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Meng, Siwei (Research Institute of Petroleum Exploration & Development, PetroChina) | Bao, Jinqing (Department of Petroleum Engineering, Xi’an Shiyou University) | Yang, Chenxu (Department of Petroleum Engineering, Xi’an Shiyou University) | Cheng, Wei (Research Institute of Petroleum Exploration & Development, PetroChina) | Zhang, Guangming (Research Institute of Petroleum Exploration & Development, PetroChina)
Staged hydraulic fracturing in horizontal wells is one of the most popular techniques in developing conventional and unconventional reservoirs, where multiple fractures initiate and propagate simultaneously and then interact with each other. It is shown in hydraulic fracturing practices that these interactions lead to unsatisfactory production performance in many fractures. It is of great importance to develop a reliable hydraulic fracturing simulator that can completely effectively take these interactions into account and predict fracture behavior accurately.
We develop a fully coupled 3D hydraulic fracturing simulator with the finite element method, where the interaction between fractures is completely taken into account. We develop a finite element equation to describe fracturing deformation and propagation based on linear elastic fracture mechanics, another one to describe fluid flow and leak-off within fractures, and friction equations to describe the effects of the perforations and tortuosity. We solve these three equations in a fully coupled and implicit way, and obtain fluid pressure, fracture width, and injection allocations between fractures in every step simultaneously.
Followed by the method’s verification with experiments, we simulated staged hydraulic fracturing with the coupled finite element simulator and investigated the interactions’ effects. It was found in the simulation that the perforations have the ability to make the injection allocated very even. However, fractures propagate and evolve in very different manners due to the interaction between fractures. Some fractures are far longer than others, while their fracture widths close to the wellbore are far smaller. Due to the stress shadows arising from the fracture interactions, some wellbore zones in the longer fractures never break, and in these fractures their widths around the tip zones are larger than those around the wellbore zones.
Insights from the simulations are helpful to understand the mechanisms leading to the unsatisfactory production performance of the fractures, and the simulator can therefore be used to optimize staged hydraulic fracturing.
A cased hole well with inflow control devices (ICDs) was logged for production profiling as part of a field trial campaign testing a new fiber-optic wireline system. Pulled by a conventional tractor, both the fiber-optic wireline and a set of conventional production logging tools (PLTs) were placed at the bottom of a horizontal wellbore, locating the fiber across the reservoir for sensing purposes. The well produced at two different choke settings, enabling both technologies to capture low flow rate as well as high flow rate. The main objective with the testing was to compare the two technologies for production flow allocation and learn more about fiber-optic analytics.
The two different measurements were performed as close in time as possible. While the fiber-optic cable was sensing, the PLT was stationary and not logging, and while PLT was logging, the fiber optic was deactivated. From fiber optics, high-quality noise logging plots were generated with distributed acoustics (DAS), identifying the inflow points despite the relatively challenging acoustic environment. Propagating sound allowed for a profile of fluid sound speed to be established. Distributed temperature (DTS) was less useful on this job due to some accidental inflow of borehole fluid causing hydrogen darkening. This affected the multi-mode fiber more than the single-mode fiber; hence, DTS data could not be used. The wireline-based MAPS tool consisted of capacitance-, resistivity- and spinner-array. With the sensors located on bow springs, the tool detected various flow patterns 360 degrees around the borehole. The fiber-optic cable is located low side in a horizontal wellbore and might be affected by this in a laminated flow situation. Still, the fiber-optic sensing system managed to provide useful flow information, comparable to the PLT tool.
Economic development of marginal oil fields usually requires utilization of nearby existing processing facilities to minimize Capital and Operational Expenses. However, tie-back of multi-phase well fluid to other existing processing facilities has challenges in fiscal oil allocation among various Shareholders. This paper presents the fiscal oil allocation experience in development of marginal fields, wherein well fluid is tied-back to existing facilities for further processing and export.
Bu Haseer field is one of the marginal field in the offshore concession area of Al Yasat Petroleum Operations Company. Due to low oil production, standalone development of Bu Haseer field was not economical. Therefore, well-fluid from Bu Haseer fields is tied-back to existing facilities at Das Island. During the initial phase of production, well fluid from Bu Haseer field was measured using Multi-Phase Flow Meter (MPFM) prior to tie-back to the existing facility. Fiscal allocation of Bu Haseer oil production was based on MPFM measurement and converting the measured oil flow at operating conditions to stock tank conditions using PVT correlations. However, oil measurement using MPFM does not meet the accuracy acceptable for custody transfer, thereby not realizing the full commercial value of the production.
