The superior performance of invert emulsion fluids in challenging drilling operations such as HT/HP wells makes them the preferred fluid for such applications. However, there are instances such as drilling in environmentally sensitive areas, or where costs and logistics become prohibitive, where their use is undesirable. In such circumstances, a high-performance water-based drilling fluid is the only option available. A main challenge in developing a water-based fluid for such applications has been to maintain the stability of key fluid properties such as rheology and fluid loss at temperatures in excess of 130°C. Conventional additives, such as biopolymers or synthetic polymers, either become ineffective at such high temperatures or generate too high a rheology when used in quantities needed to curb fluid loss. This paper discusses a novel water-based drilling fluid system in which the synergy of the key fluid components produces a stable rheology and low fluid loss at temperatures approaching 200°C. Furthermore, by balancing the components of the novel system, fluid rheology can be controlled to meet the hydraulics and hole-cleaning demands of the drilling operation.1, 2
Fang, Xiangdong (California Institute of Technology) | Wang, Qinhong (U. of Missouri Rolla) | Bai, Baojun (California Institute of Technology) | Liu, Cai Xi (California Institute of Technology) | Tang, Yongchun (California Institute of Technology) | Shuler, Patrick J. | Goddard, William A.
This investigation considered engineered rhamnolipid biosurfactants as EOR agents that potentially could be manufactured at low cost from renewable resources, and have lower toxicity than synthetic EOR surfactants. This particular biosurfactant comes mainly from the microbe Pseudomonas aeruginosa. Disadvantages of working with this strain include that the chemical structures of the produced rhamnolipids are not easily controlled, plus there is a preference to use instead a completely non-pathogenic microbe. Towards that end, the study took the approach to clone the genetic information from a P. aeruginosa strain into E. coli to manipulate systematically the structure of the created rhamnolipids and evaluate their EOR performance by themselves (no co-surfactant or viscosity chemical added).
Six E.coli strains (ETRA, ETRAB, ERAC, ETRABC, ETRhl, ETRhl-RC) that carry different combinations of the genes involoved in rhamnolipid bio-synthesis were successfully engineered and tested for their rhamnolipid production. Sand-pack core flooding tests were run to evaluate and compare the effectiveness of these products as agents for enhanced oil recovery. The brine with optimized pH and salt concentration in which a given biosurfactant product has its lowest IFT was used to saturate the core, perform a waterflood, and prepare the surfactant solution. Injection of 6 PV of only a 250 ppm rhamnolipid biosurfactant solution and 4 PV of a brine chaser could recover as much as half of the waterflood residual hydrocarbon (n-octane). The engineered E. coli strains that include more of the implanted genetic code had the better performance in these oil displacement tests. The IFT, biosurfactant concentration and pH of effluents from core flooding were monitored to address EOR mechanisms and quantify the adsorption of each product in the sand pack.
High salt concentrations in wells cause the precipitation of salt in the well bore. Fresh water washes dissolve the salt. Water washing has a high cost due to lost production and frequency of washes. This paper discusses the advantages of applying salt inhibition chemistry to extend the production period and increase the well economics.
Chemical technology has been introduced as an alternative to dissolution with water. Specialty polymers that exhibit super-saturation and crystal modification properties can be introduced into the well bore, preferably by a formation squeeze. Whereas the fresh water clean outs for these wells lasted no more than a week the salt squeezes lasted in excess of fifteen weeks.
The operator washed the wells for salt with fresh water on a weekly basis. Often the production had dropped prior to the scheduled wash out. After approving the chemical squeeze the wells were cleaned following a prescribed protocol. The wells were squeezed with chemical commensurate with the water production of the well. The well production was monitored and recorded. In all cases production exceeded the time seen with a water wash. At least one well has produced at the desired high rate for over one hundred days.
This paper details the design, application and results of a multiple well treatment of salt inhibitor in a North Africa field. The application of this chemical technology advances industry technology in two manners. First, it eliminates the need and cost of frequent water washes. Secondly, it increases production by extending the period of desired production and reducing the frequent production decreases brought about by the sale deposition. Furthermore the success of this technology is leading the research to develop longer lasting molecules that can be placed in both fracturing and squeeze applications.
Over the past two decades, viscoelastic surfactant (VES) fluids used for gravel packing, frac-packing and conventional hydraulic fracturing have primarily relied on external or reservoir conditions to break the fluid's viscosity. Unlike polymeric fluids, no internal breakers have been used. Relying on external conditions to break VES fluid has been a point of contention and questionable, especially for dry gas applications.
This paper describes how new internal breaker technology has been developed that allows VES fluids to be broken into easily producible fluids, without the need for contacting reservoir hydrocarbons. The reservoir pressure required to produce VES fluid is no longer compromised: very little pressure or time is required when an internal breaker is present. Mechanisms for internally breaking VES viscosity are discussed. New internal breakers have been found to work over a wide fluid temperature and mix water salinity range, and have compatible with newly developed VES stabilizers and fluid loss control agents. Presented are laboratory results that compare VES fluids with and without an internal breaker. Rheological data is presented that show the performance of internal breakers in degrading VES fluid viscosity, in particular at low fluid shear rates. Core clean-up tests were performed at 150°F, using 3% KCl brine and nitrogen gas as the displacement (clean-up) fluid. The results show that use of an internal breaker significantly improves VES fluid clean-up. This paper also presents VES system compatibility and proppant conductivity results.
Drag reduction is a well known phenomenon. Possible mechanism deduced from heat transfer has been suggested earlier for non isothermal Newtonian fluid treated with polymer drag reducer. Several works have shown the susceptibility of the long chain polymer to shear degradation, hence reduction in its performance. Most of the works were performed in isothermal conditions. Moreover, it mostly covers water soluble polymers. There is an increasing need to address the shear degradation phenomenon for oil soluble polymer, where its performance is related to increase transportation capacity of pipeline as well as energy savings.
