Performance Evaluation of Multistage Fractured Horizontal Wells in Tight Gas Reservoirs at Block M, Ordos Basin

Block M of the Ordos Basin is a typical low-permeability tight sandstone gas accumulation. To develop these reservoirs, various horizontal well fracturing technologies, such as hydra-jet fracturing, open-hole packer multistage fracturing, and perf-and-plug multistage fracturing, have been implemented in practice, showing greatly varying performance. In this paper, six fracturing technologies adopted in Block M are reviewed in terms of principle, applicability, advantages, and disadvantages, and their field application effects are compared from the technical and economic perspectives. Furthermore, the main factors affecting the productivity of fractured horizontal wells are determined using the entropy method, the causes for the difference in application effects of the fracturing technologies are analyzed, and a comprehensive productivity impact index (CPII) in good correlation with the single-well production of fractured horizontal wells is constructed. This article provides a simple and applicable method for predicting the performance of multi-frac horizontal wells that takes multiple factors into account. The results can be used to select completion methods and optimize fracturing parameters in similar reservoirs.

Production Splitting Method for Commingled Production Reservoir Based on Automatic History Matching of Single Well

The interlayer interference is very serious in the process of water flooding development, especially when the reservoir adopts commingling production. The implementation of various interlayer interference mitigation measures requires that the production performance parameters and remaining oil distribution of each layer of the reservoir should be clearly defined, and the accurate production splitting of oil wells is the key. In this paper, the five-spot pattern is simplified to a single well production model of commingled production centered on oil well. The accurate production splitting results are obtained through automatic history matching of single well production performance. The comparison between the calculation results of this method and that of reservoir numerical simulation shows that the method is simple, accurate, and practical. In the field application, for the multilayer commingled production reservoir without accurate numerical simulation, this method can quickly and accurately realize the production splitting of the reservoir according to the development performance data.

Laboratory studies of physico-chemical methods to break emulsions stabilized with surfactant-polymer cocktails

Introduction. Oil field treatment often makes it necessary to combine different methods of well production treatment, taking into account the development regimes and parameters, produced and injected fluids, technical equipment and economic feasibility. The carried-out complex of laboratory tests is aimed at the creation and subsequent destruction of model systems with specified parameters. The list of the considered methods and the temperature regime of the tests are due to the physicochemical parameters and the field specifics. The purpose of this article is to search for an effective method for the primary treatment of well production after SP-flooding — a highly stable oil-water emulsion, additionally stabilized during pumping by means of an ESP. Materials and methods. The laboratory tests helped to develop an optimal mode of creating an artificial emulsion based on oil from BS10-1 reservoir of the Kholmogorsk field in the Yamalo-Nenets Autonomous Okrug, and a surfactant-polymer cocktail, which simulates well production after SP-flooding. The research tested physicochemical methods of destroying oil-water emulsions, such as their dilution with formation fluids, thermal settling, gravitational separation by centrifugation at RPM = 4000–12000 rpm, introduction of demulsifiers, as well as a combined effect, including all of the above approaches. The tested methods were supplied with the calculated values of the oil phase final water-cut, which allowed us to evaluate the effectiveness of the applied approaches to the destruction of model systems. Results. It has been found that not all of the applied approaches provide the extraction of the estimated amount of oil from emulsion systems with varying degrees of dilution by formation fluids. Satisfactory destruction of the emulsion was achieved after 10–20 min of centrifugation at T = 40 °C and RPM within 4000–8000 rpm. The traditional introduction of industrial demulsifiers into the studied systems without additional influences is ineffective. Conclusion. The optimal level of water cut in the oil phase of ≤5% was achieved after diluting the emulsion with formation fluids, with a combined approach to the destruction of the original and diluted emulsion with formation fluids. In addition, the research showed that it is possible to re-use the extracted SP-composition when controlling its physicochemical parameters, taking into account the effect of the introduced additives.

Geoscience Assessment of Declined Production Rate and Recovery from a Reservoir in “ANDA” Field, Onshore Southwestern Niger Delta

Declined production rates in wells producing from common reservoirs are enigmatic and generally viewed as phenomenal in some fields worldwide. The challenge posed by such discordant production trends forecloses the preponderance of totally and partially abandoned production, especially in aging fields. This study assesses possible factors associated with varying well production trends from a common reservoir in a field in the onshore western Niger Delta, by integrating multi-geoscience parameters including formation evaluation, 3D quantitative seismic analyses, paleoenvironmental diagnoses, paleobathymetric studies, and reservoir petrophysics to unravel the complexity of the reservoir. Composite well logs were collected from five wells selected for the study. Gamma-ray and SP logs were combined to delineate the depositional environment of "Heri sand" based on Schlumberger's (1985) log motif classification. The results were applied and found useful to develop an optimum recovery production plan for the study field. It has been revealed from this study that declined production performances of the Heri sand reservoir are attributed to the deposition of the reservoir in three distinct paleoenvironments under different bathymetric settings within a coeval period. These factors constitute strong influences on the petrophysics of the reservoir which invariably influences’ the production performance of the reservoir. Having realized the cause of the declined rate of the reservoir in the Anda field, the reservoir can be revitalized by well injection and fracturing.

