Successful Case of Resin-Based Chemical Sand Consolidation as a Remedial Sand Control Treatment

2021 ◽  
Author(s):  
Antus Mahardhini ◽  
Putu Yudis ◽  
Izzad Abidiy ◽  
Yolani Bawono ◽  
Rico Pradityo
Keyword(s):  
Field Trials ◽  
Control Treatment ◽  
Sand Production ◽  
Hydrocarbon Production ◽  
Consolidation Treatment ◽  
The Past ◽  
East Kalimantan ◽  
Successful Case ◽  
Sand Control ◽  
Mahakam Delta

Abstract The Mahakam delta in east Kalimantan, Indonesia, yields gas as the main hydrocarbon production with giant reservoirs ranging from shallow to very deep zones. Reservoirs consists of clean sandstone with high permeability. Due to the field maturity, production gradually moved from the deep, consolidated zones into very shallow, unconsolidated zones. Sand production often causes significant problems at the surface when the well is online. The best approach to sand control is to keep it inside the reservoir, because it could create problems not only at surface but within the wellbore as well. Sand consolidation has been a common approach applied in Mahakam field for more than a decade. Several products have been utilized, including laboratory testing and field trials. The case history is based on a well that had been treated using 2 different sand consolidation products in the past, but both eventually produced inadequate results. Sand continued to break through after each treatment, hence the reserves could not be drained in full. Since the reservoir still had promising reserves, another remedial sand consolidation treatment was planned. This treatment was executed by utilizing a tension packer with a J-slot mechanism in order to focus injection of the resin into the zone of interest. Additionally, there was a challenge with another open zone above the subject interval. The remedial sand consolidation treatment using a resin-based chemical delivered excellent results. Even though this reservoir had been exposed to 2 different chemical treatments in the past, by using the resin-based sand consolidation product, the well was still able to be produced at target rates without sand production. In conclusion, resin-based sand consolidation solutions can unlock prolific reserves that may have been a significant challenge with traditional methods.

Extending Gravel Pack Carrier Fluid Performance in Highly Deviated Well for 7-Inch Gravel Pack Completion without Shunt Tube by Using High Grade Suspension Gravel Pack Fluid in Mahakam Offshore

2021 ◽  
Author(s):  
Putu Yudis ◽  
Doffie Cahyanto Santoso ◽  
Edo Tanujaya ◽  
Kristoforus Widyas Tokoh ◽  
Rahmat Sinaga ◽  
...  
Keyword(s):  
Control Method ◽  
Oil And Gas Industry ◽  
High Rate ◽  
Control Treatment ◽  
High Grade ◽  
Sand Production ◽  
Worst Case ◽  
Carrier Fluid ◽  
Sand Control ◽  
Gravel Pack

Abstract In unconsolidated sand reservoirs, proper sand control completion methods are necessary to help prevent reservoir sand production. Failure due to sand production from surface equipment damage to downhole equipment failures which can ultimately result in loss of well integrity and worst-case catastrophic failure. Gravel Packing is currently the most widely used sand control method for controlling sand production in the oil and gas industry to deliver a proppant filter in the annular space between an unconsolidated formation and a centralized integrated screen in front of target zones. Additional mechanical skin and proper proppant packing downhole are the most critical objective when implementing gravel packs as part of a completion operation. This paper presents a case history of Well SX that was designed as single-trip multi-zone completion 7-inch casing, S-shape well type, having 86 deg inclination along 1300 meters, 4 to 5-meter perforation range interval and 54 deg inclination in front of the reservoir with total depth of 3800 mMD. The well consists of 4 zones of interest which had previously been treated with a two-trip gravel pack system. While Well NX was designed as single-trip multi-zone completion in 7-inch casing, J-shape well type, 8-meter perforation interval and 84 deg inclination in front of the reservoir with total depth of 3300 mMD. The well consists of two zones of interest which had previously been treated with a single-trip gravel pack system. Both wells are in the Sisi-Nubi field offshore Mahakam on East Kalimantan Province of Borneo, Indonesia. This paper discusses the downhole completion design and operation as well as the changes to the gravel pack carrier which overcame challenges such as high friction in the 7" lower completion and the potential for an improper annular gravel pack due to the lack of shunt tubes in a highly deviated wellbore. In vertical wellbores, obtaining a complete annular pack is relatively easy to accomplish but in highly deviated wellbores, the annular gravel pack is more difficult to achieve and can contribute additional skin. Tibbles at al (2007) noted that installing a conventional gravel pack could result in skin values of 40 to 50, mostly due to poor proppant packing in perforation tunnels. Therefore, operator required to find a reliable gravel pack carrier fluid optimization for typical highly deviated wells to overcome the potential sand production issues by applying a single-trip multi-zone sand control system across both zones (without shunt tubes) along with the utilization of a high-grade xanthan biopolymer gravel pack carrier fluid. Laboratory testing was conducted to ensure that the gravel pack fluid could transport the sand to the sand control completion, large enough to allow for a complete annular pack and still allow the excess slurry to be circulated out of the hole. Electronic gravel pack simulations were performed to ensure that rate/pressure/sand concentration would allow for a complete gravel pack. All four zones in Both of Well SX and NX were successfully gravel packed with a high rate, relatively high sand concentration slurry. The well has not exhibited any sand production issues to date. The current production from both wells is above expectation and are comingled from the two primary zones. Multiple factors were considered during the design and operation of the sand control treatment. Those factors will be described in this paper, starting with candidate selection, completion strategy, operational challenges and treatment execution along with production monitoring of the well.

