An essential element for business success is to secure the best quality services from external providers at the lowest possible cost, which is a challenge not only for operating companies but also for service providers. This challenge is becoming more important for D&WO business, which is a major services consumer. NOCs strive to create a competitive and fair environment to encourage long-term business partnerships with service providers through a transparent process to assign more than 13 D&WO services.
A new process put into practice in the last 2 years, objectively evaluates service providers based on measurable criteria that include the pricing schema, historical performance, HSE compliance, and nationalization compliance of all providers against their contractual obligations. To assure the integrity of the process, an application was developed to fully automate the process, starting with the collection of data from its original sources to evaluate the service providers, through the electronic approval of the final assignment by management.
The application, Automated Services Assignment System (ASAS), provides different functionalities that allow seamless integration of different data sources like performance data from drilling rig morning reports and rig activity scheduling from a corporate database. It evaluates and ranks service providers automatically and provides an automated workflow for approving the services assignment based on a hybrid business model (standard process, service packaging, or lump sum turnkey), and allowing the adoption of additional business requirements during the execution phase through automated change request functionality.
The process and the application enabled D&WO organizations to respond to dynamic changes in their business by running as many scenarios as needed to identify the best business approach, with potential cost savings up to 15 percent (initial rough estimate). Effective management of the process delivers time savings up to 40 percent, compared to the manual process.
Implementing multidimensional evaluation criteria strengthens the credibility and integrity of the process compared to evaluations done based upon single criterion, such as cost or performance. In addition, this automated system combines three different business models seamlessly; capitalizes on corporate official records for drilling operations, HSE, and rig schedule; and enforces comprehensive business rules.
Smith, Chris (Condor Petroleum Inc.) | Dehghani, Ali (Condor Petroleum Inc.) | Hatcher, W. B. (Condor Petroleum Inc.) | Mukhambetpaizov, Yesset (Condor Petroleum Inc.) | Askarov, Bakhtiyar (Condor Petroleum Inc.) | Burg, George (Burg GeoConsulting Inc.)
This Paper describes the challenges and successful application of Inflow Control Devices ("ICDs") combined with sand control screens for horizontal wells. The ICDs were installed to reduce water and gas coning at the Shoba field. Shoba was the first field in Kazakhstan to use ICD technology and the first field in the Pre-Caspian basin where shallow horizontal wells were drilled.
The Shoba field is located within the Zharkamys West 1 block in western Kazakhstan. The Triassic-age sandstone reservoir consists of sweet 34° API oil. The field was initially developed with seven (7) vertical wells. However, high vertical permeability, in combination with high gas and water mobility, resulted in excessive gas and water breakthrough that marginalized the field's economics. An alternate development plan utilizing ICDs and horizontal well technologies was necessary to enhance field commerciality. This project presented numerous challenges. Since the field is relatively small and wells of this type had not been drilled in the region, there was little opportunity for a "learning curve", no margin for excessive cost over-runs, or well failures. Some of the issues overcome that will be presented: ICD design and selection considerations Wellbore instability for shallow horizontal wells Isolation of a sizable gas cap above the productive oil zone Plugging of the sand control screens during their placement Premature gas or water coning
ICD design and selection considerations
Wellbore instability for shallow horizontal wells
Isolation of a sizable gas cap above the productive oil zone
Plugging of the sand control screens during their placement
Premature gas or water coning
Shoba's first two horizontal wells were drilled and completed on time and under budget, with early results confirming a reduction of water and gas coning. A significant increase in production rates has also been realized. Given the project's initial success, additional horizontal well development drilling continues.
A new concept "local down-hole tubular model", which provides a more sophisticated description of tubular string deflection from local perspective, is proposed to overcome the shortcomings of the conventional integral model. The coupling effects of three factors including wellbore configuration, buckling mode and connector are studied in the local model. Firstly, an equivalent beam-column model is proposed to reduce arbitrary wellbores except vertical wellbores into horizontal wellbores. Thus, the tubular behaviors in arbitrary wellbores can be simplified into that in vertical and horizontal wellbores. Secondly, the two-dimensional (2D) lateral deflection, three-dimensional (3D) inter-helical buckling and intra-helical buckling of tubular strings with and without connectors under four contact cases, namely no contact, point contact, wrap contact and full contact, constrained in horizontal and vertical wellbores are studied. Meanwhile, the fitting formulae which depict the effects of connectors on critical buckling loads, contact forces and bending moments are calculated. At last, the integral model is further amended based on the results from the local model. The results show that the effect of wellbore configuration can be equivalent to additional tubular string weight. Connector parameters are closely related to buckling modes, critical buckling loads, post-buckling deflection curves, bending moments, contact forces, etc. The combination of integral and local models, namely the amended integral model, establishes a more sophisticated description of axial force, torque, bending moment, contact force and buckling mode distributions along the entire tubular string.
