An inventive application for Roller Cone (TCI) and Polycrystalline Diamond Compact (PDC) bits (all sizes) that involves reusing the bits in future wells for similar well design types. With factory drilling being carried out in one of the Gas field (among other areas in gas) with over 50 runs a year provides an excellent opportunity to utilize rerun bits, both TCI and PDC, that have a 90-95% life remaining. Using this approach provides an effective and efficient way of cost saving during drilling.
While the cost of new bits in the country is very high compared to markets outside, mainly due to logistics issues with recent and continuous enhancements in bit designs, it makes complete sense to reuse these bits; especially when a huge inventory is available due to so many rigs drilling the similar type well designs in one or similar gas fields. The main criterion is to keep a track of all sizes of bits used on all gas rigs in the area and in the tool house (warehouse). Often, a particular size bit, either TCI or PDC, is used to drill a very short interval in a particular section due to a technical reason for the bit in the well being pulled out of hole, and is almost in brand new condition. Having an up-to-date inventory of these bits from the gas rigs, the tool house, and bit vendors makes it easy to identify such bits and utilize them in new wells, which provides significant cost savings.
Using the rerun bit approach immediately takes the bit cost for that particular hole section to 0$ and so we can achieve additional drilling optimization by utilizing a mud motor in that section, i.e., 12-in., 8-3/8 in., or 5-7/8 in., and further increasing the rate of penetration (ROP) by maintaining the same cost/ft ($/ft) in the section and even breaking bit record runs. In the last few wells it has been evident that by using this approach, the cost/ft for the 12-in. section drilling in the Gas Field field is seen as low as 52% of the new bit for the same year; providing a benchmark for the field. This would not have been possible without utilizing the rerun bits from previous wells. This approach is proving to be very beneficial. As a result of a number of these TCI and PDC bits available in reusable condition as a result of a large number of wells drilled every year in gas fields, significant cost savings have been achieved, which translates into millions of dollars in savings.
The rerun bits have substantial advantages over the new bits, primarily due to cost savings and enhanced bit designs with high durability and bit life over the last decade. For particular application in gas drilling, it is clear that having a large inventory of rerun bits available for almost all hole sizes will enable drilling cost optimization.
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.
Al-Ansari, Adel (Saudi Aramco) | Parra, Carlos (Saudi Aramco) | Abahussain, Abdullah (Saudi Aramco) | Abuhamed, Amr M. (Saudi Aramco) | Pino, Rafael (Saudi Aramco) | El Bialy, Moustafa (Halliburton) | Mohamed, HadjSadok (Halliburton) | Lopez, Carlos (Halliburton)
A properly designed reservoir drilling fluid and precise control of its properties are essential to prevent formation damage issues that hamper production. An essential prerequisite for a reservoir drilling fluid are nondamaging specialty products and reduced fines and fluids invasion. This paper describes the case history of two deep gas wells in Saudi Arabia, one well showed impaired production due to screens plugging and was put on workover drilling operations whereas the other well was a regular development well. The offset data showed differential sticking, partial losses and tight spots while drilling the 8⅜ and 5⅞ in. hole sections.
The well reservoir data including the bottom hole-temperature – 300°F, permeability – roughly 10 to 20 micron pore throats and lithology – sandstone intercalated with shale, for the reservoir section were determined from offset analysis. Extensive lab testing was performed with nondamaging specialty and optimized PSD for minimized fine and fluids invasion. This engineered fluid was used to drill a 5⅞ in. vertical side track of ± 300 ft for the workover well whereas on the regular development well about ± 400 ft of the 5⅞ in. section was drilled. The fluid was continuously monitored for PSD at the rig along with the particle plugging test for fluid loss control. The hole cleaning and equivalent circulating density was monitored and programmed with a proprietary hydraulics software. All the fluid properties were determined to be within planned range. The wells were drilled without any of the offset problems as discussed above followed by running the 41/2 in. conventional sand screens to the bottom without any issue. Initial flowback production testing was performed on the workover well, which took 8 hours as compared to the usual 48 hours in the offset wells. The BS&W (basic sediment and water) from day 1 of production was 9% as compared to the 25% observed in the offset wells. The gas production rate was 200% more than was expected as per the offset information.
