Pore Network Modelling of Porous Media for Carbon Dioxide Sequestration: A Case Study of Pakistan

Carbon dioxide (CO2) storage in natural rocks is an important strategy for reducing and capturing greenhouse gas emissions in the atmosphere. The amount of CO2 stored in a natural reservoir such as natural rocks is the major challenge for any economically viable CO2 storage. The intricate nature of the porous media and the estimates of the replacement of residing aqueous media with the invading CO2 is the challenge. The current study uses MATLAB to construct a similar porous network model for simulation of complex porous storage. The model is designed to mimic the overall properties of the natural porous media in terms of permeability, porosity and inter-pore connectivity. Here a dynamic pore network is simulated and validated, firstly in the case of a porous network with one fluid invading empty network. Subsequently, the simulations for an invading fluid (CO2) capturing the porous media with filled aqueous brine solution are also carried out in a dynamic fashion. This resembles the actual storage process of CO2 sequestration in natural rocks. While the sensitivity analysis suggests that the differential pressure and porosity have a direct effect on saturation, increasing differential pressure or porosity increases the saturation of CO2 storage. The results for typically occurring rocks in Pakistan are also studies and related with the findings of the study.

Evidence for widespread cytoplasmic structuring into mesoscopic condensates

Eukaryotic cytoplasm organizes itself via both membrane-bound organelles and membrane-less biomolecular condensates (BMCs). Known BMCs exhibit liquid-like properties and are typically visualized on the scale of ~1 um. They have been studied mostly by microscopy, examining select individual proteins. Here, we investigate the global organization of native cytoplasm with quantitative proteomics, using differential pressure filtration, size exclusion, and dilution experiments. These assays reveal that BMCs form throughout the cytosplasm, predominantly at the mesoscale of ~100 nm. Our data indicate that at least 18% of the proteome is organized via such mesoscale BMCs, suggesting that cells widely employ dynamic liquid-like clustering to organize their cytoplasm, at surprisingly small length scales.

Openhole Multistage Completion Evaluation Incorporating Deployment of Downhole Shut-in Tool Application in Sour Carbonate Gas Wells, Field Application

This paper highlights the first successful application of a field deployment of a high-temperature (HT) downhole shut-in tool (DHSIT) in multistage fracturing completions (MSF) producing retrograde gas condensate and from sour carbonate reservoirs. Many gas operators and service providers have made various attempts in the past to evaluate the long-term benefit of MSF completions while deploying DHSIT devices but have achieved only limited success (Ref. 1 and 2). During such deployments, many challenges and difficulties were faced in the attempt to deploy and retrieve those tools as well as to complete sound data interpretation to successfully identify both reservoir, stimulation, and downhole productivity parameters, and especially when having a combination of both heterogeneous rocks having retrograde gas pressure-volume-temperature (PVT) complexities. Therefore, a robust design of a DHSIT was needed to accurately shut-in the well, hold differential pressure, capture downhole pressure transient data, and thereby identify acid fracture design/conductivity, evaluate total KH, reduce wellbore storage effects, properly evaluate transient pressure effects, and then obtain a better understanding of frac geometry, reservoir parameters, and geologic uncertainties. Several aspects were taken into consideration for overcoming those challenges when preparing the DHSIT tool design including but not limited to proper metallurgy selection, enough gas flow area, impact on well drawdown, tool differential pressure, proper elastomer selection, shut-in time programming, internal completion diameter, and battery operation life and temperature. This paper is based on the first successful deployment and retrieval of the DHSIT in a 4-½" MSF sour carbonate gas well. The trial proved that all design considerations were important and took into consideration all well parameters. This project confirmed that DHSIT devices can successfully withstand the challenges of operating in sour carbonate MSF gas wells as well as minimize operational risk. This successful trial demonstrates the value of utilizing the DHSIT, and confirms more tangible values for wellbore conductivity post stimulation. All this was achieved by the proper metallurgy selection, maximizing gas flow area, minimizing the impact on well drawdown, and reducing well shut-in time and deferred gas production. Proper battery selection and elastomer design also enabled the tool to be operated at temperatures as high as 350 °F. The case study includes the detailed analysis of deployment and retrieval lessons learned, and includes equalization procedures, which added to the complexity of the operation. The paper captures all engineering concepts, tool design, setting packer mechanism, deployment procedures, and tool equalization and retrieval along with data evaluation and interpretation. In addition to lessons learned based on the field trial, various recommendations will be presented to minimize operational risk, optimize shut-in time and maximize data quality and interpretation. Utilizing the lessons learned and the developed procedures presented in this paper will allow for the expansion of this technology to different gas well types and formations as well as standardize use to proper evaluate the value of future MSF completions and stimulation designs.

