World's First Extension Pack with 7-in. Enhanced Single-Trip Multizone System: Success Case and Learning Points on the Installation and Treatment Design

Abstract Gravel packing in a multilayer reservoir during an infill development project requires treating each zone individually, one after the other, based on reservoir characterization. This paper discusses the installation of an enhanced 7-in. multizone system to achieve both technical and operational efficiency, and the lessons learned that enabled placement of an optimized high-rate water pack (HRWP) in the two lower zones and an extension pack in the uppermost zone. This new approach helps make multizone cased-hole gravel-pack (CHGP) completions a more technically viable and cost-effective solution. Conventional CHGPs are limited to either stack-pack completions, which can incur high cost because of the considerable rig time required for multizone operations, or alternate-path single-trip multizone completions that treat all the target zones simultaneously, with one pumping operation. However, this method does not allow for individual treatment to suit reservoir characterization. The enhanced 7-in. multizone system can significantly reduce well completion costs and pinpoint the gravel placement technique for each zone, without pump-rate limitations caused by excessive friction in the long interval system, and without any fiuid-loss issues after installation because of the modular sliding side-door (SSD) screen design feature. A sump packer run on wireline acts as a bottom isolation packer and as a depth reference for subsequent tubing-conveyed perforating (TCP) and wellbore cleanup (WBCU) operations. All three zones were covered by 12-gauge wire-wrapped modular screens furnished with blank pipe, packer extension, and straddled by two multizone isolation packers between the zones, with a retrievable sealbore gravel-pack packer at the top. The entire assembly was run in a single trip, therefore rig time optimization was achieved. The two lower zones were treated with HRWPs, while the top zone was treated with an extension pack. During circulation testing on the lowermost zone, high pumping pressure was recorded, and after thorough observation of both pumping parameters and tool configuration, it was determined that the reduced inner diameter (ID) in the shifter might have been a causal factor, thereby restricting the flow area. This was later addressed with the implementation of a perforated pup joint placed above the MKP shifting tool. The well was completed within the planned budget and time and successfully put on sand-free production, exceeding the field development planning (FDP) target. The enhanced 7-in. multizone system enabled the project team to beat the previous worldwide track record, which was an HRWP treatment only. As a result of proper fluid selection and rigorous laboratory testing, linear gel was used to transport 3 ppa of slurry at 10 bbl/min, resulting in a world-first extension pack with a 317-lbm/ft packing factor.

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A geomechanical approach for sanding risk assessment applied to three field cases for completion optimisation

The APPEA Journal ◽

10.1071/aj09040 ◽

2010 ◽

Vol 50 (1) ◽

pp. 623 ◽

Cited By ~ 1

Author(s):

Khalil Rahman ◽

Abbas Khaksar ◽

Toby Kayes

Keyword(s):

Decision Making ◽

Petroleum Industry ◽

Cost Effective ◽

Development Planning ◽

Control Measures ◽

Sand Production ◽

Field Development ◽

Well Completion ◽

Sand Control ◽

Production Prediction

Mitigation of sand production is increasingly becoming an important and challenging issue in the petroleum industry. This is because the increasing demand for oil and gas resources is forcing the industry to expand its production operations in more challenging unconsolidated reservoir rocks and depleted sandstones with more complex well completion architecture. A sand production prediction study is now often an integral part of an overall field development planning study to see if and when sand production will be an issue over the life of the field. The appropriate type of sand control measures and a cost-effective sand management strategy are adopted for the field depending on timing and the severity of predicted sand production. This paper presents a geomechanical modelling approach that integrates production or flow tests history with information from drilling data, well logs and rock mechanics tests. The approach has been applied to three fields in the Australasia region, all with different geological settings. The studies resulted in recommendations for three different well completion and sand control approaches. This highlights that there is no unique solution for sand production problems, and that a robust geomechanical model is capable of finding a field-specific solution considering in-situ stresses, rock strength, well trajectory, reservoir depletion, drawdown and perforation strategy. The approach results in cost-effective decision making for appropriate well/perforation trajectory, completion type (e.g. cased hole, openhole or liner completion), drawdown control or delayed sand control installation. This type of timely decision making often turns what may be perceived as an economically marginal field development scenario into a profitable project. This paper presents three case studies to provide well engineers with guidelines to understanding the principles and overall workflow involved in sand production prediction and minimisation of sand production risk by optimising completion type.

