Hydrocarbons are trapped at great depths with pressure and temperature higher than surface conditions which would vary depending on reservoir properties. When the well is set on production, these hydrocarbons travel through the wellbore over reducing geothermal and formation pressure gradients. Hence, at shallower depths the temperature drops below the cloud point and sometimes, below pour point of crude thus creating an ambient temperature for the formation of wax and deposition of paraffin on the inner side of production tubing.
It has been observed that when hot fluid passes through a pipe which is covered by a continuously circulating hot water bath, the temperature difference of the fluid at surface outlet and sub-surface reservoir is reduced to a minimal value. This paper therefore proposes a practical application of such heat transfer within a wellbore for passively solving major industrial issues of paraffin depositions. The idea lies in minimizing the heat losses, which can be effectively done by insulating the inner side of the casing so that the annulus and fluid flowing within the tubing is isolated from exterior losses. According to the First law of Thermodynamics the fluid flowing within the tubing will experience reduction in thermal gradient. These loses can be compensated by injecting hotter brine through a pipe at the bottom of the annulus, which is isolated, using production packer. Further, circulating hot fluid in the annulus would result in isothermal heating of the fluid flowing through the tube which would minimize the heat loss across tubing, causing an increase in temperature of fluid at the surface above pour point. Several researchers have put forth heat transfer equations across the tubing's, annulus, insulator, casing, cement and the formation which can be used to calculate the overall heat transfer coefficient and thus, the amount of heat losses. Quartz sensors placed at the bottom of a wellbore would detect bottom borehole temperature based on which the injection temperature of fluid can be manipulated. The entire process can be automated by applying an artificial intelligent system which would monitor, control and respond. This method would increase the capex but would decrease the operating cost thus leading to an increase in the life of the well.
Wellbore instability is caused by the radical change in the mechanical strength as well as chemical and physical alterations when exposed to drilling fluids. A set of unexpected events associated with wellbore instability in shales account for more than 10% of drilling cost, which is estimated to one billion dollars per annum. Understanding shale-drilling fluid interaction plays a key role in minimizing drilling problems in unconventional resources. The need for efficient inhibitive drilling fluid system for drilling operations in unconventional resources is growing. This study analyzes different drilling fluid systems and their compatibility in unconventional drilling to improve wellbore stability.
A set of inhibitive drilling muds including cesium formate, potassium formate, and diesel-based mud were tested on shale samples with drilling concerns due to high-clay content. An innovative high-pressure high temperature (HPHT) drilling simulator set-up was used to test the mud systems. The results from the test provides reliable data that will be used to capture more effective drilling fluid systems for treating reactive shales and optimizing unconventional drilling.
This paper describes the use of an innovative drilling simulator for testing inhibitive mud systems for reactive shale. The effectiveness of inhibitive muds in high-clay shale was investigated. Their impact on a combination of problems, such high torque and drag, high friction factor, and lubricity was also assessed. Finally, the paper evaluates the sealing ability of some designed lost circulation material (LCM) muds in a high pressure high temperature environment.
Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Alkinani, Husam H. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Amer, Ahmed S. (Newpark Technology Center/ Newpark Drilling Fluids)
Equivalent circulation density (ECD) management is a key factor for the successfulness of the drilling operations, especially when dealing with narrow mud-weight windows. Poor management of ECD can result in unsafe and/or inefficient drilling as well as an increase in drilling cost due to associated nonproductive time (NPT). Different parameters can affect the ECD directly or indirectly including, but not limited to, wellbore geometry, cuttings, hole cleaning efficiency, flow rate, and rheological properties of the drilling fluid. However, the magnitude of the effect of each parameter is not well understood. In this paper, a comprehensive statistical analysis using the correlation coefficient was conducted using real field data to investigate the effect of three controllable factors - solid contents (SC), yield point (Yp), and plastic viscosity (PV) - on ECD.
The novel nanomaterial composition described in this paper has been designed to treat moderate to severe losses. The nanomaterial composition comprises an environmentally friendly nanoparticle based dispersion and a chemical activator. The design is based on a delayed activation chemistry to gel up a nanoparticle based dispersion.