Pinkstone, H. (Managed Pressure Operations) | Doll, R. (Managed Pressure Operations) | Chandra, M. (Managed Pressure Operations) | Babcock, W. (Murphy Oil Company) | Tilley, V. (Murphy Oil Company) | Choo, B. (Murphy Oil Company)
Previous offset wells drilled in the layered sandstone differentially pressured reservoir formations offshore Malaysia in 1341m water depth, using conventional open system drilling techniques, had experienced lost drilling fluid circulation and hydrocarbon gas kick events, resulting in significant non-productive drilling time, and well control events.
This paper describes how advanced Managed Pressure Drilling (MPD) technology, combined with a drill string conveyed subs based (CCS) continuous circulation system, were deployed on a tender assist semi-submersible rig, and used to effectively and safely drill subsequent development wells. Techniques employed on the project also included Dynamic MPD Well Control and Formation Evaluation procedures, along with dynamic Managed Pressure Cementing (MPC) techniques.
MPD and CCS systems were used, along with MPC, to effectively drill and complete sandstone reservoir layers at various formation pressures depleted from ongoing production, and also over pressured layers charged as a result of water injection activity.
With the exploration and development of hydrocarbon reservoirs moving toward more complex formation, downhole vibrations have been identified as one of the most significant limiters to improve the rate of penetration (ROP) and bit footage. Thus, great efforts have been put on the development of cost-effective technologies and special vibration mitigation tools in order to achieve high rock breaking efficiency. The paper introduces the development and application of optimizer of drilling operating parameters named as Smart Driller Indicator (SDI) by real-time stick/slip severity monitoing based on an innovative ROP and Mechanical Specific Energy (MSE) optimization algorithm. In addition, the drillstring mechanics model establishment anlalyzing torsional vibration and field application results of the system are elaborately description.
The optimization algorithm is a drlling performance improvement algotithm on basis of MSE theory. From the perspectives of rock mechanics and conservation of energy, the ideal performance in the optional proportion among drilling parameters, ROP and MSE have been derived from comprehensive analysis of optimized drilling mechanism. Based on Newton's equation of motion, an advanced damped forced torsional vibrarion estimate (TSE) model in frenquency-domain was developed. The vibration model achieves higher accuracy diagnosis and computational efficiency due to more boundary condition effects combined with a fit-for-purpose rigid model, damping coefficient algorithm and BHA-matching transfer matrices. The model supports real-time downhole vibration surveillance as well as pre-drill BHA evaluation and post-drill root cause analysis. Additionally, the vibration mitigation principle is demonstrated in detail, conducting a variety of tests to mitigate downhole torsional vibration. SDI can diagnose the inducing factors of downhole vibration, providing useful insights into the judgment of reasonability of drilling parameters.
A three-week pilot test has been conducted in deep wells in Yumen Oilfield in China, with 30% increase of the average ROP and 40% enhancement of the average bit footage compared with offset wells. Application of SDI to enhance ROP efficiency is not affected by well type, formation and bottom- hole temperature; thus, it could be widely applied in any drilling conditions.
Abdelaziz, Sherif (Halliburton) | Leem, Junghun (Halliburton) | Praptono, Andri Setyanto (Halliburton) | Shankar, Pranay (Cairn India Limited) | Mund, Bineet (Cairn India Limited) | Gupta, Abhishek Kumar (Cairn India Limited) | Goyal, Rajat (Cairn India Limited) | Sidharth, Punj (Cairn India Limited)
A tight-gas reservoir commonly refers to a low-permeability reservoir that mostly produces natural gas. Irrespective of the reservoir rock type (e.g. sandstone, shales, coal seams or volcanics), they all have one thing in common—these reservoirs cannot be produced at economic rates without an effective hydraulic fracturing treatment.
