Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Well Drilling
An Uneven Acid Injection Technology for Long-Lateral Horizontal Wells in Complex Carbonate Reservoirs: Simulation, Optimisation and Practice
Zou, Honglan (Petrochina Research Institute of Petroleum Exploration & Development) | Cui, Mingyue (Petrochina Research Institute of Petroleum Exploration & Development) | Liu, He (Petrochina Research Institute of Petroleum Exploration & Development) | Liang, Chong (Petrochina Research Institute of Petroleum Exploration & Development) | Liu, Pingli (Southwest Petroleum University) | Xue, Heng (China Zhenghua Oil Co.,Ltd) | Wang, Peishan (PetroChina Southwest Oil and gas field branch)
Abstract Focusing on the characteristics of long horizontal interval (>800m) and strong heterogeneity of complex carbonate reservoir, this paper puts forward a high efficiency uneven acid distribution technology, consequently solving the problems of high large scale and financially-challenged acidizing result. It takes the damage profile in productivity established stage or liquid production profile in the stable production stage for horizontal wells as the designed core, and selects optimal injecting point and interval in the long-interval horizontal well to maximize stimulation effect with minimal acid. This paper establishes an integrated mathematical model for the quantitative analysis of non-uniform damage of horizontal well simulated acidizing diverting and the acid-etched wormholes propagation for complicated carbonate reservoir. Besides, the matching technological methods and strategies, such as whole or local selective acid injection using coil tubing, inert liquid injection in the annulus, and the secondary segmented acidizing displacement, were presented. This technology has been applied in the AHDEB and HALFAYA oilfield, completing 296 wells acidizing treatments. The results demonstrated that the average acidizing volume decreased from 500-900m to 150m and production significantly increased.
- South America > Brazil > Campos Basin (0.99)
- Asia > Middle East > Iraq > Maysan Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Halfaya Field > Mishrif Formation (0.99)
- Asia > China > Sichuan > Sichuan Basin > Southwest Field > Longwangmiao Formation (0.99)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
Successful Hydraulic Fracturing Optimisation in KS Field through Fracture Height Growth Identification and Mitigation
Kamal, Hamzah (Medco E&P Indonesia) | Noke Fajar, Prakoso (Medco E&P Indonesia) | Geraldus, Yudhanto (Medco E&P Indonesia) | Luciana, Soetikno (Schlumberger) | Ricki Daniel, Marbun (Schlumberger) | Reza, Vitali (Schlumberger) | Areiyando, Makmun (Schlumberger) | Apollinaris Stefanus Leo, Anis (Schlumberger)
Abstract Hydraulic fracturing in the tight sandstone of the KS Field has been implemented in more than 200 wells since 2002. Year by year, it gets more challenging due to limited well candidates with good properties and a decreasing trend in production result. Thus, hydraulic fracturing optimization both in design and execution are critical to increase success ratio and to contribute more oil production. One of the efforts is delivering fit-to-purpose design through fracture height growth identification and mitigation. A mechanical earth model (MEM) is constructed to obtain elastic properties and stress profile as an input for fracture geometry simulation as a preliminary tool for height growth prediction. The MEM is generated using triple combo and sonic logs and validated with wellbore stability analysis. A pre-treatment mini-frac was performed and analyzed before the main fracturing operation to calibrate and update the MEM stress profile. For final validation, the profiles of MEM, MEM optimized fracture simulation and temperature log results are compared to evaluate the fracture height growth issue. Last, fit-for-purpose strategies are applied to optimize the fracture geometry result and maximize oil production. Previously, hydraulic fracturing with high proppant volume has been used to create long fracture half-length providing large reservoir contact and thus improved productivity. Unfortunately, production after fracturing in some wells shows no significant change and occasionally yields high water cut. Currently, detailed pre-fracturing evaluation is applied. Comparison plot results show fracture growth consistency between the MEM-optimized hydraulic fracturing simulation with temperature log profiles, validating the suspicion of fracture height growth to and through the upper and lower barriers of the fracturing target. Two design changes were then proposed to control fracture height growth: Applying lower-viscosity fracturing fluid by decreasing gel loading or changing to viscoelastic surfactant fluid; and applying an artificial barrier technique. These changes are designed to reduce fracture height growth and increase effective fracture half-length in the pay zone. The result is increasing fracturing success ratio, from 40% to 70%, which contributes to arresting the production decline of the KS Field. Integrating geomechanics analysis (in the form of MEM) into hydraulic fracturing design simulation and profile comparison, MEM-optimized hydraulic fracturing simulation and temperature logs have validated the issue of fracture height growth problems in the KS Field and justified the application of fit-for-purpose strategies to mitigate the issue.