Measurement accuracy is improved by installing a dedicated separator to partially stabilize the oil, and measure the separated oil flow as single phase using Custody Transfer Meter, complying with API MPMS (Manual of Petroleum Measurement Standards). The separated oil is pumped through Custody Transfer Meter, to avoid flashing across Custody Meter, which would have otherwise impacted its measurement accuracy. To convert the fiscally measured partially stabilized oil to fully stabilized oil at stock tank conditions, a Shrinkage Factor is applied to account for dissolved gases at separator operating condition. Shrinkage Factor is a function of separator operating pressure, temperature and well fluid composition; which could vary during operations as well as with producing life. Estimation of Shrinkage Factor becomes more challenging when production is from multiple reservoirs sources and downstream crude stabilization process parameters vary. A pre-defined algorithm for Shrinkage Factor is configured in flow computer considering all credible operating modes.
Measurement of multi phase well fluid or partially stabilized oil is usually not recognized in the industry for fiscal allocation, mainly due to measurement inaccuracies and uncertainty in estimation of shrinkage. This paper presents Al Yasat operating experience and challenges with partially stabilized oil measurement and methodology implemented for estimating the oil shrinkage for fiscal allocation.
A virtual metering system is an alternative way to measure the flow rate of a well in real time. They can therefore improve the reliability and the effectiveness of the production back allocation process, providing redundancy to multi-phase flow meters (MPFMs) measures.
Scope of this work is to build and validate two different virtual metering systems highlighting their peculiarities and comparing their performance.
A virtual metering system can estimate the flow rates of each well of an asset by elaboration of pressure and temperature data coming from the field.
In both virtual metering systems, the core is a fluid-mechanical model of the production network of the same off-shore field, made of six wells flowing in two parallel lines. The model is run multiple times adjusting the wells flow rates according to two different minimization algorithms, to match the measured data as much as possible.
After validating the results, the performance of the tools has been compared against MPFMs, used as a common reference.
Both systems have been validated against officially allocated flow rates coming from MPFMs. At first, only pressure data have been used as inputs.
System number one, which exploits the Matlab minimization algorithm and an OLGA model of the network, showed great accuracy in the majority of the cases, with an error less than 5%, making it a great verification tool for measures coming from other instruments. Its simulation runtime, however, is still too long to make it usable in a real-time application scenario.
System number two relies instead on the gradient descent algorithm and on a GAP model of the network. This system is equipped with an automatic tool that can discard unreliable signals coming from damaged or out-of-calibration field sensors, while simulating. The resulting accuracy is acceptable, with an average error between 5% and 8% and the computational time is short enough to be used as a live measurement tool, in parallel to MPFMs.
The validation process has been repeated adding temperatures to pressures in the input dataset. No accuracy improvement has been shown by the new results for both systems, concluding that a leaner structure where only pressure is considered is to be preferred.
The two systems represent economic measurement tools for production allocation, showing a good ability in supporting field operation in case of instrument failure or unreliability.
Wang, Yun (bp) | Jerauld, Gary (bp) | Bhushan, Yatindra (Abu Dhabi National Oil Company) | Azagbaesuweli, Gregory (Abu Dhabi National Oil Company) | Bin Romeli, Mohd (Abu Dhabi National Oil Company) | Nasir, Wardah (Abu Dhabi National Oil Company) | Al Mazrooei, Suhaila (Abu Dhabi National Oil Company) | Al Ali, Mona (Abu Dhabi National Oil Company) | Singh, Manjit (Abu Dhabi National Oil Company) | Alhefeiti, Ebtisam (Abu Dhabi National Oil Company) | Al Tenaiji, Aamna (Abu Dhabi National Oil Company) | Matthews, Anna (bp)
One of the reservoirs in a giant field in onshore Abu Dhabi has been producing for six decades. The reservoir was already saturated at the time of production commencement, with a large oil rim and a gas cap. Both water injection and lean gas injection have been relied upon to sustain production, and will play an even more prominent role for the future development of oil rim and gas cap. Due to the stakeholders’ different entitlements / equity interests in the hydrocarbons originally existed in oil rim area versus gas cap area, it is important to be able to allocate liquid hydrocarbon production and injection gas utilization among the stakeholders, based on a systematic framework.
