A truly optimized completion requires a wide range of understanding and activities. Starting with a thorough understanding of the reservoir, each completion element must be fully addressed from connecting to the reservoir, to enhancing the reservoir through proper treatments, to conducting hydrocarbons to surface for optimal efficiency. By considering the cause-and-effect interactions between these activities, each individual process can be designed and performed better, ultimately delivering the best overall solution. This overarching philosophy is also fully applicable to perforated completions.
Providing a perforating solution that is truly optimized for the reservoir is challenging, requiring advanced laboratory testing capabilities, reservoir specific products and systems, robust analysis and modeling tools, and a thorough process to insure solutions are designed, executed, and reviewed for continuous improvement and optimization. Recent advances in in-situ perforation testing techniques provide significant insights into dynamic events during perforating as well as enabling more reservoir specific equipment designs. Furthermore, state-of-the-art computational models complement testing methods by correlating dynamic perforating events and inflow analysis to actual productivity. Numeric modeling techniques also allow results from lab testing to be better translated into field scale environments. And finally, rigorous procedures can be followed to practice this process across a wide variety of completion types to provide well optimized perforated completions.
This study will detail the techniques used to employ the philosophy, and multiple case histories of such applications with results and lessons learned. In these cases, a comprehensive consideration of the overall completion was critical in optimizing the perforating process. The use of laboratory testing, customized products and systems, integrated modeling and analysis tools, and a disciplined process have led to the successful application of this scientifically engineered philosophy. This unique perforating philosophy is also aimed towards integration with other completion methods like hydraulic fracturing & stimulation, sand control and management and above all, enhancing reservoir productivity.
Spyrou, Charidimos E. (Schlumberger) | La Rosa, Andres Pieve (Schlumberger) | Khataniar, Sanjoy K. (Schlumberger) | Uzoechina, Frank (Wintershall Holding GmbH) | Awemo, Kilian N. (DEA Deutsche Erdoel AG)
A pattern flood management method based on a streamline simulator was developed to support waterflood designs. The methodology was applied on a structurally complex oil field in the North German basin. Studies are being conducted to understand the potential for extending the current waterflood in this oil field. The objective of this study was to investigate if a conventional simulation-based waterflood design could be enhanced using streamline simulation.
An alternative to using streamline simulation could be the post-processing of streamlines based on outputs of a full-field finite difference (FD) simulation model. However, there are limitations to this approach, including robustness and time considerations, especially when multiple runs with field-scale reservoir models are required. The streamline simulator contains a pattern flood management algorithm designed for optimizing the performance of waterfloods using multiple value criteria. The algorithm continuously balances patterns during forecasting runs converging to optimal injection and production rates while honoring well and field production constraints. A unique set of pattern performance diagnostics are ancillary products, for example pattern efficiencies and leakage fractions.
The full-field FD dynamic model of the aforementioned oil field was adapted for the streamline simulator. Both simulation models delivered similar results at the field and well levels and matched historical observed data satisfactorily. The best pattern flood model converged on a rate schedule that led to a 4% increase in oil production, a 17% decrease in water production, and a 5% reduction in the water injection volumes over the best performance achieved using a conventional voidage replacement strategy in the FD model. These findings were validated by executing the full-field model on a FD simulator with the recommendations from the pattern flood simulation run. The streamline simulation runs executed about seven times faster. To investigate the well count optimization potential, rigorous analyses were performed on the pattern information produced by the enhanced runs. A 12.5% reduction in well count, in terms of injectors and producers, could be achieved, and the pattern flood management algorithm converged on a rate schedule that still led to an increase of 2.3% in oil production, a 22% decrease in water production, and a 10% reduction in injection volumes.
The streamline-based simulation study proved useful in improving the existing waterflood design. Speedup in runtime allowed ample investigations and analysis within a given time period. Detailed analysis of allocated rate schedules and pattern information across numerous forecast runs gave deeper insight on the problem. The study highlighted that any well pattern has associated with it an optimal rate-scheduling strategy. Hence, the two components are important aspects of any successful waterflood design. The recommended rate schedules are model based and hence subject to uncertainty, requiring updates as additional information becomes available over time.
In this study, a review of production performance of four existing horizontal producers equipped with Inflow Control Device (ICD) completions was conducted using 4-D dynamic modelling on a sandstone reservoir with high water mobility. The aim of this study was to investigate the optimum regulation degree across ICD completion i.e. the ratio of pressure drop across ICDs to the reservoir drawdown, suitable to delay water breakthrough, minimize water cut and achieve production balance.