High Definition Acoustic and Temperature Logging for the Diagnosis of Complex Annuli Leaks and Communication

Maintaining annuli integrity is critical for safe and optimized well operations. Monitoring of tubing casing annulus (TCA) and casing-casing annulus (CCA) pressures is mandatory as it gives a direct indication of possible seal or tubular failures that may lead to a negative impact on HSE or well production. In cases where the observed annuli pressures suggest leaks and possible communication between tubing and TCA or TCA and CCA, a comprehensive plan should be put in place to detect and evaluate the possible leak sources and paths that will allow for proper remedial actions. Logging techniques using spectral noise logging (SNL), and high precision temperature Logging (HPT) are one way to diagnose the source of a leak and communication path between 2 adjacent casings (for example TCA and CCA). The operation is performed by running the HPT and SNL log under shut in conditions to establish a base line, followed by logging under dynamic conditions. Dynamic conditions can include bleeding off the TCA pressure while all other annuli and tree valves are shut-in and injecting into the tubing-casing annulus while bleeding off the CCA. The dynamic passes aim to activate the leak points. The SNL and HPT will capture the corresponding temperature and Spectral noise events revealed by the fluid flow though the leak points. These are compared to the base line shut in logs. The SNL is run in stations and can capture noise generated by fluid movement in a wide range of strength (decibels) and frequency within a wide scanning radius, while HPT can capture minor temperature changes of 0.02 Deg F. The paper will discuss an example where the HPT and SNL were run along with a set of conventional sensors such as GR, CCL, and pressure in a HPHT gas well to diagnose leak points and a possible communication path between the TCA and CCA. The Logging operation was carried out rig-less with minimum intervention using wire line under the shut in and dynamic conditions. Spectral noise logging precisely captured the leak points and drew a clear picture of the casing integrity breaches in multiple points. The results of the diagnostics and evaluation will now be used to design the appropriate remedial actions required to restore the well to the desired condition for production.

Mitigation of Gas Condensate Banking Using an Integrated Chemical Approach

In gas reservoirs, the well production can be reduced due to the development and accumulation of condensate in the near-wellbore zone. Various techniques are used to minimize the condensate damage and maintain hydrocarbon production. Hydraulic fracturing and wettability alteration techniques are the most effective methods. However, these techniques are expensive, especially in deep gas reservoirs. This paper introduces a new approach for mitigating condensate accumulation by integrating the hydraulic fracturing and wettability alteration treatments. The efficiency of two chemicals that can generate multiple fractures and alter the fracture surfaces to less condensate status is investigated in this work. Thermochemical fluids and chelating agent solutions are used to mitigate the condensate damage and improve gas production for the long term. Several laboratory measurements were carried out to study the performance of the proposed approach; coreflooding, zeta potential, and nuclear magnetic resonance (NMR) experiments were conducted. The chemicals were injected into the tight rocks to recover the condensate and improve the flow conductivity. Zeta potential was performed to assess the rock wettability before and after the chemical injection. Moreover, the changes in pores network due to the chemical treatments as analyzed using the NMR technique. Thermochemical treatment removed around 66% of the condensate liquid, while the chelating agent reduced the condensate saturation by around 80%. The main mechanism for condensate removal during thermochemical flooding is the generation of micro-fractures that increase the rock permeability and improve the condensate flow. On the other hand, chelating agents can alter the rock wettability toward less oil-state, leading to considerable recovery of the condensate liquid utilizing a wettability alteration mechanism. Finally, an integrated approach is suggested to injecting thermochemical fluids followed by chelating agent solutions. The proposed technique can lead to generating micro-fractures of less oil-wet surfaces, consequently, the condensate bank can be removed by more than 90%.

Optimizing Tubing and Liner Completion Design to Improve Gas Production from Existing Wells: Case Study for ADNOC Onshore Field Abu Dhabi, UAE