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SUB-SURFACE UNCERTAINTY IN OIL FIELDS: LEARNINGS FROM EARLY PRODUCTION OF LEGENDRE OIL FIELDS

The APPEA Journal ◽

10.1071/aj02021 ◽

2003 ◽

Vol 43 (1) ◽

pp. 401

Author(s):

R. Seggie ◽

F. Jamal ◽

A. Jones ◽

M. Lennane ◽

G. McFadzean ◽

...

Keyword(s):

Planning Process ◽

Development Planning ◽

Oil Field ◽

Production Performance ◽

Oil Fields ◽

High Rate ◽

Secondary Development ◽

North West ◽

Field Development ◽

Small Primary

The Legendre North and South Oil Fields (together referred to as the field) have been producing since May 2001 from high rate horizontal wells and had produced 18 MMBBL by end 2002. This represents about 45% of the proven and probable reserves for the field.Many pre-drill uncertainties remain. The exploration and development wells are located primarily along the crest of the structure, leaving significant gross rock volume uncertainty on the flanks of the field. Qualitative use of amplitudes provides some insight into the Legendre North Field but not the Legendre South Field where the imaging is poor. The development wells were drilled horizontally and did not intersect any fluid contacts.Early field life has brought some surprises, despite a rigorous assessment of uncertainty during the field development planning process. Higher than expected gas-oil ratios suggested a saturated oil with small primary gas caps, rather than the predicted under-saturated oil. Due to the larger than expected gas volumes, the gas reinjection system proved to have inadequate redundancy resulting in constrained production from the field. The pre-drill geological model has required significant changes to reflect the drilling and production results to date. The intra-field shales needed to be areally much smaller than predicted to explain well intersections and production performance. This is consistent with outcrop analogues.Surprises are common when an oil field is first developed and often continue to arise during secondary development phases. Learnings, in the context of subsurface uncertainty, from other oil fields in the greater North West Shelf are compared briefly to highlight the importance of managing uncertainty during field development planning. It is important to have design flexibility to enable facility adjustments to be made easily, early in field life.

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Bringing Flexibility and Automation to Well Testing Operations Through Wireless Telemetry - Case Study

10.4043/31275-ms ◽

2021 ◽

Author(s):

Elias Temer ◽

Deiveindran Subramaniam ◽

Yermek Kaipov ◽

Carlos Merino ◽

Vladimirovich Latvin ◽

...

Keyword(s):

Real Time ◽

Reservoir Characterization ◽

Time Window ◽

Weather Conditions ◽

Development Planning ◽

Testing Time ◽

Well Testing ◽

Well Test ◽

Real Time Control ◽

Field Development

Abstract Dynamic reservoir data are a key driver for operators to meet the forecasted production investments of their fields. However, many challenges during well testing, such as reduced exploration and capex budgets, complex geologic structures, and inclement weather conditions that reduce the well testing time window can prevent them from gathering critical reservoir characterization data needed to make more informed field development planning decisions. To overcome these challenges, a live, downhole reservoir testing platform enabled the most representative reservoir information in real time and connected more zones of interest in a single run for appraisal wells in the Sea of Okhotsk, Russia. This paper describes the test requirements, the prejob planning, and automated execution of wirelessly enabled operations that led to the successful completion of the well test campaign in very hostile conditions, a remote area, and restricted period. The use of a telemetry system to well testing in seven zones enabled real-time control of critical downhole equipment and acquired data at surface, which in turn was transmitted to the operator's office in town in real time. Various operation examples will be discussed to demonstrate how automated data acquisition and downhole operations control has been used to optimize operations by both the service company and the operator.

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Successful Application of Managed Pressure Drilling and Cementing in Naturally Fractured Carbonates Environment of Prohorovskoe Exploration Well

10.2118/206449-ms ◽

2021 ◽

Author(s):

Dmitry Krivolapov ◽

Taras Soroka ◽

Artem Polyarush ◽

Denis Lobastov ◽

Viktor Balalaev ◽

...