A single wellbore model was built by populating rock and fluid properties in 3-D around the wellbore for each of the studied wells. The model was then calibrated to the measured production log flow profile and bottomhole pressure profile for the deployed ICD completion in each well. Thereafter, several ICD simulation cases were run at target rates for a production forecast of 4 years. An optimum ICD case for each well was selected on the basis of water breakthrough delay, water cut reduction and incremental oil gain.
The study results showed that there is a correlation between reservoir heterogeneity index, well productivity index (PI) and optimum regulation degree required across ICD to achieve longer water breakthrough delay and better water cut control. In general, high heterogeneity, high PI wells require higher regulation degree across ICD of close to one; medium heterogeneity, low PI require regulation degree across ICD of between 0.3 – 0.45 while low heterogeneity, low PI, require very low regulation degree of between 0.1 – 0.15. Based on study results, a new ICD design framework and correlation chart were developed. This framework was then applied to two newly drilled horizontal producers to test the applicability of the workflow in real time ICD design scenarios and positive results were achieved.
Given the significant number of ICD completions deployed yearly, this new ICD design framework would provide guidance on how much pressure drop across ICD is required during real time design for newly drilled or sidetrack wells and would ultimately ensure maximum short and long term benefits are derived from deployment of ICD completions.
Verma, Chandresh (Saudi Aramco) | ElKawass, Amir A. (Saudi Aramco) | Mehrdad, Nadem (Saudi Aramco) | ElDeeb, Tarek (Saudi Aramco) | Qazi, Muhammad Q. (Saudi Aramco) | Galaby, Amir (Schlumberger) | Salaheldin, Ahmed (Schlumberger) | Fakih, Abdulqawi Al (Schlumberger) | Osman, Ahmed (Schlumberger) | Hammoutene, Cherif (Schlumberger)
While ERD multi-lateral wells in a large Middle East field are typically drilled in six to seven well bore sections, drilling the 8.5-in curve and the 6.125-in lateral sections represents more than 50 % of the total time spent drilling the well. Challenges while drilling the curve section with a motor include difficulty transferring weight to the bit while sliding and differential sticking in the highly poros zones of gas cap. The laterals, which can extend up to 12,500 ft of reservoir contact, are characterized by medium to hard compacted carbonate formations with high stick and slip tendency. This represents several challenges for drill-bit design engineers given that aggressive cutting structures are preferred to generate good rate of penetration even though this often leads to high bottom-hole assembly vibration. Trajectory control, hole cleaning and long circulating hours also represent significant challenges.
This paper will present details of the engineering analysis performed to optimize both 8.5-in and 6.125-in wellbore sections.
For the curve section, the first step was to change the drill string from 5 in to 4 in which considerably reduced the time taken to change the string prior to drilling the laterals. This change of drill string was accompanied by the use of a rotary steerable system and a PDC bit. This was a combination that had never been implemented since the field discovery in 1968. These changes resulted in performance improvements in excess of 50 %.
For the laterals, the engineering analysis resulted in the need of a completely new bit design. The cutting structure was modified to provide a more aggressive bit to formation interaction, and the gauge contact with the formation was enhanced to maintain the bit and BHA stability. The resulting design broke the field rotary steerable ROP record by 28 %. The bit drilled the highest single run footage in the field (12,698 ft) at the highest ROP (96.93 ft/hr) with a rotary steerable system. This was further complemented by optimizing the drilling practices and well bore cleaning practices allowing the elimination of several conditioning trips within the long laterals which resulted in three days of savings in a three lateral well.
The paper will conclude with a discussion regarding the reduced injury exposure that resulted from changing the drill string earlier within the well and a review of further improvement opportunities.
Drilling activity in remote, complex environments has increased in Alaska as operators seek to combat falling production in existing wells and shift to commercialization of natural gas and condensates. The completion of these wells often requires coiled tubing (CT) intervention, whereby CT is used for various applications, including wellbore cleanout, milling, fishing, and acidizing operations. To complete multiple high-pressure wells in a remote field, an operator required a CT contingency to shift formation isolation valves.
A new collaborative approach was implemented in which the operator and CT service provider closely worked together on the technical job design from the onset of the project to optimize planning and execution. The planned intervention was part of a large project in which a single company provided most of the services. This allowed the CT service provider to work closely with the operator and third-party providers, such as the fluid supplier and completion equipment supplier, to complete key technical design elements, including CT string design, fluid design, and downhole tools selection. In this way, an integrated, fit-for-purpose solution was delivered to the operator.
