The oil-water interfacial tension (IFT) is by all means important in capillary pressure estimation and fluid-fluid and fluid-rock interactions analysis. Observations from experimental data indicate that oil-water IFT is a function of pressure, temperature, and compositions of oil and water. A reliable correlation to estimate oil-water IFT is highly desire. Unfortunately to our best knowledge no correlation that uses the compositions of oil and water as inputs is available. Our work is to fill this gap.
In this research, we collected data from former studies and investigations and developed a correlation for oil-water IFT. In the proposed correlation oil-water IFT is a function of system pressure, temperature, and compositions of oil and water. Error analysis was conducted to check the accuracy of the equation by comparing the calculated values with the experimental data. The results indicated that the new correlation predicts reliable oil-water IFTs. Our correlation calculates the oil-water IFT from system pressure, temperature, and compositions of oil and water. It addresses the effect of composition of oil on IFT, which is not presented in existing correlations. Therefore it can not only be applied in the calculation of capillary pressure in the compositional simulation, but also be used in daily petroleum engineering calculation such as waterflooding analysis.
Hole enlargement is a serious problem while drilling in permafrostconditions. The hole enlargement problems leads to lost circulation. Irregularand unstable holes also affect the quality of cement jobs. The drilling fluidis generally at a higher temperature than the permafrost formation. This causesa heat transfer from the drilling fluid to the formation. The ice particlesbinding the sediments together start to melt. This loosens up thesediments and causes caving. This paper proposes to minimize this problem witha low thermal conductivity fluid.
The drilling fluid can be cooled at the surface after it comes out of theannulus and before it is circulated back into the drill string. Cooling reducesthe temperature gradient between the fluid and formation. But this cooling isnot enough since the permafrost is at subzero temperatures and cooling to suchlow temperatures is not economically and practically feasible. This is wherethe innovative drilling fluid comes in. The drilling fluid shall have hollowmicrospheres. These microspheres are easily available commercially undervarious trade names. These microspheres lower the heat transfer coefficient ofthe fluid. This means that a significantly small amount of heat will betransferred from the drilling fluid to the formation. Low temperaturegradient and low thermal conductivity will work in conjunction.
The drilling fluid shall have a low heat transfer coefficient of 2.9-3BTU/hr.ft2.oF. The composition of the fluid and the heattransfer coefficient measuring experimental setup shall be discussed in thepaper. The paper shall also discuss the effects of heat transfer coefficient,circulation rates etc. on the thawing of permafrost.
The technique in this paper could go a long way in mitigating drillingproblems in permafrost regions.
Ilyas, Muhammad (Mari Gas Company Limited) | Sadiq, Nauman (Dowell Schlumberger Western S.A.) | Mughal, Muhammad Ali (Mari Gas Company Limited) | Pardawalla, Hassan (Dowell Schlumberger Western S.A.) | Noor, Sameer Mustafa (Dowell Schlumberger Western S.A.)
This research work "Improvement of Cementing in Deep Wells" was carried out with the collaboration of Mari Gas Company Limited (MGCL), Pakistan and Schlumberger Pakistan, to recommend the designs and practices by which future cementing operations for zonal isolation in deep Wells may be improved.
Mari Gas Company Limited had successfully drilled, tested and completed Halini Well - 1 (Total Depth = 5350 m) in the Karak Block. The Karak Block is located in Northern Region of Pakistan which is known for its challenges, such as high pressure water influxes and weak zones, which led to a number of cementing challenges in this Well. The Cementing related problems that were faced on this Well were:
1- Sustained Casing Annulus Pressure in 13 3/8" x 9 5/8" Casing Annulus
2- Poor CBL-VDL results in 13 3/8" and 9 5/8" Casing
The scope of the project was to investigate the root cause of cementing challenges faced at Halini Well-1 and to propose recommendations for improving future cementing in deep Wells.
s to the above, the cementing of Halini Well- 1 was thoroughly analyzed along with similar case histories and problems in offset fields. On the basis of observations made, various recommendations have been proposed, mostly related to areas of fluid rheology, fluid contamination, fluid channeling, density and friction pressure hierarchy between fluids, fluid loss, temperature differential, and setting of casing slips etc. The idea for this project is to serve as a guideline for cementing the future deep Wells.
Primary Cementing is the process of placing cement between casing and the formations exposed to wellbore . The objective is to provide Zonal Isolation by creating a hydraulic seal thereby preventing the flow of wellbore fluids like oil, water or gas between formations or to surface. The life of the Well is directly dependent on the quality of this hydraulic seal, making cementing job a vital operation.