Keyword(s):

Health Hazard ◽

Development Stage ◽

Komi Republic ◽

Lessons Learned ◽

High Hydrogen ◽

Well Control ◽

Core Drilling ◽

Field Development ◽

Well Completion ◽

Managed Pressure Drilling

Abstract This technical paper provides the result of utilizing MPD technology for drilling and cementing a 127 mm production liner withing the Zadonian horizon D3zd in an exploratory well of the Prohorovskoe field. The previous wells drilled with a conventional approach in the field had complicated issues such as circulation losses and well control. It was complexified with high hydrogen disulfide concentration in reservoir oil which was a health hazard to a site personnel. As a result, to eliminate all complications, resources and operational time were needed. To prevent and eliminate complications in a long wall, core drilling and well completion, managed pressure drilling (MPD) and cementing technology with semi-automatic control system was applied. The project is unique as such complicated jobs with the core drilling and cementing with MPD were executed for the first time in The Komi Republic. MPD approach allowed to figure out bottomhole safe conditions and maintain ECD within a required pressure window. It is necessary to notice that a part of the section was core drilled. Knowing the window between pore and fracture pressures safety limits, a run-in-the-hole design with further cementing job was optimized. The execution was done flawlessly without circulation losses and well control issues. In comparison to a previous well in the Prohorovskoe field, MPD allowed to shorten loss circulated mud volume from 2 2215 m3 to 0 m3 and avoid non-productive time. Through accomplished goals and lessons learned, new grounds to well owners and well services in a field development stage are broken.

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Maximizing Co-Activity Operation and Mastering Drilling Practice as Effective Strategies for Marginal Field Development

10.2118/205767-ms ◽

2021 ◽

Author(s):

Praja Hadistira ◽

Bintang Kusuma Yuda ◽

Setiohadi Setiohadi ◽

Muhammad Alfianoor Yudhatama ◽

Ryan Aditia Wijaya ◽

...

Keyword(s):

Development Project ◽

Time Saving ◽

Field Development ◽

Effective Strategies ◽

Well Completion ◽

Deep Well ◽

Drilling Parameters ◽

Safety Incident ◽

Mature Field ◽

Marginal Field

Abstract A limited remaining reserve is one of the challenges commonly found in mature field development. Swamp fields in the Mahakam block is an example of mature field development which leads to a marginal operation. Delivering wells more economically is one of the key points to survive during those conditions. Rig operation with a significant daily expenditure could be a way for improvement to yield economic wells. In general, an efficient rig operation would deliver wells in a shorter duration and at a lower cost. In order to lessen the well duration, two aspects could be improved: performing co-activity operation to shorten the horizontal time (preparation) and mastering drilling practices to shorten the vertical time (drilling). In the co-activity operations aspect, various initiatives have been implemented, such as rigless operations, batch drilling, and offline or simultaneous activities. While in the drilling practices aspect, drilling parameters, bit design, connection practice, and team motivation were the areas that have been improved. This paper will elaborate further on those initiatives. Implementing massive co-activity operations and the best drilling practices have demonstrated a significant time saving of 24% for the shallow well (final depth around 1800 m) and 27% for the deep well (final depth around 4300 m) in the block. These practices have also made a new record of the fastest well completion in 2.17 days and the highest drilling ROP for 141 m/hour with drilling 2303 m in the first 24 hours. The record of most drilled length in 24 hours is the world best performance of RSS BHA as per Directional Driller Company worldwide record. As a result, the 2020 average cost of the shallow well was 2.6 MUSD while the deep well was 4.1 MUSD. Those massive co-activity operations and drilling practices have been properly executed since 2019 without any safety incident and related NPT. The positive results have helped the development project to survive in marginal conditions.

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Lessons Learned from the First Chemical Sand Consolidation in Zawtika Field

10.2118/201045-ms ◽

2021 ◽

Author(s):

Wiwat Wiwatanapataphee ◽

Thanita Kiatrabile ◽

Pipat Lilaprathuang ◽

Noppanan Nopsiri ◽

Panyawadee Kritsanamontri

Keyword(s):