Case Study- Real Time Downhole Telemetry CCL and Tension Compression, a Differentiator for Successful Manipulation of ICD's in Horizontal Wells

Horizontal well completions are often equipped with Inflow Control Devices (ICDs) to optimize flow rates across the completion for the whole length of the interval and to increase the oil recovery. The ICD technology has become useful method of optimizing production from horizontal wells in a wide range of applications. It has proved to be beneficial in horizontal water injectors and steam assisted gravity drainage wells. Traditionally the challenges related to early gas or water breakthrough were dealt with complex and costly workover/intervention operations. ICD manipulation used to be done with down-hole tractor conveyed using an electric line (e-line) cable or by utilization of a conventional coiled tubing (CT) string. Wellbore profile, high doglegs, tubular ID, drag and buoyancy forces added limitations to the e-line interventions even with the use of tractor. Utilization of conventional CT string supplement the uncertainties during shifting operations by not having the assurance of accurate depth and forces applied downhole. A field in Saudi Arabia is completed with open-hole packer with ICD completion system. The excessive production from the wells resulted in increase of water cut, hence ICD's shifting was required. As operations become more complex due to fact that there was no mean to assure that ICD is shifted as needed, it was imperative to find ways to maximize both assurance and quality performance. In this particular case, several ICD manipulating jobs were conducted in the horizontal wells. A 2-7/8-in intelligent coiled tubing (ICT) system was used to optimize the well intervention performance by providing downhole real-time feedback. The indication for the correct ICD shifting was confirmed by Casing Collar Locator (CCL) and Tension & Compression signatures. This paper will present the ICT system consists of a customized bottom-hole assembly (BHA) that transmits Tension, compression, differential pressure, temperature and casing collar locator data instantaneously to the surface via a nonintrusive tube wire installed inside the coiled tubing. The main advantages of the ICT system in this operation were: monitoring the downhole force on the shifting tool while performing ICD manipulation, differential pressure, and accurately determining depth from the casing collar locator. Based on the known estimated optimum working ranges for ICD shifting and having access to real-time downhole data, the operator could decide that required force was transmitted to BHA. This bring about saving job time while finding sleeves, efficient open and close of ICD via applying required Weight on Bit (WOB) and even providing a mean to identify ICD that had debris accumulation. The experience acquired using this method in the successful operation in Saudi Arabia yielded recommendations for future similar operations.