In conventional reservoirs, rock flow capacity is usually sufficient to allow for hydrocarbons flow; therefore, hydraulic fracturing is broadly considered as a remedial technique to improve the productivity of suboptimal producing wells. In this study, fracturing was not originally considered in the primary drilling and completion planning phases, which in many cases limited the effectiveness of fracturing treatments because of challenges resulting from the well architecture, trajectory, azimuthal orientation with respect to dominant stress regimes, and other factors. As the importance of unconventional resources for hydrocarbon production has increased dramatically during the past decade and more attention and efforts are focused globally to explore these reserves, the demand for hydraulic fracturing techniques to prove the economic profitability of these resources has in turn tremendously increased. This has created a paradigm shift, as operators are beginning to recognize that they need to drill and complete wells for hydraulic fracturing to maximize the return on their assets. Therefore, hydraulic fracturing has gained an advanced position in the planning phase of unconventional assets.
Volcanic formations are one of the rarer rock types with the potential for accumulations of hydrocarbons that can produce economically. This rarity has resulted in a lack of understanding across the industry on the nature of these reservoirs and how to successfully turn them into lucrative assets. Because of the tight nature of these formations, optimal hydraulic fracturing strategies are intrinsically necessary for economic production. Without a thorough and integrated understanding of the petrophysical and geomechanical properties of these formations, it will be difficult to interpret the fracture growth behavior and its inherent effect on fracture flow capacity in the production phase.
This paper highlights the value of seismic while drilling to successfully drill a vertical exploration well offshore Malaysia when faced with an expected pressure ramp in the shallow section and a gas chimney in the deeper section disrupting the surface seismic image data.
Using a dual tool Logging While Drilling (LWD) seismic configuration enabled real time Vertical Seismic Profile (VSP) imaging and velocity data for accurate casing point selection, hazard avoidance and successful well construction and enabled elimination of a planned casing string.
The seismic while drilling was conducted from seabed down to final well Total Depth (TD) to acquire a time-depth relationship for the entire wellbore. Acquisition was conducted during connections, an acoustically quiet period when the seismic shots are fired and downhole receivers in the seismic collar are recording. Transmission of the real time data starts when the connection is complete, and the mudpulse telemetry resumes with the drilling. Seismic waveforms sent to surface after each connection were processed for checkshots and VSP image successively after each seismic acquisition level.
Critical 20 inch casing point was accurately set within 20m of identified hazards, despite an initial uncertainty of 100m predrill. The VSP image data was superior to the surface seismic image, recording clear reflectors within a disrupted gas zone, with better phase and frequency content. Full velocity profile over the whole well interval with 15m definition was acquired and processed. The character differed from the initial predrill model and offset well information significantly.
Seismic while drilling removed the need for a pilot hole, and optimized the 20 inch casing point. Accurate real time velocity information allowed for accurate time to depth conversion for drilling decisions i.e. to assist in navigating the shallow pore pressure ramp, casing point setting and providing better seismic imaging in the gas chimney. This case study highlights one of the first applications of real time VSP data enabled by the use of two seismic tools placed 15m apart in the Bottom Hole Assembly (BHA).
Carbon dioxide flooding is considered one of the most commonly used miscible gas injection to improve oil recovery and its applicability has grown significantly due to its availability, greenhouse effect and easy achievement of miscibility relative to other gasses. Therefore, miscible CO2-injection is considered one of the most feasible methods worldwide. For long term strategies in Iraq and the Middle East, most oil fields will need to improve oil recovery as oil reserves are falling. This paper presents a study of the effect of various miscible CO2-injection scenarios on the performance of the highly heterogeneous clastic reservoir in Iraq. An integrated field-scale reservoir simulation model of miscible CO2-flooding is accomplished. The compositional simulator, Eclipse-300 has been used to investigate the feasibility of miscible CO2-injection process. The process of the continuous CO2-injection was optimized to start in January 2056 as an improved oil recovery method after natural depletion and water flooding processes have been performed, and it will continue until January 2063. The minimum miscibility pressure (MMP) for CO2 was determined using empirical correlation as a function of crude oil composition and its properties. Ten miscible CO2-injection options were undertaken to investigate the reservoir performance. These options included applying a wide range of the CO2-injection rates ranged between 1.25 to 50 MMScf/day. All development options were analyzed with respect to net present value (NPV) calculations to confirm the more feasible CO2development strategy. The results showed that the application of CO2-injection option of a 20 MScf/day attained the highest recovery of 28% by January 2063 among the others. The recovery growth was so minor by the increasing the CO2-injection rate above this level. Based on economic findings the option of 20 MScf/day also attained the highest net present value (NPV). The results showed that after January 2063, the oil recovery attained by the different CO2-injection options are less than the one attained by the waterflooding process. Therefore, the miscible CO2-injection became unviable economically after January 2063.
