
Fata Yunus
Keyword(s):  
Gas Production ◽  
Shallow Gas ◽  
Well Design

Heat Transfer Enhancement in a Rectangular (AR = 3:1) Channel With V-Shaped Dimples

2012 ◽  
Vol 135 (1) ◽  
Author(s):  
C. Neil Jordan ◽  
Lesley M. Wright
Keyword(s):  
Heat Transfer ◽  
Reynolds Number ◽  
Nusselt Number ◽  
Liquid Crystal ◽  
Pressure Drop ◽  
Heat Transfer Enhancement ◽  
Thermal Performance ◽  
Secondary Flows ◽  
Transfer Enhancement ◽  
Reduced Pressure

An alternative to ribs for internal heat transfer enhancement of gas turbine airfoils is dimpled depressions. Relative to ribs, dimples incur a reduced pressure drop, which can increase the overall thermal performance of the channel. This experimental investigation measures detailed Nusselt number ratio distributions obtained from an array of V-shaped dimples (δ/D = 0.30). Although the V-shaped dimple array is derived from a traditional hemispherical dimple array, the V-shaped dimples are arranged in an in-line pattern. The resulting spacing of the V-shaped dimples is 3.2D in both the streamwise and spanwise directions. A single wide wall of a rectangular channel (AR = 3:1) is lined with V-shaped dimples. The channel Reynolds number ranges from 10,000–40,000. Detailed Nusselt number ratios are obtained using both a transient liquid crystal technique and a newly developed transient temperature sensitive paint (TSP) technique. Therefore, the TSP technique is not only validated against a baseline geometry (smooth channel), but it is also validated against a more established technique. Measurements indicate that the proposed V-shaped dimple design is a promising alternative to traditional ribs or hemispherical dimples. At lower Reynolds numbers, the V-shaped dimples display heat transfer and friction behavior similar to traditional dimples. However, as the Reynolds number increases to 30,000 and 40,000, secondary flows developed in the V-shaped concavities further enhance the heat transfer from the dimpled surface (similar to angled and V-shaped rib induced secondary flows). This additional enhancement is obtained with only a marginal increase in the pressure drop. Therefore, as the Reynolds number within the channel increases, the thermal performance also increases. While this trend has been confirmed with both the transient TSP and liquid crystal techniques, TSP is shown to have limited capabilities when acquiring highly resolved detailed heat transfer coefficient distributions.

The Method of Dynamic Reserves Prediction for a Constant Volume Gas Reservoir

2013 ◽  
Vol 275-277 ◽  
pp. 456-461
Author(s):  
Lei Zhang ◽  
Lai Bing Zhang ◽  
Bin Quan Jiang ◽  
Huan Liu
Keyword(s):  
Pressure Drop ◽  
Material Balance ◽  
Production Method ◽  
Gas Production ◽  
Constant Volume ◽  
Phase Method ◽  
Gas Reservoirs ◽  
Two Phase ◽  
Material Balance Method ◽  
Unit Pressure

The accurate prediction of the dynamic reserves of gas reservoirs is the important research content of the development of dynamic analysis of gas reservoirs. It is of great significance to the stable and safe production and the formulation of scientific and rational development programs of gas reservoirs. The production methods of dynamic reserves of gas reservoirs mainly include material balance method, unit pressure drop of gas production method and elastic two-phase method. To clarify the characteristics of these methods better, in this paper, we took two typeⅠwells of a constant volume gas reservoir as an example, the dynamic reserves of single well controlled were respectively calculated, and the results show that the order of the calculated volume of the dynamic reserves by using different methods is material balance method> unit pressure drop of gas production method >elastic two-phase method. Because the material balance method is a static method, unit pressure drop of gas production method and elastic two-phase method are dynamic methods, therefore, for typeⅠwells of constant volume gas reservoirs, when the gas wells reached the quasi-steady state, the elastic two-phase method is used to calculate the dynamic reserves, and when the gas wells didn’t reach the quasi-steady state, unit pressure drop of gas production method is used to calculate the dynamic reserves. The conclusion has some certain theoretical value for the prediction of dynamic reserves for constant volume gas reservoirs.

Logging Optimization and Data Analysis Enabling Bypass Pay Identification and Hydrocarbon Quantification with Advanced Pulsed Neutron Behind Casing

2021 ◽  
Author(s):  
Sviatoslav Iuras ◽  
Samira Ahmad ◽  
Chiara Cavalleri ◽  
Yernur Akashev
Keyword(s):  
Cross Section ◽  
Pore Space ◽  
High Energy ◽  
Elastic Cross Section ◽  
Gas Production ◽  
Donets Basin ◽  
Lithology Identification ◽  
Open Hole ◽  
Pulsed Neutron