SmartWater Synergy with Microsphere Injection for Permeable Carbonates

This paper presents a laboratory study on combination of SmartWater with microsphere injection to improve oil production in carbonates, which increases the sweep efficiency and oil displacement efficiency. In this study, the properties of a micro-sized polymeric microsphere were investigated including size distribution, rheology, and zeta potential in SmartWater, compared with conventional high salinity injection water. Coreflooding tests using natural permeable carbonate cores were performed to evaluate flow performance and oil production potential at 95°C and 3,100 psi pore pressure. The flow performance was evaluated by the injection of 1 pore volume microspheres, followed by excessive water injection. Oil displacement tests were also performed by injecting 1 pore volume of microspheres dissolved in SmartWater after conventional waterflooding. The median particle size of the microsphere in conventional injection water with a salinity of 57,670 ppm was about 0.25 µm. The particle size was increased by 50% to 100% with reduced elastic modulus when the microsphere dispersed in SmartWater with lower salinity. The zeta potential value of microsphere was decreased in SmartWater compared to that in conventional injection water, showing more negatively charge property. Flow performance of microsphere solutions in the carbonate cores was found to be dependent on their particle size, strength, and suspension stability. The results from coreflooding tests showed that the microsphere dispersed in SmartWater would result in higher differential pressure than that observed in conventional injection water. The SmartWater caused the microspheres swell to larger but softer particles with better suspension stability, which enhanced both the migration and blocking efficiency of microsphere injection. The oil displacement tests confirmed that the microsphere in SmartWater displaced more oil than that obtained with conventional injection water. This result was clearly supported by the higher differential pressure from microsphere injection in SmartWater. The oil bank appeared historically in the post water injection stage, which was quite different from the reported findings of typical mobility controlling agents in the existing knowledge. The microspheres were observed in the core flood produced fluids, indicating the improvement of microsphere migration by SmartWater. This work, for the first time, demonstrated that the combination of SmartWater and microsphere injection yields additional oil production. The proposed hybrid technique can provide a cost-effective way to improve waterflooding performance in heterogeneous carbonates.

Extending ESP Run Life By Reducing Shutdowns and Improving Restarts Using Novel Pump Protection Technology

Meeting the production demand in today's market without sacrificing performance of the artificial lift method is critical. Aggressive flowback procedures lead to solids production and unplanned electric submersible pump (ESP) shutdowns because of solids overload. A novel pump protection system has been designed, tested, and installed in the field. The system enhances the ESP life, improves restarts, and reduces downhole vibrations and unplanned shutdown by controlling the solids flowback and sending solids-buildup pressure signals. A comparative study on three ESP wells in the Delaware basin (US) demonstrated the efficacy of the system. The system comprises of an intake sand control screen and valve assembly. The novel stainless steel wool screen acts as a three dimensional (3D) filter capable of filtering out particles of 15 to 600 μm, and the valve assembly activated by differential pressure across the screen creates a secondary flow path to allow cyclic cleanup of the screen. Stainless steel wool screen with variable pore sizes is used as the sand control media for its high efficiency in preventing the flow of most of the solid particles. When the solids build up on the screen surface, the valve assembly opens upon reaching a preset differential pressure to enable flow past the screens and into the ESP and allows sands deposited on the screen surface to fall off. The pump protection assembly was tested at surface and installed in three wells along with downhole ESP gauges measuring pressure, temperature and vibrations after pulling out existing ESP completions. Qualification testing confirmed the opening of the valve assembly after solids buildup on the stainless steel wool screen. It also validated that the deposited sand fell-off from the screen surface after flow diverted through the valve assembly and pressure differential across screen dropped. In the field installations, the run life of the ESPs improved by an average of 35%, with comparable production volumes and slow drawdowns. In addition, the number of ESP shutdowns related to sand and solids was reduced by as much as 75%, improving longevity of electrical components. The success rate of ESP startups after planned and unplanned shutdowns also improved by 22%. The increase in inlet pressure captured via the downhole gauges when the valve assembly opened indicated the sand control prevention and mitigation system was bridged, and ESP replacement should be scheduled to minimize deferred production from a solids-induced ESP failure and to minimize surface solids management costs. The vibration signal data obtained from downhole sensors confirmed the reliability of the system. Overall, results demonstrate that the system designed is successful at increasing ESP run life without detriment to well production performance. The new, field-proven pump protection system along with its components and the completion design substantially increase life of ESP by reducing the number of shutdowns related to sand overload, reducing shutdowns, reducing overall vibrations, increasing the probability of successful start after shut-in, and increasing the performance reliability during fracturing of a neighboring well. Consequently, more wells that are looking to increase the ESP life can now benefit from this technology and increase output.