An onshore gas field contains several gas wells which have low–intermittent production rates. The poor production has been attributed to liquid loading issue in the wellbore. This study will investigate the impact of optimizing the tubing and liner completion design to improve the gas production rates from the wells. Numerous sensitivity runs are carried out with varying tubing and liner dimensions, to identity optimal downhole completions design. The study begins by identifying weak wells having severe gas production problems. Once the weak wells have been identified, wellbore schematics for those wells are studied. Simulation runs are performed with the current downhole completion design and this will be used as the base case. Several completion designs are considered to minimize the effect of liquid loading in the wells; these include reducing the tubing diameter but keeping the existing liner diameter the same, keeping the original tubing diameter the same but only reducing the liner diameter, extending the tubing to the Total Depth (TD) while keeping the original tubing diameter, and extending a reduced diameter tubing string to the TD. The primary cause of the liquid loading seems to be the reduced velocity of the incoming gas from the reservoir as it flows through the wellbore. A simulation study was performed using the various completion designs to optimize the well completion and achieve higher gas velocities in the weak wells. The results of the study showed significant improvement in gas production rates when the tubing diameter and liner diameter were reduced, providing further evidence that increased velocity of the incoming fluids due to restricted flow led to less liquid loading. The paper demonstrates the impact of downhole completion design on the productivity of the gas wells. The study shows that revisiting the existing completion designs and optimizing them using commercial simulators can lead to significant improvement in well production rates. It is also noted that restricting the flow near the sand face increases the velocity of the incoming fluid and reduces liquid loading in the wells.

The Overlooked Intricacies of Wellbore Cleanout in Sub-Hydrostatic Conditions with Coiled Tubing: Lessons Learned Toward an Effective Approach

This study focuses on horizontal wells completed with pre-perforated liners installed in open holes, and which produce under sub-hydrostatic conditions. During workover operations, loss circulation materials (LCM) are routinely pumped, thus requiring coiled tubing (CT) cleanout interventions to enable well production afterwards. The sub-hydrostatic nature of the reservoir makes it challenging to maintain optimum bottomhole pressure (BHP) and have the ideal downhole conditions, without significant losses and with sufficient annular velocities, for an effective cleanout. During CT cleanout operations, the LCM plugging the formation may falsely create a perception that the well is able to sustain a column of fluid. However, as the LCM is cleaned out and the wellbore starts communicating with the reservoir, sudden fluid losses may occur, causing solids in the annulus to fall and leading to a stuck pipe scenario. Constant control of the balanced downhole conditions is therefore critical in such operations—yet frequently overlooked during job design. The use of real-time downhole pressure sensors thus not only ensure effective cleanout but also act as a stuck pipe prevention measure. Based on job executions in similar wells, several lessons learned were compiled. The ability to maintain optimum downhole conditions by adjusting liquid and nitrogen rates during cleanout has proven to be key to a successful cleanout. Additionally, in one of the wells where CT did get stuck, the team was able to prevent debris from falling, thus addressing the root cause, and facilitating the implementation of an effective contingency plan to get the pipe free. The need for live downhole monitoring is even more important when operating in the pre-perforated liner sections that are exposed to the open hole. Common designs calculate annular velocities based on the internal diameter of the liner, but in reality, the much bigger openhole diameter shall be taken into consideration, which result in much lower values of annular velocities in reality. Additionally, selection of the right bottomhole assembly (BHA) is critical for the overall system performance. In the presented case, the motor and mill configuration was observed to be more effective compared to a high-pressure rotary jetting tool. However, as the motor and mill combination creates significant vibrations while operating, it becomes critical to use a ruggedized version of the live downhole CT acquisition system to ensure maximum reliability. The observations compiled throughout operations enabled the development of best practices. Risks involved in a cleanout operation are often underestimated, especially in a well with a depleted reservoir. As more reservoirs face depletion in mature fields globally, the ability to clearly understand the downhole dynamics during such operations makes the difference between a successful job and a catastrophic failure.

High Performance Tailored Mechanically Enhanced Cement Slurry Helped in Delivering Dependable Barriers Across HPHT Reservoir: Case Study from UAE Offshore

The concept of zonal isolation has evolved recently addressing new industry challenges to provide dependable barriers throughout the life of the well. This helps ensure long term well integrity for safer and more efficient hydrocarbon production, especially for the fields predicted to have a long lifetime. This leads to tailoring of cement slurry designs for superior mechanical parameters to avoid deteriorating them under post cementing operational loads. Following cementing best practices is a key parameter to achieve a successful cementing job, however adequate mechanical properties will help a cement slurry to withstand all the cyclic loads that the well will experience during its lifetime. Determining these properties and tailoring cement slurry designs to meet these properties will help ensure that the cement slurry will still survive these loads, all the way from placement until it has experienced all the post cementing operational loads including but not limited to multiple pressure testing, unloading the well, perforations, various thermal loads during well production, hydraulic fracturing etc. The tailored cement slurry was able to provide an adequate solution of such challenges faced by an operator in Offshore UAE under a high pressure – high temperature (HPHT) environment. Stress modelling was performed for the life of the well considering post cementing operations. This helped in determining optimum mechanical properties required for the cement slurries considered. Specialized testing was performed in both lab and yard to achieve such properties for field execution. Based on various stress and hydraulic modelling, slurries ranging from 13 to 17.5 ppg were designed and pumped successfully in the wellbore. Post cementing bond logs showed adequate placement of a tailored dependable barrier across a complete wellbore including an HPHT reservoir section. This approach can be used for wells with similar challenges around the world for long term zonal isolation.