scholarly journals A review of experimental studies on sand screen selection for unconsolidated sandstone reservoirs

2020 ◽  
Vol 10 (4) ◽  
pp. 1675-1688
Author(s):  
Nur Aqilah Ahad ◽  
Morteza Jami ◽  
Stephen Tyson
Keyword(s):  
Experimental Studies ◽  
Experimental Tests ◽  
Cost Effective ◽  
Sand Production ◽  
Hydrocarbon Production ◽  
Sand Control ◽  
First Choice ◽  
Sandstone Reservoirs ◽  
The Cost ◽  
The Impact

AbstractSand production is a problem that affects hydrocarbon production from unconsolidated sandstone reservoirs. Several factors, such as the strength of the reservoir, its lithification and cementation and reduction in pore pressure, may cause sand to be separated from the rock and transported by hydrocarbons to the well. Producing sand commonly causes erosion and corrosion of downhole and surface equipment, leading to production interruptions and sometimes forces operators to shut-in wells. Several different methods of sand control are available to reduce the impact of sand production. The reviewed papers suggest that the most suitable methods for unconsolidated sandstone reservoirs are stand-alone screens and gravel packs. Because of the cost and complexity of gravel packs, stand-alone screens are usually the first choice. These screens have different geometries, and selection of the most suitable screen depends on the particle size distribution of the grains in the formation and other reservoir and production parameters. A screen retention test, run in a laboratory with screen samples and typical sands, is often used to ensure that the screen is suitable for the reservoir. This paper reviews the main causes of sand production, the properties of unconsolidated sandstones that predispose reservoirs to sand production problems and the selection criteria for the most suitable mitigation method. The process of selecting a screen using experimental screen retention tests is reviewed, and the limitations of these tests are also discussed. Some numerical simulations of experimental tests are also reviewed, since this represents a very cost-effective alternative to laboratory experiments.

Acaricide resistance in the red tick, Rhipicephalus evertsi Neumann.

1961 ◽  
Vol 51 (4) ◽  
pp. 755-764 ◽  
Author(s):  
G. B. Whitehead ◽  
J. A. F. Baker
Keyword(s):  
South Africa ◽  
Laboratory Experiments ◽  
Sodium Arsenite ◽  
Field Trials ◽  
Cross Resistance ◽  
Acaricide Resistance ◽  
The Past ◽  
High Degree

Early in 1959, observations on the farm Tayside, in the East London district of South Africa, suggested that populations of the ‘two-host’ red tick, Rhipicephalns evertsi Neum., were more difficult to control with toxaphene preparations than they had been in the past. Resistance to toxaphene was suspected, and both field and laboratory experiments were carried out to investigate this possibility. Field trials indicated an increase in tolerance by Tayside populations of the tick to toxaphene, γ BHC and dieldrin, but showed no increased tolerance to sodium arsenite or DDT. Similar results were obtained in laboratory experiments where Tayside adults were compared with those of other populations of the tick known to be sensitive to insecticides. Laboratory experiments with larvae indicated a high degree of resistance to toxaphene and γ BHC in the Tayside population, but no increased tolerance to sodium arsenite, Delnav, Sevin or DDT could be detected. This pattern of cross-resistance is similar to that occurring in resistant populations of Boophilus dccoloratus(Koch).