This paper presents a comprehensive comparison of two modeling-based approaches of fluid tracking for condensate allocation and gas utilization – a tracer modeling option in a commercial reservoir simulator, and a full component fluid tracking approach implemented for this reservoir. The component tracking approach is based on the idea that if individual components represented in a fully compositional reservoir model are tracked separately starting from model initialization, one can trace back the source of hydrocarbon production from both gas cap and oil rim. This approach is implemented through the doubling of the number of components in the equation of state fluid characterization – one set of components for the gas cap, and another set for the oil rim. In order to track the net utilization of the injected lean gas, additional components are needed – in this case one more component representing the lean gas, as the injected gas is a dry gas.
The results of the comprehensive comparison demonstrate very clearly that these two approaches yield consistent condensate allocation and gas utilization results over the entire life of field (including history match and prediction). For condensate allocation, the hydrocarbon liquid production split depends on how the injected lean gas is tracked. For gas utilization, the injected lean gas must be tracked as a distinct component separate from both oil rim and gas cap components. The comparison also shows that although the tracer-based approach is numerically more efficient with less runtime, the full component tracking approach is simulator agnostic, and therefore can be implemented in any reservoir simulator. In addition, the full component tracking method can be used for cases where injection gas is a known mixture of oil rim and gas cap gas – something the tracer-based option cannot handle.
In summary, this paper presents a first comprehensive comparison of the two (2) different fluid tracking modeling approaches, with practical recommendations on modeling-based hydrocarbon liquid production and injection gas utilization allocation in cases where the commercial framework makes such allocation necessary.
The latest well completions developments for extended-reach wells include advanced diagnostic and intervention capabilities to determine and improve techniques to achieve sustainable well production. The objective of this case history was to reach the target zones using extended-reach tools and perform acid stimulation diagnostics using real-time distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) tools deployed by coiled tubing (CT) to perform an effective acid stimulation treatment by improving distribution.
This paper describes how fiber-optic real-time CT service was implemented during a matrix stimulation treatment using 2-in. outer diameter (OD) CT to reach the target depth (TD). The stimulation fluid was 15% hydrochloric (HCl) acid, which was pumped through the annulus.
To optimize the treatment, DTS and DAS baselines were used to identify which zones required acid stimulation treatment to improve production. DTS profiles were collected during both the shut-in and injection stages and DAS data were acquired during the injection stages.
The injection flow profile effectiveness of a limited entry liner (LEL) completion was determined using DTS flow allocation quantitative analysis and DAS qualitative analysis. The flow rate distribution per stage was identified using DTS analysis during and after acid stimulation, and the results were compared to the DAS data interpretation. The extent of fluid diversion was evaluated within the compartments covering the entire open hole section exposed behind the liner.
The completion effectiveness was evaluated using injection distribution of stimulation fluid and water. The results showed stimulation fluid flowing and distribution through the entire horizontal section, which indicated completion effectiveness. Thermo-hydraulic modeling (THM) measured and visualized the temperature across the wellbore using the continuity equation, equation of motion, Darcy's law, and energy balance equations. Additionally, the downhole pressure was monitored throughout the entire injection process for post-job analysis of the stimulation effectiveness.
Thermal hydraulic interpretation of the DTS and DAS data analytics confirmed the effectiveness of the completion currently run by the operator.
This diagnostic process provides advanced technology options for evaluating data, reservoir productivity, and completion effectiveness for extended deep-reach wells. Best practices developed during this case study highlight the technique benefits.