Plessis, Guillaume J. (National Oilwell Varco, NOV) | Uttecht, Amie (National Oilwell Varco, NOV) | Pink, Tony (National Oilwell Varco, NOV) | Hehn, Lucien (National Oilwell Varco, NOV) | Jellison, Michael J. (Sub Surface Tools) | Vinson, Barry (Sub Surface Tools)
Moving into the next decade, wells in the Middle East are becoming more challenging as the deeper and more complex plays are exploited. This environment will be challenging from a torsional and tensile loading standpoint, and will be dynamically very active. This type of environment combined with high levels of H2S calls for a new high grade of sour service pipe. The Middle East is also opening up to the idea of high speed telemetry and wired pipe economics that call for a long lasting pipe product.
When using sour service pipe that is traditionally limited to 105 KSI grades, even with an optimized string design, drillers sometimes have no other option than to sacrifice the margin of overpull, risking losing the well if fishing is unsuccessful. Alternatively, they can elect to use drill pipe, which is not suited for use in this corrosive environment, generally using API S135, with a risk of parting the string due to H2S embrittlement. To address these operational limitations, the pipe body, which is the drill pipe limiting member in tension, has to come with higher material strength and at the same time exhibit improved Sulfide Stress Cracking (SSC) resistance compared to API S135 grade.
A novel grade of drill pipe was developed over a period of two years that is the strongest sour service drill pipe the industry has to offer to date and gives drillers an extra 19% of tensile capacity with its 125 KSI material yield strength. This new grade has been ordered for use in various regions of the world and for numerous applications. At this time, it is being used for intervention and stimulation operations in the Gulf of Mexico (GOM), and drilling long, extended reach (ER) wells with wired telemetry drill pipe in the Middle East.
This paper presents the phases of the grade development and discusses testing requirements for the crossover between strength and SSC resistance. It also includes statistical data on the first full scale manufacturing tests. Finally, it outlines the products expectations for field applications.
Casing design for oil and gas wells continues to evolve to adapt to increasing challenges. The casing program of most wells represents a significant portion of the total well cost, between approximately 15 and 35%. This paper discusses how expandable liner hanger (ELH) technology continues to evolve to meet the needs of an operator with a new thick walled casing design in fields with H2S and CO2. Circumstances are described wherein thick wall casing design was necessary (greater collapse pressure and room for production safety valves). Details are presented describing why the ELH was selected, challenges encountered, development of a new liner hanger to fit the smaller thick-walled casing inside diameter (ID), and how the liner hanger running tool was modified to work inside a smaller casing. Prejob analysis that was performed to help reduce risks while running in hole (RIH) is discussed. Also highlighted are improved procedures, torque and drag simulations, surge and swab simulation, and critical well review exercises.
The operator chose a well design using 10 3/4 in. casing for a larger inside diameter (ID) installation of an arrangement using double electric submersible pumping (DESP). Casing weight of 79.2 ppf was selected to support the pressure load during well production. The ELH system complemented the new heavy wall casing design during construction and installation because of the many benefits it provided, such as high torque, washing and reaming, and multiple setting contingencies. Suitable expandable material was selected for the H2S and CO2 well environment. Two ELHs were used to run into 10 3/4 and 13 5/8 in. casing, 7 5/8- and 10 3/4-in. in liner through a sidetrack with deviation of more than 75° at the bottom, overcoming entrapment issues during the operation, and reaching total depth (TD). The cementing operation was executed successfully and the ELH expanded, leading to a successful operation with zero health, safety, and environment (HSE) or service quality issues. This paper discusses the latest ongoing developments in ELH technology applied using a new casing size and weight during the construction of oil and gas wells with sour service requirements.