Using an Adjustable Cone Meter to Measure Wet Gas

A traditional fixed size Venturi meter has a turndown of about 8:1 under dry gas conditions that may drop to as low as 3:1 under wet-gas flow. When the well conditions change, a replacement of the original Venturi meter with one of a different size is needed. In this paper, we present the design, development and testing of an Adjustable cone meter that has the ability to adapt itself to the flow conditions automatically and provide a turndown of as much as a 54:1 under dry gas conditions and as much as 20:1 under wet-gas conditions. The patented feature of the Adjustable cone meter is the adjustable sleeve that moves over the cone when the flow rate decreases below a preset value causing an increase in the differential pressure across the meter. In addition, traditional Venturi meters have only one differential pressure measurement and the sensor tends to overestimate the flow when there is liquid present in the flow (wet-gas). The Adjustable cone meter has two differential pressure sensors and the second measurement is used to estimate the liquid content in wet-gas. Two meters were manufactured and tested at the National Engineering Laboratory in East Kilbride, Scotland under gas flow rates of up to 18 MMscfd. Based on the differential pressure measurements under varying flow conditions, algorithms were developed to measure the dry gas and liquid fraction. An over-reading model of the meter and a liquid fraction estimation model based on the pressure loss ratio was derived from an additional differential pressure measurement. The model was used to not only to quantify the gas and liquid flow rates but also the estimated error in each measurement. The measurements show that the Adjustable Cone meter is able to provide low uncertainty in both dry and wet gas conditions and met the conditions outlined in ISO 5167-5. The Adjustable cone meter is a much needed innovation in the area of differential pressure measurement.

Use of Obturating Pills Combined with Low Concentration Acid Pills to Overcome Differential Stuck Challenges in Highly Deviated Wells

In 2020, A Major Offshore Operating Company in UAE faced a high differential pressure stuck event. This took place, during the execution of formation evaluation with a conveyed pipe sampling BHA. It is well known that after a differentially stuck pipe event happens, the success ratio will be time dependent (i.e. the less time a pipe remains stuck, the more chances there will be for it to become released) and the chances of releasing the BHA are always limited to the logging tools tensile limitations. One of the most common and successful methods to release differentially stuck BHA's specifically in limestone formations is by pumping and soaking acid pills. However, under such a high differential pressure environment, the use of acid may induce losses in the so called "thief zones", causing worse problems. The standard release procedure started by working the string within the tensile limits, followed by pumping acid pills (using the available volume mobilized before spudding each drilling section). During the first acid pills pumped to attempt to release the stuck pipe, loss volume pump rates, acid pill position(s) and coverage in the annulus was assessed and evaluated. Based on the results it was observed that the thief zone was in direct contact with the Pipe Conveyed circulation port, at the latching assembly. This then created a situation whereby, the acid pills were lost immediately after the acid came into contact with the formation. Utilizing low acid concentration pills also had the same effect. The solution was to pump an Obturating pill made-up of a weighting agent as a spacer behind the high volume, low concentration acid pill with crosslinking divergent chemicals, pumped at a high flow rate. This solution reduced the acid losses across the thief zone and once the Obturating pill came into contact with the loss zone, it facilitated the seal and cured the losses, by allowing the acid to move up the annulus until it reached the differentially stuck point and soaked across the problematic area. Once the acid pill was successfully placed at the required location using this method, the string was worked and successfully released. This combination of low concentration acid along with crosslinking divergent chemicals coupled with the Obturating pill behind the acid helped a major offshore operating company to pump the acid pill under partial losses only, to regain full circulation after only 10 bbl. of Obturating pill had entered inside the annulus. It allowed the acid pill to react across the stuck point, while keeping the string under low torque and compression. The operator was able to release the sampling BHA and bring it back to surface avoiding a lost in hole cost of around 4 MM$. The Obturating pill combined with low concentration CDC acid pill is proven to be a successful method in drilling operations when trying to release differentially stuck BHA's within a wellbore.