- Asia > Indonesia (1.00)
- North America > United States > Texas (0.69)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.52)
- Asia > Indonesia > Sumatra > South Sumatra > South Sumatra Basin (0.99)
- Asia > Indonesia > Sumatra > South Sumatra Basin > South Sumatra Basin > Telisa Formation (0.99)
- Asia > Indonesia > Sumatra > South Sumatra Basin > South Sumatra Basin > Rimau Block (0.99)
- Asia > Indonesia > Northwest Java Sea > West Java > Sunda Basin > Baturaja Formation > Lower Baturaja Formation (0.99)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Displacement Efficiency for Primary Cementing of Washout Sections in Highly Deviated Wells
Renteria, Alondra (University of British Columbia) | Maleki, Amir (University of British Columbia) | Frigaard, Ian (University of British Columbia) | Lund, Bjornar (SINTEF Industry) | Taghipour, Ali (SINTEF Industry) | Ytrehus, Jan David (SINTEF Industry)
Abstract Anywhere between 0%-80% of cemented wells have integrity failures, suggesting both geological and operational factors. One way geology affects cementing is via irregular wellbores, e.g. washouts. Here we study the effects of washouts on mud removal in strongly inclined wellbores, experimentally and via 2-D computational simulations, with aim of identifying key control parameters. Experiments were performed with 2 fluids with properties representative of drilling mud and cement (or spacer), displaced at constant flow rate through a 10 m long annular flow loop. A downstream "washout" section of the annulus had an enlarged outer diameter. Twenty-four conductivity probes tracked the arrival times of the displacing fluid by measuring the conductivity of fluids as they pass. The experimental matrix includes 8 experiments with 2 eccentricities (standoff = 1, 0.58), 4 angles of inclination and slightly variable rheology. The simulation study covered wider ranges of variables. The results of simulations and experiments agree qualitatively on the main effects, as shown in [7]. Here we extend the study using the 2D simulation to study the effects of washout length and diameter, for both concentric and eccentric wells, all oriented horizontally. The simulations provide detailed information on the evolution of the fluid-fluid interfaces as they pass through the washout, as well as information on the velocity fields and stresses. In any near-horizontal section there is a delicate balance of buoyancy and eccentricity influences, in both regular and irregular geometries. Under some circumstances an irregular section seems to have a positive stabilizing effect on the interface. However, this positive message is balanced practically by uncertainty of washout size and in-situ mud properties and the positive effects are not universal. We find that increasing the washout diameter always appears to decrease the displacemnt efficiency, for both concentric and eccentric annuli. Increasing the washout length is less clear in its effects. In all cases, the main risk from residual drilling mud in isolated washouts is that it can contaminate the cement slurry as it passes.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (0.91)
- Well Drilling > Drilling Operations > Directional drilling (0.88)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.69)
- (2 more...)
Abstract In this paper, we introduce a methodology for the automated construction of a statistical forecast for gas production from coalbed methane wells. The approach uses decline curves to extrapolate production from individual wells and provides a statistical range of outcomes based on a regression model, fit to a cluster of wells similar to the one being forecasted. The purpose of the method is to provide a quick forecast that uses only directly measured data that are subject to a minimal additional interpretation and modelling. In the paper, we describe application of the workflow to forecast production from previously produced and newly drilled horizontal coal-gas wells in the Bowen basin and compare predictions to the actually observed production. First of all, we benchmarked different types of decline curves against numerical simulation to evaluate the applicability of decline curves for long term predictions. We checked Arps's and power-law and exponentiated exponential family of type curves to predict production for up to 30 years. When compared to the simulation results, Arps's curves provided the best match. Then, we introduced a type curve fitting workflow and compare prediction against observed production for each type of decline curves at prediction period from three months to five years. After that, we evaluated different regression models (linear, kernel density estimate, agglomerative clustering, Bayesian combination of linear regression and clustering, support vector and random forest) to predict the peak rate and provide a way to extract the decline statistics for similar wells. The combination of type curves and a regression model allowed us to construct a distribution of decline curves for each well and extract curves corresponding to the requested quantiles. We applied this statistical approach to production of 140 wells and compared the predicted results with the actual production. In the end, we discuss how this workflow can be applied to forecast production from the new infill wells. The only essential difference is that the peak rate needs to be adjusted to take the depletion into account. That can be done by multiplying the peak rate estimate by the ratio of inflow rate at the time of the historical peak and the current time. The inflow ratio can be estimated by comparing the average reservoir pressure at both moments in time. We used this workflow as a part of the screening process to select infill well candidates. In the paper, we compare the results of the prediction with the actual production from 15 infill wells drilled within two years form the time of the forecast.