Three different types of nanoparticles were used in the study to develop the novel loss circulation material. Two different types of negatively charged nanoparticle based dispersion and one positively charged nanoparticle based dispersion were used in the study. An inorganic activator has been used for the study. The effect of this inorganic activator on the gelation properties of the nanoparticle based dispersion was investigated. The gelling times were evaluated at different temperatures up to 300°F. The effect of activator concentration on the gelling time of the new composition has also been studied. The effectiveness of the newly developed composition as a loss circulation treatment was also evaluated by performing permeability plugging tests to test the plugging capacity of this novel system.
The novel nanomaterial composition is designed so as to have a controllable gelation time under a variety of downhole conditions to allow accurate placement of the treatment fluid inside the wellbore without premature setting of the fluid. It was shown that the gelation time of the treatment composition could be controlled by adjusting the concentration of the activator. The system is designed so as to give a predictable and controllable pumping time, ranging from a few minutes to several hours at over a wide range of temperatures. This is an important advantage as it allows the loss circulation composition to remain pumpable for sufficient time for placement and develops the network structure that leads to gelation, over a predictable period of time. The set gel, which appears as a crystalline solid, could remain homogenous and stay in place thereby preventing loss circulation.
Commonly used fluid loss additives (FLAs) in today's invert emulsion drilling fluids include materials with various attributes. The unmet needs of existing materials may include: Environmental restrictions due to ecotoxicity or biodegradability concerns Performance issues at high temperatures Overdosing at high temperatures High costs Formation damage
Environmental restrictions due to ecotoxicity or biodegradability concerns
Performance issues at high temperatures
Overdosing at high temperatures
To address these challenges, a FLA was developed for invert emulsion drilling fluids that is made from a renewable raw material and performs at high temperature and high pressure. The renewable raw material used to make this novel FLA is a biopolymer byproduct of the paper pulping process, and was chemically modified under controlled conditions to create a high-performing FLA. Detailed testing was done to determine the additive's performance in different base oils (mineral and diesel), at various mud weights (12 to 16 ppg), at elevated temperatures and in different fluid systems characterized by rheology and high-pressure, high-temperature (HPHT) fluid loss. The novel FLA was compared to other commercially available FLAs for fluid loss performance.
The novel FLA outperformed or was on par with the industry available FLAs tested in this study. The novel FLA realized comparable fluid loss performance of less than 10 ml at 375 F at lower concentrations as compared to the industry FLAs. In some cases, the novel FLA performed at higher temperatures, whereas some of the industry available FLAs did not. The novel FLA also boosted the electrical stability (ES) of the emulsion in certain fluid systems. The novel FLA showed minimum change in the rheology of the oil-based fluids as compared to the industry available FLAs. The novel FLA demonstrated reasonable performance in different mud weights, base oils and fluid systems. Since this novel FLA is derived from a renewable raw material, it may have less of an environmental impact compared to other FLAs utilized today.
The novel FLA: Was developed from a renewable raw material for invert emulsion drilling fluids; Performed on par or outperformed industry available FLAs; and Boosted the ES of the emulsion for certain fluid systems.
Was developed from a renewable raw material for invert emulsion drilling fluids;
Performed on par or outperformed industry available FLAs; and
Boosted the ES of the emulsion for certain fluid systems.
Drilling in high pressure high temperature (HPHT) deep gas reservoirs, with multiple shallow different pressure horizons, requires special techniques which include application of Managed Pressure Drilling (MPD), revising casing setting depths, improving casing strength, and refining mud design. This paper focuses on application of MPD in HPHT gas wells and also describes briefly other techniques which can improve drilling performance and reduce nonproductive time.
Wang, Gang (China University of Petroleum-Beijing) | Fan, Honghai (China University of Petroleum-Beijing) | Zhang, Wei (CNPC Engineering Technology R&D Company Limited) | Yang, Yang (China University of Petroleum-Beijing) | Han, Zili (CNPC Bohai Drilling Engineering Company Ltd.) | Wu, Hongxuan (CNPC Chuanqing Drilling Engineering Company Ltd.) | Li, Wanjun (CNPC Engineering Technology R&D Company Limited) | Li, Jiaying (CNPC Engineering Technology R&D Company Limited) | Zhou, Tuo (CNPC Engineering Technology R&D Company Limited) | Zhou, Haiqiu (CNPC Engineering Technology R&D Company Limited) | Liu, Jitong (CNPC Engineering Technology R&D Company Limited)
M15 well contains complex intervals, where anticlinal structures developed from faults make long mudstone barriers full of cracks, which makes it hard to predict pore pressure. Loss is one of the most serious problems during drilling and cementing, while blow out accidents happen sometimes. Previous casing programs hardly adjust to all complex intervals and conventional LCMs (loss control materials) play few roles. As a result, designated targets used to be rarely reached.