Many key challenges were associated with this intervention. The biggest challenge was the absence of previous such experience in a well in Alaska where maximum allowable surface pressure (MASP) exceeded 8,500 psi. The intervention would require well control equipment and other pieces of treating equipment and downhole tools rated for 15,000 psi that were not readily available in Alaska. In addition to the well's high MASP (8,564 psi), other key challenges included being ready to perform a CT milling operation of a formation isolation valve in large casing (7�? in.) in an environment with 30-ppm H2S and 4.55% CO2 where ambient temperatures could drop as low as−50° F. A 2-in. CT string with a length of 19,000 ft was designed to provide sufficient weight on bit and overpull to complete all required contingency CT operations. A fluid system was designed to not only control the high pressure in the well but also be pumped through the CT string at circulating pressures that did not exceed the limits of the pipe. Furthermore, a test was completed prior to the mobilization of equipment to location to determine the optimal design for milling the formation isolation valve with CT.
This paper presents the job design and preparation processes completed for the first planned CT intervention contingency in Alaska, in addition to lessons learned that can be applied to future high-pressure CT operations requiring well control equipment rated to 15,000 psi.
During the last decade, inflow control device (ICD) technology has rapidly developed and widely been used in horizontal wells due to its effectiveness in flux equalization and mitigation of unwanted fluid breakthrough. An ICD completion achieves flux equalization and manages water breakthrough by introducing an extra pressure drop in the ICD and redistributing the drawdown across the sandface between high and low permeable intervals of a horizontal well. This additional pressure loss in the ICD completion will cause reduction of effective productivity of the well, in other words it will require lower flowing bottom-hole pressure for a well with ICD completion to produce the same liquid rate compared to a well with a barefoot completion. The higher the pressure drop across the ICD completion, the better will be the equalization effect and water mitigation. Subsequently, the reservoir pressure has to be used wisely during field development as expensive pressure maintenance programs are utilized in many fields as part of the field development plans.
This study tries to answer an important question: What should the optimum pressure regulation in an ICD completion be to realize the benefits of ICD without excessive reduction of well productivity? The effect of ICD regulation on flux equalization and well productivity reduction for various cases of well productivity index (PI) and permeability variation were studied through numerous static near wellbore simulation runs. Dynamic reservoir simulation was conducted to verify the results from the static simulation and dependence of the degree of flux equalization along the horizontal section on water breakthrough deferment and the oil recovery factor.
An ICD design workflow is presented, which can be used to select an optimum ICD design, which maximizes the benefits of ICD with the least reduction in well productivity. A trade-off chart between well productivity and the degree of influx equalization has been built, which helps to determine the optimum pressure drop across an ICD completion in the presence of various levels of permeability variation along the wellbore. This approach can provide quick and simple calculation for the required ICD strength or number of ICD joints along the wellbore to maximize recovery of hydrocarbons. A real field case is used to illustrate the effectiveness of this workflow for optimum ICD design.
In deepwater Gulf of Mexico, cement placement through coiled tubing (CT) has been proven over several decades to be a valuable, versatile, and cost-effective tool for the through-tubing plug and abandonment of depleted oil and gas producers. In this paper, several present-day recommendations and best practices in relation to CT cementing for well abandonment are described.
CT cementing is typically used for well abandonment when leaving part of the production tubing in place is deemed beneficial from an economic or operational risk standpoint. As demand for the reliable placement of permanent cement barriers during well abandonment continues to grow, the importance of optimal design methodology, laboratory practices, and placement techniques associated with CT cementing has also increased. For instance, one of the most important aspects is to design a thin yet stable cement slurry. In addition, thickening time tests must account for the time a slurry is in the CT reel at surface before travelling downhole. Fluid placement techniques should account for the use of any downhole tools and be adjusted accordingly.
In recent well abandonments, a high success rate in the placement of cement plugs through CT has been observed. The main contributor to this success is the consistent manner in which the best practices described in this paper were followed. These methodologies also include some that have slowly evolved over time. For example, during well abandonment, one procedure that appears to be gaining popularity in some situations is the running of inflatable cement retainers with the ball on seat. In regards to CT cementing, this has often resulted in modified strategies, with fluid placement techniques counteracting the inability to pump any fluids through the CT prior to setting the retainer.
This paper is based on several recent abandonment campaigns using an intervention vessel in the Gulf of Mexico in 2016. Throughout the course of these particular campaigns, a total of 32 cement plugs were placed through CT, all of which were successfully verified, thus avoiding costly remedial placement. Although different conditions and well-specific challenges can slightly alter the approach taken, there are several steadfast techniques that appear to be effective in the consistent delivery of desired results.