- North America > United States (1.00)
- Asia (1.00)
- North America > Canada > Alberta (0.28)
- Oceania > Australia > Queensland > Central Highlands (0.25)
- Oceania > Australia > Queensland > Central Highlands > Bowen Basin (0.99)
- Asia > China > Qinshui Basin (0.99)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning > Support Vector Machines (0.48)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning > Regression (0.34)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning > Clustering (0.34)
Abstract Water production is a major concern for oil companies because it involves not only a high cost for handling the water on surface, but also issues related to scale and corrosion in tubulars, and an overall decrease of hydrocarbon production. Finding the right solutions for each case is a challenge because there is no one solution that fits all. Chemical treatments for water shutoff are cheaper than mechanical treatments and can offer more targeted and customized design, but they often come with higher operational risks. A new water control system based on a single particulate additive was extensively evaluated under laboratory conditions and then successfully implemented in the field. The fluid is easy to prepare using traditional field mixers and does not need curing after it is pumped into the formation, thus saving time and cost compared to most conventional water shutoff systems. The fluid was evaluated in the laboratory with a wide range of formation permeabilities and injection conditions using the fluid loss apparatus, permeameter, and formation response tester. The viscosity and stability of the fluid in different water salinity and concentrations were also investigated. Overall, it was found that the new fluid system was very efficient in shutting-off formations greater than 50 md up to a few darcies. Those results were consistent with the nature of the plugging mechanism, which relies on physical pore plugging alone. The system could be further tuned depending on the formation permeability. In the presence of oil saturation, the penetration of the particulate system was found limited as compared to a single-phase, water-saturated core.
- North America > United States (1.00)
- Asia > Middle East (0.69)
- Well Drilling > Drilling Fluids and Materials (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- (4 more...)
Abstract Challenges are usually exaggerated related to matrix acid stimulation and fluid placement in extended reach horizontal wells and demand a constant flow of innovation. The optimization of real time fluid placement, increasing the reservoir contact and establishing uniform fluid distribution for better production/ injection across the openhole interval is one area that can benefit from these new innovations. Coiled tubing (CT) equipped with a tractor and new real-time downhole flow measurement capabilities was selected as the solution. While a CT tractor facilitates the reach, flow measurements provide a clearer understanding of downhole injectivity patterns. Real-time fluid direction and velocity are acquired and used to identify high/low intake zones. The data is subsequently applied to adjust the stimulation diversion schedule accordingly. In a water injection well, baseline data was acquired before commencing a matrix stimulation treatment. The treatment was squeezed through the CT at the depths highlighted as low intake during the initial profiling. The coiled tubing real-time flow tool was deployed during the matrix stimulation treatment of the extended reach water injection well with a downhole tractor. The flow tool measured the baseline injection profile which was then correlated with the mobility data. Results from the pre-stimulation profile showed that 70% of injection was entering in a 3,000 ft. section near the toe (24,500 ft.), whereas 30% of injection was spread across the remainder of the open-hole interval. The acquired flow data was able to identify sections of the wellbore featuring low mobility and viscous fluids, which in turn provided additional information for the adjustment of the subsequent stimulation pumping sequence. The real-time optimization of stimulation treatment helped to increase the post-stimulation injection rate by over 4 times the pre-stimulation rate. The combination of CT tractor with real-time flow measurement tool provides an efficient means to stimulate extended-reach water injector wells. The basic technology behind the real time flow tool is a synchronized system with a series of heating elements and temperature sensors along the tool to determine the direction and mean velocity of the fluid. This ultimately allows for a more accurate placement of stimulation treatment to the targeted zones. The technology can also be applied for extended reach oil producers, however, for optimum tool performance, the well should first be displaced with an inert fluid.