Incomplete zonal isolation can prevent either the Well from being completed at all to a loss of a producing well. The importance of cementing operation can be magnified by the fact that the cement has to survive the complete life of the Well that could vary anywhere between a year to fifty or more years.
Successful cementing operation would include a good casing to cement bond, good cement to formation bond and the ability of the cement placed itself to prevent any flow through it. In the event of this hydraulic seal being ineffective, it can allow fluids to migrate and channel through in the annulus and potentially even flow to the surface. This destroys the integrity of the Well. Any remedial job is extremely difficult to plan, execute and usually carries very low chances of success.
Newly developed drilling automation systems locate a computer interface between commands issued by the driller and instructions transmitted to the drilling machinery. Such functions are capable of faster and more precise control than can be achieved by an unaided operator and thus can help drilling within narrow margins. To ensure that these systems work properly in all circumstances, an advanced drilling simulator has been developed to enable testing under a wide range of simulated conditions. The environment described in this paper uses hardware in the loop (HIL) simulation to verify that the automation techniques being tested respond correctly in real time. Rigorously validated physical models of the drilling process simulate the response of the well to the commands given to the drilling machines. Abnormal drilling conditions (e.g., packoffs, kicks) and equipment or machine-related problems (e.g., plugged nozzles, power shortage) are convincingly recreated. The drilling simulator models the behavior of surface equipment such as the activation of gate valves to line up different pits or the flow in the mud return. It simulates changes in the drilling fluid properties when mixing additives to the mud. It is therefore possible to focus training sessions on cooperation between different groups at the wellsite. This is particularly useful when planning the introduction of drilling automation that involves new work procedures as a result of automation and adaptation of the drilling team to a new operational environment. Drilling operations are becoming more and more complex. Automation has the potential to provide large improvements in efficiency and safety, but automation technologies must be implemented correctly at the workplace. Just as the aviation industry has used simulated environments for decades, drilling simulation environments are the key to the safe and successful implementation of drilling automation and the development of crew skills to face future challenges.
The oil-based drill solids are regarded as controlled or hazardous waste since it is contaminated with oil and other organic/inorganic contaminants. As such, the drill solids can be disposed with 3 different ways: (1) decontamination treatment before discharged into the sea; (2) re-injecting the drill solids into the well or (3) hazardous waste controlled landfill. The disposal of the drill solids in the landfills is usually the last environmental option. The lowest environmental impact way for the solid disposal, especially for offshore operation, is still a decontamination treatment before discharged. However, the conventional decontamination technology still exhibits limited efficiency to extract oil from the drill solids; yielding the oil content in the treated solids of much greater than 1% oil content in the dried solids, which does not meet a strict environmental regulation in many highly ecological-sensitive countries (e.g. UK and North Sea countries, etc.).
This paper demonstrates a new promising technology to overcome this efficiency limitation, called nanoemulsion. Nanoemulsion is a water-in-oil emulsion, having the Winsor type III or IV stages but with high surfactants-to-interface ratio. When analyze using dynamic light scattering, it shows the natural distribution of <100nm particle size. Nanoemulsion is able to provide ultralow interfacial tension (IFT) of <0.01mN/m. According to Laplace Pressure equation, when IFT is extremely low, less energy is required to remove the oil that trapped inside the pores. Recently Nanoemulsion has been demonstrated able to remove sticky oil-base mud inside the wellbore and able to suspend the mud after treatment. When using it to remove the oil from the drill solids, it is able to reduce the contact angle and capillary force on the solid particle surface, subsequently, allowed water to penetrate and wet the particle surface and accessible pores. This mechanism indeed converts the surfaces become water-wet (hydrophilic). Once the particles surfaces are water-wet, oil will instantly desorb from it and easily segregate through centrifuge force. Different proposed process will be shared and discussed in this work. It was found that the oil content in the drill solids after treatment with nanoemulsion cleaning process was able to reach <1%.