Control Method ◽

Cost Effective ◽

Lessons Learned ◽

Candidate Selection ◽

High Rate ◽

Operation Performance ◽

Coiled Tubing ◽

Cost Effective Method ◽

Sand Control ◽

Gravel Pack

Abstract The conventional gravel pack sand control completion (High Rate Water Pack / Extension Pack) was the primary sand control method for PTTEPI, Myanmar Zawtika field since 2014 for more than 80 wells. Although the completion cost of gravel pack sand control was dramatically reduced around 75 percent due to the operation performance improvement along 5 years, the further cost reduction still mandatory to make the future development phase feasible. In order to tackle the well economy challenge, several alternative sand control completion designs were reviewed with the existing Zawtika subsurface information. The Chemical Sand Consolidation (CSC) or resin which is cost-effective method to control the sand production with injected chemicals is selected to be tested in 3 candidate wells. Therefore, the first trial campaign of CSC was performed with the Coiled Tubing Unit (CTU) in March to May 2019 with positive campaign results. The operation program and lesson learned were captured in this paper for future improvement in term of well candidate selection, operation planning and execution. The three monobore completion wells were treated with the CSC. The results positively showed that the higher sand-free rates can be achieved. The operation steps consist of 1) Perform sand cleanout to existing perforation interval or perforate the new formation interval. 2) Pumping pre-flush chemical to conditioning the formation to accept the resin 3) Pumping resin to coating on formation grain sand 4) Pumping the post-flush chemical to remove an excess resin from sand 5) Shut in the well to wait for resin curing before open back to production. However, throughout the campaign, there were several lessons learned, which will be required for future cost and time optimization. In operational view, the proper candidate selection shall avoid operational difficulties e.g. available rathole. As well, detailed operation plan and job design will result in effective CSC jobs. For instance, the coil tubing packer is suggested for better resin placement in the formation. Moreover, accommodation arrangement (either barge or additional vessel) and logistics management still have room for improvement. These 3 wells are the evidences of the successful applications in Zawtika field. With good planning, lesson learned and further optimization, this CSC method can be beneficial for existing monobore wells, which required sand control and also will be the alternative sand control method for upcoming development phases. This CSC will be able to increase project economic and also unlock the marginal reservoirs those will not justify the higher cost of conventional gravel pack.

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Integrated Subsurface Study for Gas-Oil Communicating Reservoirs: From Structural Synthesis to Optimum Co-FDP

10.2118/208044-ms ◽

2021 ◽

Author(s):

Mohamad Yousef Alklih ◽

Andi Ahmad Salahuddin ◽

Karem Alejandra Khan ◽

Nidhal Mohamed Aljneibi ◽

Coriolan Rat ◽

...

Keyword(s):

Decision Making ◽

Reservoir Characterization ◽

Development Planning ◽

Co2 Injection ◽

Oil Reservoir ◽

Discounted Cash Flow ◽

Field Development ◽

Development Scenarios ◽

Pressure Depletion ◽

Field Management

Abstract This paper presents an integrated subsurface study that focuses on delivering field development planning of two reservoirs via comprehensive reservoir characterization workflows. The upper gas reservoir and lower oil reservoir are in communication across a major fault in the crest area of the structure. Gas from the upper reservoir, which is not under development, is being produced along with some oil producers from the oil reservoir as per acquired surveillance data. Pressure depletion is observed in observer wells of the upper reservoir, which substantiate both reservoirs communication. The oil reservoir is on production since 1994, under miscible hydrocarbon water alternating gas injection (HCWAG) and carbon dioxide (CO2) injection. The currently implemented development plan has been facing several complexities and challenges including, but not limited to, maintaining miscibility conditions, sustainability of production and injection in view of reservoirs communication, reservoir modeling challenges, suitability of monitoring strategy, associated operating costs and expansion of field development in newly appraised areas. In this study, an assessment of multiple alternative field development scenarios was conducted; with an aim to tackle field management and reservoir challenges. It commenced by a comprehensive synthesis of seismic, petrophysical (including extensive core characterizations), geological, production and reservoir engineering data to ensure data adequacy and effectiveness for development planning. The process was followed by evaluation of the historical reservoir management, HCWAG and CO2 injection practices using advanced analytics to identify areas for improvement and accelerate decision making process. The identified areas of improvement were incorporated into a dynamic model via diverse set of field management logics to screen wide range of scenarios. In the final step, the optimal scenarios were selected, in line of having strong economic indicators, honoring operational constraints, corporate business plan and strategic objectives. The comprehensive and flexible field management logic was set up to target different challenges and was used to extensively screen hundreds of different field development scenarios varying several parameters. Examples of such parameters are WAG ratio, injection pressures for both water/gas and CO2, cycle duration, well placement, reservoir production and injection guidelines, different co-development production schemes coupled with static and dynamic uncertainty properties against incremental oil production and discounted cash flow. The simulation results were analyzed using standardized approach where a number of key indicators was cross-referenced to produce optimal field development scenarios with regards to co-development effect of both reservoirs, miscibility conditions, balanced pressure depletion, harmonized sweep as well as robust discounted cash flow. Strong management support, multi-disciplinary data integration, agility of decision making and revisions in a controlled timeframe are considered as the key pillars for success of this study. The adopted workflow covers subsurface modeling aspects from A-Z and following reservoir characterization and modeling best practices. The methodology applied in this study uses an integrated subsurface structured approach to tackle reservoirs challenges and co-development, generate alternative development options leveraging on data analytics techniques and advanced field management strategies.

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