- Asia > Middle East > Saudi Arabia > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Basin > Widyan Basin > Wafra Joint Operations Block > South Umm Gudair Field > Pre-Khuff Formation (0.99)
- Asia > Middle East > Saudi Arabia > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Basin > Widyan Basin > Wafra Joint Operations Block > South Umm Gudair Field > Khuff Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Arabian Basin > Widyan Basin > South Ghawar Field (0.99)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Well Completion > Acidizing (1.00)
- (3 more...)
- Information Technology > Architecture > Real Time Systems (1.00)
- Information Technology > Communications > Networks > Sensor Networks (0.35)
Abstract Due to drilling economics, operators prefer extending the lateral section over drilling a new well. It presents a challenge to run casing strings to the target depth in wells where horizontal section is longer than the vertical section. Although alteration of casing weight or installation of liner may present as solutions, they are hardly economical compare to selective buoyancy methods. This paper aims to take an engineering approach on optimizingly palceing a buoyancy barrier which traps lighter fluid in the horizontal section for thepurpose of reducing friction. As seem to not have been presented in SPE conferences before, the aim of this paper is to engineeringly identify the optimum placement of the barrier, measure the efficiency improvement and identify the cases for which running a barrier is essential to run the casing string to the target depth. Operators usually run a torque and drag to measure the improvemet made by placing a barrier in kick off point. In this paper we intended to verify this practice and offer a simple rule of thumb method that can help an operator to decide on weather it is needed to run a barrier. Referred to in this paper as flotation collar, it is installed as part of the casing string. It employs a mechanical barrier that traps the air or lighter completion fluid in the mostly horizontal section and separates it from the heavier completion fluid in the mostly vertical section of the casing string. Identifying the best position of the barrier is important to achieve the maximum hook-load. In this paper, numerous cases are studied by gradually expanding the air section and monitoring the hook-load to identify the best position for which the hook-load is maximum. As per its physics, there is only one position of placement which results in the highest axial tensile force, also known as hook-load, when forces of gravity and friction engage. Placing the tool too high or too low in the string misuses the available tensile axial force and will not provide the best results. By using casing flotation tools as a barrier, a spectrum of thirty to eighty percent tensile improvement in the axial load are observed and more than fifty percent reduction of buckling effects in vertical section. For some cases, running a flotation tool was the only option to reach to the target depth with the casing string. Flotation tools in long string wells are the only economical alternative to changing casing weights or running liners when it is to completing wells with extended horizontal sections. A flow-chart is presented to help with simplifying the process of choosing a flotation tool and finding its best position of placement.
- Well Drilling > Drilling Operations > Running and setting casing (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Drilling > Casing and Cementing > Casing design (1.00)
A Priori Scenario Modelling with LWD Seismic for Successful Well Placement
Tan, Aaron (Sabah Shell Petroleum Co. Ltd.) | Lee, Bor Seng (Sarawak Shell Berhad) | Van Voorst Vader, Herman (Sarawak Shell Berhad) | Holleman, Nico (Sabah Shell Petroleum Co. Ltd.) | Spiteri, Richard (Sarawak Shell Berhad) | Ahmed, Aqil (Schlumberger) | Maula, Fahdi (Schlumberger) | Shamsuddin, Shanaz (Schlumberger) | Heng, Elijah (Schlumberger)
Abstract A Vertical Seismic Profile acquired while drilling and which utilized an a priori velocity model template to facilitate accurate well landing in a constrained drilling section is presented. The results were compared to original predictions based on surface seismic and actual formation depths taken from log data. The approach used actual checkshot velocities acquired in real time using VSP lookahead imaging while drilling to reduce spatial and depth uncertainty. Projections ahead of the well landing utilized the checkshot data to perturb the a priori velocity templates in real time. It was also complemented by the borehole seismic image to check for sub-seismic faults and alternate interpretations. Based on these projections, trajectory corrections were made to optimize landing the well in a key reservoir sand. Initiating early directional changes were critical to land on a short, directionally-constrained open-hole section whilst ensuring the section was within the targeted fault block. A comparison of the actual wellbore velocities against the predrill scenarios is provided along with corresponding vertical depth predictions. Lateral constraint was provided by the correlations of the VSP with the surface seismic image at key stages while drilling. Mapping of the drilling data to the velocity templates showed a deep case scenario for well placement. Details of the two resultant trajectory changes initiated after 2 and 5 stands of drilling respectively are explained. The approach allowed for accurate well placement, reducing depth uncertainty from 60-100 ft. predrill to within 5 ft from final while drilling prediction to actual depth. Final depth confirmation utilized Gamma Ray and Resistivity at Bit Inclination (GABI and RABI) for the key sand. The sand was found to be 18 ft. deeper than initially expected based on the pre-drill model. This method saved the drillers a potential side track. Conventional Electromagnetic well placement techniques can be limited in short open-hole sections where early time information is required to facilitate trajectory changes to allow for correct spatial landings. By using VSP while drilling in conjunction with a priori modelling, data can be acquired early enough to successfully, address this challenge.