Martinez, Erik (Halliburton) | Ramirez, Silvestre (Pemex E&P) | Ramirez Lara, Ricardo (Pemex E&P) | Alvarez Lopez, Eduardo (Pemex E&P) | Bevilacqua, Simon (Halliburton) | Barrera, Guillermo (Halliburton)
The Bolontiku field is located offshore on the continental shelf of the Gulf of Mexico, adjacent to the coast of Tabasco state. This field is composed of dolomitized carbonates of the Upper Jurassic Kimmeridgian formations, which yields 39° API hydrocarbons. Exploitation has dropped the bottomhole pressures from 8,159 psi to 5,600 psi and has created an average operating drilling window of 0.07 g/cm3. Such a narrow operating window increases the technical difficulty for continued development in this mature field using conventional drilling techniques. The complexity of effectively controlling the wellbore pressure has resulted in an endless cycle of fluid loss to formation, kicks, and well control events that translate into non-productive time (NPT), which increased operating time and costs, potentially leading to well abandonment.
A managed pressure drilling (MPD) technique allows for effective control of the pressure profile throughout the wellbore, identifying the bottomhole pressure (BHP) limits and applying appropriate backpressure accordingly. Owing to its efficiency, this technique has evolved from an innovative technology to become a required application to mitigate the inherent wellbore pressure problems associated with conventional drilling. Therefore, as MPD evolves, different approaches for well control evolve for kick events.
This paper describes a well-control application simultaneous to the drilling operation using MPD with a closed-loop pressurized control system. This paper reviews a case history of two wells that were drilled with MPD and compares results against three wells that were conventionally drilled in the Bolontiku field. MPD and simultaneous well control allowed for drilling the Bolontiku 37 well, which consisted of compartmentalized pressure that historically lead to fluid losses and water influxes. Therefore, it was possible to drill through zones that before were not technically possible.
Wellbore strengthening techniques have been used in recent years to increase the capability of wellbores to maintain higher pressures. By increasing the fracture resistance of formations, operators can save rig-time and large volumes of drilling fluids.
The Luna-41 well, offshore Italy, intersects a critical interval comprising high pressurized formations overlaying a lower pressure depleted zone. The initial plan for the well was to divide this interval into two separate hole sections using two different mud systems. A casing string would have been set to isolate the shallower high pressure region followed by an expandable liner to isolate the over pressured shales laying above the depleted reservoir level.
An alternative design was proposed that required only one fluid system and a single casing string, thus saving an expandable liner. Thanks to the wellbore strengthening application and the proprietary continuous mud circulation device, the accomplished well program allowed an 8-day rig-time reduction and a 3-MMUSD cost saving.
A specific modelling tool developed for wellbore strengthening applications was used to assist with fluid design. The tool calculates the width of microfractures induced by differential pressure and the Particle Size Distribution (PSD) of carbonate materials required to plug such microfractures and ultimately strengthen the wellbore.
The mud formulation for Luna-41 was tested in the laboratory using a Pore Plugging Apparatus (PPA) and aloxite discs with pore sizes corresponding to the calculated microfracture width. The fluid used to drill the critical interval was a salt saturated system based on polyglycerol complex and supplemented with a polyamine inhibitor.
The field application was a success. The depleted zone was drilled without incurring lost circulation. This paper describes the results of the field application as well as the fluid engineering process and laboratory testing to highlight the benefits - such as accessing depleted reservoirs and saving casing strings - that wellbore strengthening combined with a continuous mud circulation system can bring to the industry.
When drilling in lost-circulation-prone locations using conventional cements and circulation methods, significant challenges can be encountered during primary cementing operations. Using conventional circulation cementing methods might not be the best choice in circumstances where a wellbore has formations with low fracture gradients unable to withstand the pressure commonly associated with conventional circulation cementing operations. The formation could possibly breakdown under the pressure applied by the cement, causing the cement to be lost into the formation.
Cement lost into the formation is undesirable because of the associated damage and expense. To overcome these challenges, the use of an unconventional cementing method during primary cementing operations is proposed. This method reduces the equivalent circulation densities (ECDs), minimizes excess cement volumes, and eliminates displacement, thereby increasing the chances of a successful cement job with minimum environmental impact. Reverse circulation can significantly reduce bottomhole pressures and allow placement of cement with no apparent losses in many cases. This unconventional cementing method is discussed and a case history is presented.
Mitigating down time, while curing losses, is a critical part of designing and executing a good well plan. Even when anticipated, the loss of drilling fluids to depleted formations is a costly event resulting in excessive down time for the entire rig as well additional costs in replacing costly drilling fluids.
The search for new hydrocarbon reserves increasingly sends us back to proven fields where drilling through depleted zones as become an increasing liability to daily operations. The costly time required to pump multiple activation and deactivation balls down the string makes operating conventional tools tedious and time consuming. A more efficient tool for the placement of lost circulation materials (LCM) that does not require the exorbitant lost time and complicated cycling methods of the current technology has not been available for over a decade.