Decommissioning activity will increase in the next nine years with a predicted £1.3 billion spent on decommissioning of subsea pipelines and associated subsea infrastructure in the North Sea from 2014-2023 [REF 1]. Detailed preparation prior to the Cessation of Production (CoP) may significantly reduce this cost. Savings can be made during late in life operations on the platform and preliminary decommissioning planning. A Comparative Assessment tool assists the project team in selecting the most preferred decommissioning and abandonment option for subsea pipelines by using criteria such as safety, environmental factors, technical feasibility, economics and societal issues. These are then ranked by priority through matrix algebra.
Peng, C. (University of Science and Technology Beijing) | Guo, Q. S. (University of Science and Technology Beijing) | Zhang, Z. C. (University of Science and Technology Beijing) | Zhao, L. (University of Science and Technology Beijing) | Yan, Z. X. (University of Science and Technology Beijing)
ABSTRACT: With the increase of the slope height in open-pit mines, the contradiction between the mining safety and stripping quantity becomes progressively serious. According to the analysis and calculation, the original slope angle in Gaocun Iron mine is conservative. After engineering geological investigation and rock mechanical tests, three optimization schemes were proposed. FLAC3D numerical simulation software was used to analyze the slope stability by several indexes such as displacement and plastic zone. In addition, the safety factors were obtained according to the limit equilibrium method by Geo-slope software. Eventually, the final slope angle of the mine was determined. It showed that the optimized slope angle is improved by 3° compared with that of the former design on the whole, and the slope stability well meets the requirement of production.
There are a growing number of metal mines carrying on deep mining in our country, and the design of open pit slopes faces a dilemma in that situation: When the slope angle is too big, the steep slope will cause instability and failure, which is not conducive to the normal production of the mine; In contrast, the small angle will increase the stripped amount and the production costs significantly. To solve this problem, slope angle must be optimized on the premise of mining safety (Heok & Bray 1981, Duncan & Christopher 2005).
Gaocun pit of Nanshan Mining Co., Ltd., is a large open pit mine, whose ore production has reached 7 million tons per year with the total mining and stripping of 18 million tons. After entering the second phase of open pit mining, the north-south length of the stope expands from 780 m to 1500 m, and the east-west width expends from 575 m to 820 m. The highest level of open pit mining is up to +90 m and the bottom elevation is down to-186m. Under the conditions of high and steep slope mining, with mining depth increases, the contradiction between security and economic production is gradually highlighted. Therefore, slope design must be optimized to ensure the production safety and increase economic efficiency.
Fiber-optic sensing technology is the right technology for Permanent Reservoir Monitoring (PRM) applications due to significant advantages in reliability, system design and installation flexibility, and enhanced compatibility with future field development trends.
It is well known that fiber-optic technology is inherently a more reliable technology choice for underwater applications. This has been proven by long-term use within military applications and the telecommunications industry. The application of fiber-optic technology for PRM offers the proven reliability benefits long recognized by the telecommunications industry to the oil and gas industry. The use of fiber-optic sensing technology removes the electronics and electrical power requirements from the seabed and replaces it with completely electrically passive components, which can be interrogated from a platform, FPSO or from shore, using only optical signals. This eliminates the potential for electrical leakage and decreases the potential for mechanical water leak-induced failures in the underwater equipment. The improved reliability drives down the through-life operations and maintenance costs for PRM applications.
It is less well known that the inherent flexibility available with fiber-optic PRM systems generates significant additional value beyond the reliability advantage. Fiber-optic systems enable more flexible system design and layout solutions compared to electrical based alternatives. Greater design and layout flexibility translates into significant advantages during system installation, which can reduce the cost and risk of PRM projects. Advanced optical architectures and proprietary system design techniques generate an expanded range of layout and connection options, which can be used to optimize the system supply and installation solutions during an integrated PRM project planning process.
The authors conclude that PRM systems based on fiber-optic technology offer a better platform for the future due to a number of key advantages. Fiber-optic systems offer greater potential for cost-effective expansion, technology upgrade and cost reduction moving forward. The very low propagation loss intrinsic to fiber-optic technology makes it ideally suited to address a number of developing trends in offshore field development.
In this paper, the authors present examples of clear advantages in reliability, flexibility, expandability and suitability to address future trends for operators to consider when selecting a PRM system for 4D seismic monitoring. Based on these examples and evidence, the authors conclude that fiber-optic sensing is the technology of choice for PRM.