This paper shows the successful use of reservoir drill-in fluid on two gas wells: one was a workover well and another a regular well. The abstract presents a mutual approach between Halliburton and Saudi Aramco to address the issue of minimizing formation damage and mitigating differential sticking. Offset well data learnings, optimized PSD design, monitoring at the rig site, and the use of nondamaging specialty products delivered production optimization.
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.
Mallick, Tanmay (Shell India Markets Private Limited) | Garg, Ashutosh (Shell India Markets Private Limited) | Choudhary, Manish (Shell India Markets Private Limited) | Nair, Saritha (Shell India Markets Private Limited) | Pal, Sabyasachi (Shell India Markets Private Limited) | Jana, Debadrita (Shell India Markets Private Limited) | Singh, Abhinav (Shell India Markets Private Limited) | Goudswaard, Jeroen (Shell India Markets Private Limited) | Faulkner, Andrew (Shell India Markets Private Limited) | Salakhetdinov, Ravil (Shell India Markets Private Limited)
A new seismic and quantitative reinterpretation was carried out for a brownfield in Western Desert, Egypt to improve depth predictability, de-risk appraisal well locations and to better understand producer-injector connectivity.
The study field is located in the Western Desert, Onshore Egypt and comprises of Upper Cretaceous tidal channel systems across four key reservoir levels where sand thicknesses range from 2 to 15 m. The field was discovered in 1993 but development drilling only commenced in 2008. The last integrated field study was performed in 2012. The analysis of wells drilled post-2012 indicated that there is a considerable depth difference along the flanks of the structure between seismic predicted depths and actual well tops (>50 m). The fault interpretation also required a re-look so as to reduce the lateral uncertainty of the main boundary fault and explain the lack of injection response in some areas of the field. This necessitated an update of seismic interpretation, static and dynamic models. A new interpretation could help identify attic volume upsides and help mature new appraisal and producer-injector locations. Further work was also proposed to test the feasibility of using seismic inversion for facies discrimination.
The available Pre-Stack Depth Migration (PreSDM) data was re-interpreted as part of the project. The fault interpretations were quality checked using Semblance/Dip maps, sand box models and wherever possible, were tied to the fault cuts seen in previously drilled wells. The time horizon correlation and seismic polarity were verified and were also cross-checked with the P-Impedance volume before being used in the static modelling workflow. The PreSDM Interval velocity model was used for depth conversion, where an anisotropy correction was applied to tie the wells. Vok and Polynomial methods were also applied, which in turn were used to derive depth uncertainty estimates. The update in the main bounding fault interpretation generated new appraisal locations in the deeper levels. The new interpretation was tested against the results from the latest drilling campaign in the field, and nine out of ten wells were within the one standard deviation uncertainty range.
Simultaneous inversion of the seismic data was also carried out as part of the project using the acoustic, shear and density data from 6 wells over the field. The inverted P-Impedance and S-Impedance were converted to Net to Gross (NtG), and were checked against the remaining 24 wells, which helped in validating the property cubes.
Forward wedge modelling suggested that individual sands of less than 15 m thickness would not be resolved from seismic due to seismic bandwidth limitations. Still, a review of inversion data together with geological insights and dynamic data helped to identify the high NtG areas across the reservoirs.
The integrated interpretation of inverted volumes with well and production data resulted in new insights into the field and helped to mature new appraisal and development well locations.
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.
The ability to drill wells in high temperature formations is limited by the temperature specification of the available drilling tools. Most drilling tools currently have a temperature rating of 150°C, and there is an ongoing effort to develop tools with a higher temperature rating. A parallel effort is to develop the modeling capability to simulate the complex downhole temperature environment, to allow engineer to understand the temperature effect on drilling operation and better manage the temperature-related risks.