Today, a new tool, utilizing innovative shifting technology, provides unlimited open / close cycles. With this technology, drillers can shift an unlimited number of times and in as little as 5% of the time required by conventional tools. These capabilities result in direct reduction of lost time operating the tool as well as a quantifiable reduction in fluids lost while operating the tool. Simplified operation also makes the tool uniquely easy to operate reducing the potential for user errors that frequently plague existing technology.
This paper details how the use of this innovative circulating technology has assisted a major service company in reducing downtime and excessive costs during lost circulation events. The design has proven simpler to operate and has effectively reduced the non-productive time and lost fluid versus operation of conventional circulating subs. Supporting case studies are included to detail the increase in efficiency and reduction in costs.
Well plans are continually evolving as we search for ways to keep old field producing. Drilling in existing fields has been a common practice since the first wells were drilled but as these fields are depleted through production and drilling operations empty zones are left behind creating a challenge for the next wells to be drilled in the area. Drilling through these depleted areas often results in additional operations and additional costs that arise from an inability to maintain return flow of drilling fluids from the bit back to the circulating system. Rather than returning to the rig via the annulus, fluid is instead lost to the depleted formation zones resulting wasted material and the need to replace costly drilling fluids before drilling ahead. Apart from the fluid costs, the down or non-productive time (NPT) spent trying to cure these losses extends the time required to reach the planned well depth and ultimately deteriorates the profitability of the well. The need for profitability of course drives us deeper into this situation by pushing operators to squeeze every drop of resource possible out of these fields and in so doing, expose themselves to an increasing risk for high fluid losses.
Ji, Lujun (M-I Swaco) | Guo, Quan (M-I Swaco) | Friedheim, James E. (M-I Swaco) | Zhang, Rui (China University of Petroleum Huadong) | Chenevert, Martin E. (University of Texas At Austin) | Sharma, Mukul Mani (University of Texas At Austin)
Although key shale gas plays vary considerably in terms of reservoir pressure, temperature, mineralogy, and in-situ stresses, the principal drilling-related issues are wellbore stability, shale inhibition, hole cleaning and rate of penetration. Because many of the shale reservoirs are in either environmentally sensitive or densely populated areas, stricter environmental regulations will require new types of environment-friendly water-based drilling fluids. The traditional shale inhibition method through either chemical inhibition or use of invert emulsion drilling fluid is not enough to satisfy the stricter environmental requirements.
This paper focuses on the lab techniques and the performance results of evaluating and analyzing an innovative water-based drilling fluid system containing nanoparticles as a physical shale inhibitor. The physical shale inhibition is achieved by plugging the pores and microfractures in shale with nanoparticles and thus preventing water invasion into the shale. A series of transient pressure penetration or flow-through tests, also known as shale membrane efficiency tests, were performed to evaluate water invasion rates into various shale core samples, with initial brine permeabilities varying from less than 1 nD to over 100,000 nD. Permeability reduction was used as a proxy of water invasion reduction and the effectiveness of plugging of pores and microfractures in shale by the nanoparticles. Many orders of permeability reduction were consistently observed for the drilling fluids with nanoparticles.
Pressure increases in the near-wellbore region due to water invasion during a given time also were analytically calculated using the permeabilities for various fluids which were interpreted from these transient flow-through tests. These pressure increases then were compared to illustrate the approximate impact depth of water invasion and give an indication of shale stability and shale inhibition performance of these drilling fluid systems.
Test results and pressure increase analyses showed that this new water-based drilling fluid with nanoparticles provides an entirely different type of shale inhibition by physically plugging pores and microfractures in shale and meets the strictest environmental regulations for shale gas drilling. The tests also showed that although nanoparticles alone may be effective in preventing water invasion into shale samples with no microfractures, the combination of properly formulated drilling fluid and nanoparticles of appropriate size and concentration is the key to prevent water invasion into shale gas core samples with or without microfractures.
Depletion of many conventional oil and gas reserves and increasing energy demand have heightened the importance of developing techniques to effectively and efficiently drill gas/oil shale. Traditionally, shale is considered as hydrocarbon source rock and/or seal rock only; some shale plays are now recognized as major unconventional hydrocarbon reservoirs. Worldwide, likely recoverable shale gas reserves exceed 250 Tcf by some estimates, with over 10 times that speculated to be in place. In North America, shale gas has been one of the most rapidly expanding trends in onshore domestic natural gas exploration and exploitation (Sandrea 2006).