It is proved that low pressure intervals shall be isolated firmly and complex intervals as well as reservoirs should be developed in independent intervals, thus casing programs have been modified. 188 lab tests were finalized, including 180°C hot rolling, anti-contamination test, lubricity test and inhibition experiments, in order to develop a kind of organic salt mud system that has premium inhibition, plugging, lubricating, heat & salt resistance properties. Precise MPD (managed pressure drilling) techniques are recommended to achieve near-balance drilling operation, solving borehole instability problems to some extent.
In the second interval the organic salt mud system is applied, while logging and casing running may be accomplished in one time. Besides, strings can be tripped out smoothly and high pressure brine productive zones are drilled safely. φ339.7mm casing joints are set at the depth of 3848m in the second interval and φ244.5mm casing joints are set at the depth of 5177m in the third interval, in order that deeper complex formation may be developed in a separate casing interval in which precise MPD is applied with LCMs while drilling and compound plugging agents. Therefore, downhole pressure is precisely controlled and large cracks are plugged statically on 28 occasions. Designated targets have been all reached and 20 oil & gas productive layers have been developed.
Downhole complexities arising from loss and blowout have been solved in M15, where φ339.7mm casing was set at the deepest interval in CNPC overseas operation history, making a new record of safe drilling operation, borehole quality and cementing quality. More oil and gas productive zones have been discovered and all designated targets have been achieved. New drilling experience got from M15 has significant meanings in the development of similar blocks.
Patel, Niley (Scaled Solutions LLC) | Rafferty, Andrew (Scaled Solutions Ltd) | Stewart-Liddon, Christine (Scaled Solutions Ltd) | Hammonds, Paul (Scaled Solutions Ltd) | Graham, Gordon M. (Scaled Solutions Ltd) | Maskell, Phillip (Scaled Solutions Ltd) | Frigo, Dario M. (Plinius Chemical Consulting)
A technique has been developed to allow for the comparison of scavenging rates and scavenging capacity of different hydrogen sulphide scavengers by continuously measuring the hydrogen sulphide concentration in the gas phase of a multiphase system. In addition, the stability of the scavenger reaction products has also been investigated.
The methodology to assess the performance of the hydrogen sulphide scavenger is described. The scavenging rates of the hydrogen sulphide scavenger are compared by the contact time required to reduce the initial hydrogen sulphide concentration to a pre-determined value. In addition, the scavenging capacity of the scavengers can be calculated by recording the gaseous hydrogen sulphide concentration once the reaction has been allowed to run to completion. Finally, the stability of the scavengers and their reaction products, including carbon disulphide, are determined by treating a solution of the scavenger with excess hydrogen sulphide.
It is known that hydrogen sulphide scavengers have the potential to form reaction products that can foul the refining process. More recently, it has been identified that carbon disulphide may be produced during the scavenging reaction of some commonly used triazine based chemistries, driving a desire to identify alternative products. These works describe a new method which is capable of differentiating between the hydrogen sulfide scavenging performance of different chemistries. It also allowed for the scavengers to be differentiated with respect to the formation of both solid and oil soluble by-products, with the presence / increase in carbon disulphide analysed by gas chromatography. By doing this, the method allows for improved scavenger selection on the basis of performance, compatibility and cost.
This work presents a novel method for the assessment of relative reaction rates and scavenging capacity of hydrogen sulphide scavengers. In doing so, it allows the evaluation of cost performance and suitability of different treatments and scavenger chemistries to be evaluated. Additionally, the likelihood of a scavenger chemistry fouling the refining process due to the production of reaction by-products can be investigated.
Acid stimulation in sandstone reservoirs containing significant amount of clays can end up with undesired results due to unexpected reactions between stimulation fluids and formation clays. This paper demonstrates how heavily damaged clay-rich sandstone reservoir completed with cased hole gravel pack (CHGP) in offshore Myanmar can be successfully established for commercial production with organic clay acid stimulation treatment. The formation is laminated dirty sand with very high clay content (up to 30%) and large gross height (>100m MD). Production logging results showed only a small portion of perforated intervals contributing to production. Thus, an appropriate stimulation treatment is required to unlock well potential and prevent screen failures from concentrated flow through a small interval.