Pipeline Dent Management Program

2002 ◽  
Author(s):  
Scott D. Ironside ◽  
L. Blair Carroll
Keyword(s):  
Finite Element ◽  
Oil And Gas ◽  
Selection Process ◽  
Element Model ◽  
Field Trials ◽  
Management Program ◽  
Operating Conditions ◽  
Published Data ◽  
Element Analysis ◽  
The Past

Enbridge Pipelines Inc. operates the world’s longest and most complex liquids pipeline network. As part of Enbridge’s Integrity Management Program In-Line Inspections have been and will continue to be conducted on more than 15,000 km of pipeline. The Inspection Programs have included using the most technologically advanced geometry tools in the world to detect geometrical discontinuities such as ovality, dents, and buckles. During the past number of years, Enbridge Pipelines Inc. has been involved in developing a method of evaluating the suitability of dents in pipelines for continued service. The majority of the work involved the development of a method of modeling the stresses within a dent using Finite Element Analysis (FEA). The development and validation of this model was completed by Fleet Technology Limited (FTL) through several projects sponsored by Enbridge, which included field trials and comparisons to previously published data. This model combined with proven fracture mechanics theory provides a method of determining a predicted life of a dent based on either the past or future operating conditions of the pipeline. CSA Standard Z662 – Oil and Gas Pipeline Systems provides criteria for the acceptability of dents for continued service. There have been occurrences, however, where dents that meet the CSA acceptability criteria have experienced failure. The dent model is being used to help define shape characteristics in addition to dent depth, the only shape factor considered by CSA, which contribute to dent failure. The dent model has also been utilized to validate the accuracy of current In-Line Inspection techniques. Typically a dent will lose some of its shape as the overburden is lifted from the pipeline and after the indentor is removed. Often there can be a dramatic “re-rounding” that will occur. The work included comparing the re-rounded dent shapes from a Finite Element model simulating the removal of the constraint on the pipe to the measured dent profile from a mold of the dent taken in the field after it has been excavated. This provided a measure of the accuracy of the tool. This paper will provide an overview of Enbridge’s dent management program, a description of the dent selection process for the excavation program, and a detailed review of the ILI validation work.

scholarly journals A robust fuzzy logic-based model for predicting the critical total drawdown in sand production in oil and gas wells

PLoS ONE ◽  
2021 ◽  
Vol 16 (4) ◽  
pp. e0250466
Author(s):  
Fahd Saeed Alakbari ◽  
Mysara Eissa Mohyaldinn ◽  
Mohammed Abdalla Ayoub ◽  
Ali Samer Muhsan ◽  
Ibnelwaleed A. Hussein
Keyword(s):  
Fuzzy Logic ◽  
Correlation Coefficient ◽  
Oil And Gas ◽  
Maximum Error ◽  
Physical Parameters ◽  
Sand Production ◽  
Gas Reservoirs ◽  
The North ◽  
Sand Control ◽  
North Adriatic Sea

Sand management is essential for enhancing the production in oil and gas reservoirs. The critical total drawdown (CTD) is used as a reliable indicator of the onset of sand production; hence, its accurate prediction is very important. There are many published CTD prediction correlations in literature. However, the accuracy of most of these models is questionable. Therefore, further improvement in CTD prediction is needed for more effective and successful sand control. This article presents a robust and accurate fuzzy logic (FL) model for predicting the CTD. Literature on 23 wells of the North Adriatic Sea was used to develop the model. The used data were split into 70% training sets and 30% testing sets. Trend analysis was conducted to verify that the developed model follows the correct physical behavior trends of the input parameters. Some statistical analyses were performed to check the model’s reliability and accuracy as compared to the published correlations. The results demonstrated that the proposed FL model substantially outperforms the current published correlations and shows higher prediction accuracy. These results were verified using the highest correlation coefficient, the lowest average absolute percent relative error (AAPRE), the lowest maximum error (max. AAPRE), the lowest standard deviation (SD), and the lowest root mean square error (RMSE). Results showed that the lowest AAPRE is 8.6%, whereas the highest correlation coefficient is 0.9947. These values of AAPRE (<10%) indicate that the FL model could predicts the CTD more accurately than other published models (>20% AAPRE). Moreover, further analysis indicated the robustness of the FL model, because it follows the trends of all physical parameters affecting the CTD.