Abstract Ukraine ranks the third largest gas reserves in Europe. Gas production is carried out mainly from the Dnieper-Donets Basin (DDB). A gradual decline in reserves is forcing Ukraine to actively search for possible sources to increase reserves by finding bypassed gas intervals in existing wells or exploration of new prospects. This paper describes 3 case studies, where advanced pulsed neutron logging technology has shown exceptional value in gas-bearing layer identification in different scenarios. The logging technology was applied for formation evaluation. The technology is based on the neutron interaction with the minerals and the fluids contained in the pore space. The logging tool combines measurements from multiple detectors and spacing for self-compensated neutron cross-capture section (sigma) and hydrogen index (HI), and the Fast Neutron Cross Section (FNXS) high-energy neutron elastic cross section rock property. Comprehensive capture and inelastic elemental spectroscopy are simultaneously recorded and processed to describe the elemental composition and the matrix properties, reducing the uncertainties related to drilling cuttings analysis, and overall, the petrophysical evaluation combined with other log outputs. The proposed methodology was tested in several wells, both in open hole and behind casing. In the study we present its application in three wells from different fields of the DDB. The log data acquisition and analysis were performed across several sandstone beds and carbonates formation with low porosities (<10%), in various combinations of casing and holes sizes. The results showed the robustness and effectiveness of using the advanced pulsed neutron logging (PNL) technologies in multiple cases: Case Study A: Enabling a standalone cased hole evaluation and highlighting new potential reservoir zones otherwise overlooked due to absence of open hole logs. Case Study B: Finding by-passed hydrocarbon intervals that were missed from log analysis based on conventional open hole logs for current field operator. Case Study C: Identifying gas saturated reservoirs and providing solid lithology identification that previously was questioned from drilling cuttings in an unconventional reservoir.

Challenging Catenary Coiled Tubing Thru Tubing Screen Deployment Operation Offshore Borneo

2021 ◽  
Author(s):  
Seng Wei Jong ◽  
Yee Tzen Yong ◽  
Yusri Azizan ◽  
Richard Hampson ◽  
Rudzaifi Adizamri Hj Abd Rani ◽  
...  
Keyword(s):  
Oil Wells ◽  
Well Control ◽  
Coiled Tubing ◽  
Open Hole ◽  
Catenary System ◽  
Offshore Oil ◽  
Gravel Pack ◽  
Emergency Measures

Abstract Production decline caused by sand ingress was observed on 2 offshore oil wells in Brunei waters. Both wells were completed with a sub-horizontal openhole gravel pack and were subsequently shut in as the produced sand would likely cause damage to the surface facilities. In an offshore environment with limited workspace, crane capacity and wells with low reservoir pressures, it was decided to intervene the wells using a catenary coiled tubing (CT) vessel. The intervention required was to clean out the sand build up in the wells and install thru-tubing (TT) sand screens along the entire gravel packed screen section. Nitrified clean out was necessary due to low reservoir pressures while using a specialized jetting nozzle to optimize turbulence and lift along the deviated section. In addition, a knockout pot was utilized to filter and accommodate the large quantity of sand returned. The long sections of screens required could not be accommodated inside the PCE stack resulting in the need for the operation to be conducted as an open hole deployment using nippleless plug and fluid weight as well control barrier. A portable modular crane was also installed to assist the deployment of long screen sections prior to RIH with CT. Further challenges that needed to be addressed were the emergency measures. As the operation was to be conducted using the catenary system, the requirement for an emergency disconnect between the vessel and platform during the long cleanout operations and open hole deployment needed to be considered as a necessary contingency. Additional shear seal BOPs, and emergency deployment bars were also prepared to ensure that the operation could be conducted safely and successfully.

Minimization of Negative Impact of Well Cementing on Productive Horizons by Utilization of Swellable Packers

2021 ◽  
Author(s):  
Mykhaylo Paduchak ◽  
Viktor Dudzych ◽  
Anatolii Boiko
Keyword(s):  
Negative Impact ◽  
Differential Pressure ◽  
High Rate ◽  
Donets Basin ◽  
Technical Solution ◽  
Negative Consequences ◽  
Well Completion ◽  
Stable Production ◽  
Geological Conditions ◽  
Gas Tight

Abstract Avoiding of negative impact of slurry contact with productive sections by utilization of swellable pakers well completion systems as a key solution for depleted reservoirs. Results are compared to previously used classic well completion method with production casing cementing The new method of the well completion is based on a long period and many wells operations within Svyrydivske field in Dnipro-Donets Basin (here and after DDB). Precise selection of hybrid, oil and water based elastomers and correct placement in the appropriate hole zones for water and sectional isolation together with oil based mud utilization during drilling have provided stable production in depleted reservoirs and have minimized negative consequences from water filtration. The results achieved and the well completion method are described in detail to allow readers to replicate all results in a comparable geological conditions in DDB. Current well completion method has a couple of outstanding results achieved: –well integrity barrier is based on sufficient differential pressure provided by swellable packers;–reliable long term water isolation of all detected water contained intervals;–the production sections are not polluted by slurry filtrated water;–increased production rate comparing to cemented wells;–no risks of slurry loss during well cementing. This technology has been successfully implemented in both vertical and deviated wells on 4.5″ (114.3 mm) casing OD, in the interval 5100-5450 meters, bottom hole temperature 120-135°C. The differential pressure provided by swellable packer is up to 10,000 PSI (68.9 MPa). Fluid reactive packers are ready to expand and isolate highly cavernous hole sections and keep differential pressure sustainably. To achieve the best results with this well completion method, it is also important to use reliable gas tight casing connections and know precise reservoir characteristics. That is why the technology is recommended to be customized for well known brownfield reservoirs with high rate of depletion. The main benefit of the well completion method is a proved and safe technical solution for mainly depleted deep gas and condensate deposits in DDB (Ukraine) with sensitive economics

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