Given high clay content as well as presence of acid sensitive clays, conventional treatments using HCl as preflush and hydrofluoric (HF) acids as main fluids would result in potential damages from secondary and tertiary reactions. Furthermore, undissolved clays in the critical matrix left over from the treatment would potentially migrate and plug the pore throat. The new acid system was designed to generate small amount of HF in-situ (~0.1%) at any given time with total strength of 1% HF, which would greatly minimize second and tertiary reactions and also permits acids travel deeper into the formation. Furthermore, the reaction products would react with the clays and physically "welding" the undissolved clays to the surface of the pore spaces permanently and prevent them from migration.
The treatment was designed in three stages: 1) screen and gravel pack cleanup using coiled tubing (CT) jetting; 2) injectivity test; 3) main treatment consisting of acetic acids as preflush, and new acid system as main fluids followed by overflush. A newly designed linear gel containing relative permeability modifier was used for diversions. Two underperforming CHGP wells were treated, and both wells yielded 100% increase in productivity with no fine production observed at the surface.
The success of the campaign owes to the sophisticated engineering workflow which starts from diagnostic of the damage zone and root-cause of the formation damage, followed by detailed analysis of various skin components using radial numerical reservoir modeling for all the reservoir layers that led to a proper treatment strategy and fluid design based on the damage and formation mineralogy as well as comprehensive laboratory tests. This has helped to minimize the risk of the treatment and eventually unlocked the production from the heavily damaged sandstone reservoir.
Li, Wai (The University of Western Australia) | Liu, Jishan (The University of Western Australia) | Zhao, Xionghu (China University of Petroleum Beijing) | Jiang, Jiwei (China University of Petroleum Beijing) | Peng, Hui (Beijing Oilchemleader Science & Technology Development Co., Ltd.) | Zhang, Min (Shengli Oilfield Exploration and Development Research Institute) | He, Tao (GWDC Drilling Fluid Company, PETROCHINA) | Liu, Guannan (China University of Mining and Technology) | Shen, Peiyuan (The University of Western Australia)
Biodiesel-based drilling fluid (BBDF) draws considerable attention because biodiesel has excellent environmental acceptability and great potential to provide high drilling performance. There are some investigations reported about BBDF both in laboratory and in the field recently, demonstrating its feasibility. In contrast to traditional petrodiesel and mineral oil, biodiesel has some chemical activity which affects the reliability of BBDF in drilling environment. This paper details the principles and strategies for developing and selecting additives of BBDF. A variety of experimental results obtained by laboratory tests were presented to elucidate the importance of suitable additives for an eligible BBDF. Electrical stability test and centrifuge test were conducted to evaluate the effectiveness of emulsifier. A six-speed viscometer and a high-pressure-high-temperature (HPHT) rheometer were used to measure the parameters of BBDF to evaluate organophilic clays and rheological modifiers. Density test was performed to investigate the suspendability of the fluids. Hot rolling treatment was carried out to study the thermal tolerance of the fluids. The laboratory results and the literature showed that both lime content and calcium chloride concentration have significant effects on the stability and rheological parameters of BBDF. Even moderate amount of lime in BBDF will significantly decrease the stability of BBDF. The effect of calcium chloride concentration on BBDF varies according to the type of emulsifier. A compound emulsifier based on fatty alkanolamides and alkyl sulfonates exhibits reliable ability to prepare stable, thermal-tolerate invert biodiesel emulsion. It offers biodiesel emulsion reduced viscosity compared to those given by traditional Span/Tween emulsifier combinations. For another, commercial organophilic clays cannot give satisfactory rheological parameters because the viscosity-temperature profile of BBDF is often steeper than those of traditional oil based drilling fluids (OBDFs). Therefore, rheological modifier should be used to compensate the viscosity loss of BBDF under high-temperature conditions. A condensate of alkoxylated fatty amine and polycarboxylic acid showed good performance to provide a relatively flat rheological profile. Some empirical laws, principles and strategies are summarized for BBDF additive selection. One is that the combinations of non-ionic and anionic emulsifiers have better effectiveness for biodiesel. The other conclusion is that lime content must be strictly controlled. With the boom of the biodiesel industry, it is predicted BBDF will take a place in the family of drilling fluid. However, most previous works show that BBDF may be not satisfactory when the temperature is over 120 Celsius degrees. This work presents valuable experience for further improvement of this promising drilling fluid.