Many high temperature wells are planned in an extremely conservative manner. The engineer will rely on the formation temperature measured in offset wells to determine temperature gradient of the planned well. This temperature gradient will be used as a reference for all aspects of the well design, including drilling tools selection, cementing design, etc. In reality, there are many factors which affect the actual downhole temperature experienced by the tools. There is a complex interaction between heating from the formation, drilling fluid circulation, and the mechanical action of drilling tools. There are many forms of energy loss contributing to the downhole temperature, such as mechanical friction, rock cutting, and fluid friction.
A new state-of-the-art dynamic temperature model is developed to simulate downhole conditions in order to precisely predict downhole temperatures. This paper will explain the development of dynamic temperature modeling and how the model being used to plan high temperature well. The paper will also present several case studies where the modeling was used on planning high temperature well and comparison between model results and actual downhole temperature measurements.
A significant percentage of all ESP failures are electrical failures and this becomes even more noteworthy in harsh, high temperature applications such as Steam Assisted Gravity Drainage (SAGD). For this reason, it is extremely important to continue the enhancement of ESP motor technologies that are specifically designed to address the challenging and unique SAGD environments that include wide bottom hole temperature ranges, abrasives and gas rich fluids. Through experience and testing, it has been learned that for these types of applications it imperative to design not only to a high temperature limit, but also to withstand extreme temperature cycles experienced on steam injection facility shutdown. A combination of historic evidence with controlled laboratory evidence yielded improvement areas for a new high-temperature ESP motor development. The new high ultra-temperature motor breaks paradigms and opens a new generation of motors that looks towards above 300 C downhole temperatures. This paper will review the performance of the motor at Suncor's Firebag SAGD field where 92 units have been installed since January 2015 in bottom hole (BHT) temperatures reaching 240 C. Description of the laboratory qualification, major design characteristics and field results will also be discussed on the paper.
Al-Houti, Naser (Kuwait Oil Company) | Al-Othman, Mohammad (Kuwait Oil Company) | Al-Qassar, Khalid (Kuwait Oil Company) | Al-Ebrahim, Ahmed (Kuwait Oil Company) | Matar, Khaled (Halliburton) | Al Hamad, Abdulla (Halliburton)
This paper presents the application of a unique gelling system for perforation shut-off operations that can help reduce operational time by 50% and can also be used as an effective water- and gas-migration control agent. The system combines a conformance sealant (based on an organically crosslinked polymer) with non-cementious particulates. The particulates provide leak-off control, which leads to shallow matrix penetration of the sealant. The filtrate from the leakoff is thermally activated and, as a result, forms a three-dimensional (3-D) gel structure that effectively seals the targeted interval after exposure to the bottomhole temperature (BHT).
The traditional method for recompleting wells into newer layers, after the current producing zones have reached their economic limit, involves several steps. The first step is to squeeze off the existing unwanted perforations using cement, drill out the cement across the perforations, and then pressure test the squeezed zones to help ensure an effective perforation seal has been achieved. The new zones are then perforated and completed for production. The entire operation can require four or more days of rig time, depending on the success of the cement squeeze. In cases of cement failure, the required time can extend to over one week. Common challenges associated with cement-squeeze operations include leaky perforations, fluid migration (gas or liquid) behind the pipe, or compromises in the completion. Attempts to remediate these issues must be repeated until all objectives are met.
The new perforation plugging system can be bullheaded into the well (spotted at a desired location in the wellbore), allowing for easy placement and calculation of the treatment volume. The limited and controlled leakoff into the matrix during the squeeze results in a controlled depth of invasion, which allows for future re-perforation of hydrocarbon-producing zones. The system can be easily washed out of the wellbore, unlike cement, which must be drilled out. The temperature range of the particle-gel system is 60 to 350°F, which makes it versatile.
To date, more than 500 operations have been performed with this system globally. This paper presents the results obtained from laboratory evaluations, the methodology of the treatment designs, and four case histories from Kuwait. A salient case is the successful use of the sealant/particulate system, resulting in shutting off all perforations after six failed cement-squeeze operations.
The prospect of reducing the required time to perform remedial cement-squeeze operations by 50%, as well as the ability to repair casing leaks and seal off thief zones, make this sealant/particulate system a valuable alternative to standard cement-squeeze operations.