Temperature as a key factor for successful inoculation of soybean with Bradyrhizobium spp. under cool growing conditions in Belgium

2018 ◽  
Vol 156 (4) ◽  
pp. 493-503 ◽  
Author(s):  
J. Pannecoucque ◽  
S. Goormachtigh ◽  
J. Ceusters ◽  
J. Debode ◽  
C. Van Waes ◽  
...  
Keyword(s):  
Field Trials ◽  
Protein Yield ◽  
Control Treatment ◽  
Rhizobial Symbiosis ◽  
Key Factor ◽  
Growing Conditions ◽  
Set Up ◽  
Biological Nitrogen ◽  
Intermediate Performance

AbstractBacterial inoculation of soybean seeds to improve biological nitrogen fixation is a well-known practice to achieve higher seed and protein yield with reduced fertilization. The optimal inoculation strategy in temperate regions is unknown because soybeans are rarely cultivated under colder growing conditions. The aim of the present work was to determine the most suitable inoculation strategy for soybean cultivation in Belgium. Field trials were set up with four Bradyrhizobium inoculants (HiStick, Force 48, Biodoz and Optimize) at two locations over 2 years (2014–2015) and compared with a non-inoculated control treatment. In addition, HiStick was tested at three doses and Optimize at two time periods prior to sowing. Under Belgian conditions, all inoculants were effective in establishing rhizobial symbiosis, resulting in increased yield, protein content, protein yield and thousand-grain weight compared with the non-inoculated control. A single dose of HiStick was sufficient to establish symbiosis. Pre-inoculation with Optimize 2 weeks before sowing gave an intermediate performance for most parameters between the non-inoculated control treatment and inoculation with Optimize 24 h prior to sowing. Among the four products tested, Biodoz seemed the best product for inoculation under cool growing conditions. Based on the atpD gene, the bacterial strain of Biodoz showed complete similarity with Bradyrhizobium diazoefficiens, while strains of other products were identified as Bradyrhizobium japonicum. In vitro growing capacity of the Biodoz strain at 8 °C was higher compared with the other strains. Better cold adaptation of the Biodoz strain might be a possible explanation for the better performance of Biodoz in Belgium.

First Application Drilling New Wells with HWU in Swamp Environment, Mahakam Delta

2021 ◽  
Author(s):  
R. A. S Wijaya
Keyword(s):  
Drilling Rate ◽  
Shallow Gas ◽  
Field Development ◽  
Drilling Rig ◽  
East Kalimantan ◽  
Well Location ◽  
Shallow Wells ◽  
Drilling Unit ◽  
Mature Field ◽  
Mahakam Delta

Tunu is a mature giant gas and condensate field locate in Swamp Area on Mahakam Delta, East Kalimantan, Indonesia. The field has been in developed for more than 40 years and considered as a mature field. As mature field, finding an economic well has become more challenging nowadays. The deeper zone of Tunu (TMZ) has no longer been considered profitable to be produced and the focus is shifted more on the producing widespread shallow gas pocket located in the much shallower zone of Tunu (TSZ). Facing the challenge of marginal reserves in the mature field, Pertamina Hulu Mahakam (PHM) take two approaches of reducing well cost thus increase well economics, improving drilling efficiency and alternative drilling means. Continues improvement on drilling efficiency by batch drilling, maxi drill, maximizing offline activities and industrialization of one phase well architecture has significantly squeezed the well duration. The last achievement is completing shallow well in 2.125 days from average of 6.5 days in period of 2017-2019. Utilization of Swamp Barge Drilling Rig on swamp area had been started from the beginning of the field development in 1980. Having both lighter and smaller drilling unit as alternative drilling means will give opportunity of reducing daily drilling rate. Hydraulic Workover Unit (HWU) comes as the best alternative drilling means for swamp area. In addition, fewer and smaller footprint equipment requires smaller barges with purpose of less civil works to dredge the river and preparing well location. Drilling with HWU project has been implemented at Tunu area with 5 wells has been completed successfully and safely. HWU drilling concept considered as proven alternative drilling means for the future of shallow wells development.