Design, Fabrication and Field Trial Testing of a Novel Rotating Continuous Circulation Tool RCCT
Badran, Mohammed (Drilling Technology Team, Exploration and Petroleum Engineering - Advanced Research Center) | Gooneratne, Chinthaka (Drilling Technology Team, Exploration and Petroleum Engineering - Advanced Research Center) | Saqqa, AbdulKarim (Kasab International)
Abstract In this paper, we present an innovative Rotating Continuous Circulation Tool (RCCT) that allows both limited rotation of a drillstring assembly and uninterrupted circulation of drilling fluid during making up of, or breaking out, a drill pipe, to/from the drillstring assembly. Continuous/nearly continuous drilling has many advantages such as reducing the risk of stuck pipe and wellbore collapse as well as the efficient removal of cuttings resulting in improved borehole cleaning. The RCCT is a sub with a central bore and upper and lower ends that connect to the drillstring assembly. The upper and the lower part of the RCCT are able to rotate independently and in unison through a clutch/sleeve system. A central bore valve that is coupled to the upper part of the RCCT is able to selectively open and close the central bore. There is also a side entry port in the sidewall of the upper part that is controlled by the central bore valve to selectively allow drilling fluid to be injected into the central bore. A preliminary field trial to validate the RCCT was safely and successfully performed in a hydrocarbon well during a cement cleanout operation. The four RCCT subs were successfully tested for rotation with the rotary table and for drilling dynamics while cleaning out cement. Recommendations for improvements from this trial test are planned to be implemented in future field tests.
- Asia > Middle East (0.46)
- North America > United States (0.29)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drillstring Design (1.00)
- Well Drilling > Drilling Operations (1.00)
- (3 more...)
Abstract As Malaysia’s first tension leg platform, the Shell Malikai project, represents an unconventional approach towards deepwater operation in this region. In a field embedded characterized by reservoir drawdown from adjacent production wells, the lowest cementing margin is 0.65 ppg. Annular gaps between casings of as tight as 0.53 in each side further elevates the equivalent circulating density (ECD). Cementing software simulation predicts risk of heavy losses during cement placement and subsequently lack of isolation between multiple hydrocarbon-bearing zones. The loss of zonal isolation would mean crossflow between the reservoir. At worst case, some of the water injector wells may be abandoned due to inability to inject into the target reservoir and uncertainties of injection efficiency. This represents a significant loss of capital investment. A two-pronged solution has been developed to secure the long-term well integrity of the deepwater project. Implementation involved front-end design, modelling, planning, and execution. Two-stage cementing is a technique by which selected intervals along the casing can be cemented in separate stages. It reduces the risk of losses due to long column of cement slurry exerting high hydrostatic head towards the weak formation. In 11 3/4in liner with tight annular gap, the risk of taking losses is high. Therefore, two-stage cementing was employed, combined with specialized blended lightweight 11.5-ppg cement. First-stage cement will provide good liner shoe strength for drilling ahead, and second-stage cement will provide zonal isolation for two hydrocarbon zones near the top of the liner. For 9 5/8in liner, due to the presence of a pressure ramp at the top of the section and weak formation at the bottom, managed pressure cementing (MPC) was the chosen approach to mitigate the risk of losses. MPC is a technique that enables cementation to be conducted in a hydrostatically underbalanced condition where surface backpressure (SBP) is applied to maintain the bottomhole pressure between the highest pore pressure and the lowest fracture pressure of the well. The combination of MPC and two-stage cementing, together with other existing best practices, formed an integrated solution in narrow margin cementing. This has resulted in flawless cementation for two water injector wells. No losses were observed during cement displacement, there was no gas migration, and the liner top packer was successfully set, and pressure tested in MPC mode. A subsequent cement log confirmed the top of cement requirement was fulfilled. The paper will further explain on how this unconventional technique were planned and executed.
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- (8 more...)