Satti, Rajani (Baker Hughes) | Bale, Derek (Baker Hughes) | Patel, Amar (Baker Hughes) | Nazarenko, Pavel (Baker Hughes) | Avella, Oscar (Baker Hughes) | Solorzano, Pedro (Ecopetrol) | Sanchez, Walter (Ecopetrol) | Giosa, Carlos (Ecopetrol) | Satizabal, Monica (Ecopetrol) | Vega, Sandra (Ecopetrol) | Hernandez, Nini (Ecopetrol) | Coronel, Ivan (Ecopetrol)
Injector well completions are typically carried out using two methods: simple and selective. The performance of injector wells has traditionally been evaluated using spinner-based injection logging tools (ILTs) or on-demand fiber optic distributed temperature and acoustic (DTS or DAS) sensing while logging the well performance every 3 months or once a year depending on the application. However, with such methods utilizing a snap shot approach, critical well performance information or possible anomalies are often missed due to measurements taken only during certain periods. Therefore, operators have explored the use of advanced fiber-optics methods such as permanent distributed temperature sensing (DTS) and permanent distributed acoustic sensing (DAS), that provide continuous, real-time measurements to enable understanding of dynamic well behavior at all times and mitigate any deferred or behavioral problems.
Of relevance to this work is a vertical, injector well in a competent sandstone formation of the Heavy Oil Chichimene field in Llanos Basin, Colombia. As a first step of the fiber-optics monitoring strategy, a careful evaluation of DTS and DAS based fiber-optics methods was conducted. Based on the data analysis and operational history, DAS-based fiber optics monitoring was chosen as the most effective monitoring solution for this well. Subsequently, a proprietary DAS algorithm was developed to analyze the data and estimate the flow allocation for all the four zones. The results include waterfall acoustic energy maps, temporal flow allocation profiles and most importantly, the zonal flow allocation values.
Predicted (DAS) zonal flow allocation data was compared with traditional injection logs (ILT) under different operational conditions (varied injection flow rates and valve choke settings). Based on comparable agreement between DAS and ILT data, the operator decided to replace ILT runs with DAS-based fiber optic monitoring, resulting in lower operational costs while enabling near real-time monitoring, and providing the continuous distributed data essential for the dynamic monitoring of the well. The successful application of fiber-optics monitoring to provide an injection profile in conjunction with a surface-controlled electric valve system demonstrates a significant potential to optimize the injection process in complex injector wells. Further, remotely controlling, monitoring and optimizing injection rates into the multi-segmented zones improves the service life of the injection operations, eliminates future intervention costs, and increases ultimate recovery.
This paper presents a method of using chemical tracer data to quantitatively evaluate interwell communication in various well configurations by combining raw tracer data with field production data. Qualitatively, tracer breakthrough in an offset well indicates that there is communication between the infill and primary well, but by utilizing the method described in this paper, the fracture driven interaction (FDI) severity can be quantified by determining the total mass of tracer produced out of the primary well and new wells. The technique yields an allocation of load fluid and hydrocarbon recovery at each well and associated formation.
Integrated production data management system (PDMS) solution is presented that incorporates three remote locations of the company's different departments (Field Operation, Engineering and Economics) into a single working environment. Automated workflows implemented on the basis of PDMS aimed to improve speed and efficiency of engineering analysis and economic planning.
PetroKazakhstan Kumkol Resources JSC operates a wellstock consisting of more than fifteen hundred wells. Operational data is loaded into a system on a daily basis at a central office on the field site. At this stage data is quality checked and used for production monitoring.
All information is automatically synchronized to the office in Kyzylorda city, where production back allocation is performed. Every month regulatory reports are generated from the system. Decline curve analysis forecasts at well level are frequently applied for daily routine economical assessment of well intervention and surface construction operations. Moreover, saved forecasts are also automatically available for budgeting purposes in Almaty office.
As a result of integrated PDMS solution, PKKR JSC engineers and economists get easy and automated access to raw operational data as well as results of allocated production and forecasting by the decline curve analysis (DCA). Automated workflows for back allocation, regulatory report generation and forecast result data sharing made different departments closer and decision making more efficient. Overall, data travel distance of about 1500 km.
Shared workspace with standard analytical templates (plots, reports, maps, forecasts) allowed engineers to promote best practices across organization, align reservoir surveillance and monitoring approach in a common standardized way. PDMS allows engineers, previously overloaded with manual data handling and reporting, to have more time to solve reservoir and production engineering problems. Meanwhile, the economists gain direct and automated access for DCA forecasts, performed by reservoir engineers, not only at field, but also at well level. This helps prioritize each well's economic potential and rank accordingly, which is critical in budget planning.
The novelty of integrated PDMS solution is that it brings a new level of integration of different departments into synergy. Teamwork spread beyond engineering, operations and geology, adding economists into the team to address today's operational challenges.