Taming the Monster: Arresting Excessive Sand Production Problem in ARAMU037

2021 ◽  
Author(s):  
Emily Ako ◽  
Erasmus Nnanna ◽  
Odumodu Somtochukwu ◽  
Akinmade Moradeke
Keyword(s):  
North Sea ◽  
Niger Delta ◽  
Best Practice ◽  
Integrated Approach ◽  
Sand Production ◽  
Sand Control ◽  
Production Problem ◽  
Normal Production ◽  
The Way

Abstract Chemical Sand Consolidation (SCON) has been used as a means of downhole sand control in Niger Delta since the early 70s. The countries where SCON has been used include Nigeria (Niger Delta), Gabon (Gamba) and UK (North Sea). SCON provides grain-to-grain cementation and locks formation fines in place through the process of adsorption of the sand grains and subsequent polymerization of the resin at elevated well temperatures. The polymerized resin serves to consolidate the surfaces of the sand grain while retaining permeability through the pore spaces. In a typical Niger Delta asset, over 30% of the wells may be completed with SCON. A high percentage are still producing without failure since installation from1970s. Where the original SCON jobs have failed, re-consolidation has also been carried out successfully. Chemical Sand Consolidation development has evolved over the years from: Eposand 112A and B, Eposand 212A and B, Wellfix 2000, Wellfix 3000, Sandstop (resin based), Sandtrap 225, 350 & 500 (resin based) and lately Sandtrap 225,350, 500 (solvent based) and Sandtrap ABC (aqueous based). There have been mixed results experienced with the deployment of either of the latest recipes of SCON. This was due to the fact that the conventional deployment work procedure was followed with the tendency for one-size-fits-all approach to the treatment. This paper details the challenges faced with sand production in ARAMU037, the previous interventions and how an integrated approach to the design and delivery of the most recent intervention restored the way to normal production. The well has now produced for about 2 years with minimal interruption with the activity paying out in less than 6 months. The paper also recommends the best practice for remedial sand control especially for wells in mature assets.

One Phase Well OPW : Unlock Shallow Reservoir Efficient and Economically by Eliminating Surface Casing

2021 ◽  
Author(s):  
Irfan Hanif ◽  
Bramarandhito Sayogyo ◽  
R Riko ◽  
Praja Hadistira ◽  
Karina Sari
Keyword(s):  
Shallow Gas ◽  
Two Phase ◽  
East Kalimantan ◽  
Drilling Operations ◽  
The Common ◽  
Mature Field ◽  
The Cost ◽  
Mahakam Delta ◽  
Common Architecture ◽  
Drilling Time

Abstract Tunu is a mature giant gas and condensate field locate in Mahakam Delta, East Kalimantan, Indonesia. The field has been in development for almost 30 years and currently has been considered as a mature field where to put a state of an economic well has become more challenging nowadays. The deeper zone of Tunu has no longer been considered as profitable to be produced and the current focus is more on the widespread shallow gas pocket located in the much shallower zone of Tunu. One phase well is architecture without 9-5/8" surface casing. OPW is one-section drilling using a diverter mode from surface to TD without using BOP. Historical for OPW is began from 2018, where drilling reservoir section using diverter mode in two-phase. In 2018 also succeeded in performing perforated surface casing. Due successfully in drilling operation using diverter and perforated surface casing, in 2019 drilling trials for OPW were carried out. Until now, the OPW architecture has become one of the common architecture used in drilling operations as an optimization effort. Until December 2020 PHM has completed 15+ OPW wells. A general comparison of OPW and SLA well is at the cost of constructing a well of approximately 200,000 - 300,000 US$. The disadvantages of OPW wells are more expensive in the mud and cement section when using a 9-1/2" hole, but in terms of the duration, OPW drilling time is more efficient up to 2-3 days. If viewed from the integrity of the OPW wells, from 15 OPW wells that have been completed, only 2 of them have SCP.

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