In this work the degradation of oil drag reducing polymer in a non-isothermal environment in which rheological change of oil (the carrier fluid in this work) occurs as the fluid is transformed from Newtonian to non-Newtonian is addressed. In another words, the paper addresses the temperature effect on the degradation of the oil soluble drag reducer polymer in a wide range of temperatures. The non-Newtonian fluid behaviour here is defined as the temperature below which paraffin deposits in presence of drag reducer polymer. The validity of equations for estimating Colburn factor is also addressed.
The fragile damage of cement sheath, induced by perforation and stimulation treatments, can bring formation fluid to cross flow and increase the damage rate of casing. The fragile damage can be avoided by using fiber-toughening agents. With ordinary fiber-toughening agents, the toughness of set cement is increased, but the Young's modulus is barely decreased and the elasticity is hardly improved. In fact, as the Young's modulus is decreased, the spread rate of stress wave produced by perforation in cement sheath is decreased. Because the spread rate of stress wave in cement sheath is decreased, the fragile damage of cement sheath is decreased. Therefore, a novel fiber-toughening agent, named PJ, was developed. It consisted of carboxylated nitrile rubber particles named J at 5.5% by weight of cement (BWOC) and a polypropylene fiber named P (0.2%BWOC). Its effects on the mechanical properties, the engineering properties and the microstructure of set cement and the compatibility with other admixtures were evaluated. Experimental results showed that both the elasticity and the toughness of set cement with PJ were increased markedly.The comprehensive engineering properties of the slurry with PJ (5.7% BWOC), drag reducer USZ (0.2% BWOC), filtrate loss additive F17B (1.2% BWOC) and expanding agent F17A (3% BWOC) met technical requirements of cementing operation. Good quality cement sheath with PJ was observed by the CBL /VDT logs (cement bond log/variable density log).
Mixing of injected seawater with formation brines may cause scale precipitation at production wells and surface facilities, but does not generally cause significant damage within the formation itself. Indeed, mixing within the reservoir may be beneficial, if the concentration of scaling ions is reduced due to ion stripping as the brine mixture approaches the production well1. One potential exception to this is when the availability of produced water for re-injection (PWRI) is insufficient to maintain voidage replacement, and must be supplemented with seawater. Under such circumstances, seawater and formation brine may be completely mixed before injection. This will not lead to a loss of injectivity if scale inhibitor chemicals are appropriately applied to the injected brine stream2.
However, scale inhibitors are retained by the reservoir rock as they are displaced away from the wellbore, resulting in the inhibitor front propagating more slowly than the saturation front - usually referred to as chemical retardation. As brine is displaced away from the injection well, the upshot is a growing zone of mixed brine with chemical concentration below the threshold required to inhibit the scaling reaction.
The question this paper considers that has not been addressed before is whether the ratio of produced water to seawater that is injected, the possibility of treating the injection brine mix with inhibitor, and field specific details such as the location of the injection wells relative to production wells and the aquifer can impact how this zone of unprotected mixed brine is displaced and reacts deep within the reservoir, away from both injection and production wells. If the scaling reaction can be limited to a region deep within the reservoir where the volume of rock is large compared with the potential mass of scale that may deposit, then the sulphate ions associated with seawater may be stripped from the brine mixture before the water is produced. Thus, by considered yet straightforward management of the PWRI scheme, it may be possible to protect the production wells from scale damage in a way that is not possible under conventional seawater injection. This hypothesis is tested using conventional reservoir simulators and reaction-transport modelling. Various conditions are considered, including brine reactions, extent of brine displacement through the oil leg or aquifer, as well as management of the PWRI wells. Prediction of scale damage potential at production wells is made for an example field system.
Viscoelastic surfactant (VES) fluids have been widely used as gravel-packing, frac-packing and fracturing fluids for more than a decade because the fluids exhibit excellent rheological properties and maintain low formation damage characteristics compared with crosslinked-polymer fluids. Due to its non-wall-building property, VES fluid has much higher fluid leak-off into the reservoir matrix than wall-building polymer fluid. For frac-packing this has limited VES use to reservoirs with permeability of less than 1000 md and, in most cases, less than 250 md. Excessive fluid leak-off also significantly increases the cost of treatment.
This paper will introduce new technology for controlling the fluid loss of VES fluids to about 300ºF. New fluid loss control agents have been developed that, through chemisorption and surface charge attraction, associate with VES micelles to produce a pseudo-filtercake of viscous VES fluid that significantly reduces the rate of fluid loss. Use of this technology will reduce the VES fluid volume required for a given treatment by up to two-thirds and extends the permeability range of VES fluids to about 2000 md. The fluid loss control agents are slowly water-soluble particles that are used at relatively low concentrations. The particles will be dissolved and/or flowed back with the producing fluid. The rate of the pseudo-filtercake clean-up is enhanced by use of internal VES breakers. The results of rheology, leak-off, and core flow tests will be presented for the VES fluid systems at temperatures 150°F and 250°F.
Farrera Romo, Gustavo Alonso (Pemex-Exploracion Y Produccion) | Hernandez Leyva, Hector (Pemex-Exploracion Y Produccion) | Bonifacio Aguilar, Raul (Halliburton Energy Services) | Caballero, Carlos (Halliburton de Mexico, S.A. de C.V.) | Eoff, Larry S. (Halliburton Energy Services Group) | Dalrymple, Eldon Dwyann (Halliburton Energy Services Group)
This paper presents the results of a successful application of a new-generation polymeric relative permeability modifier (RPM) that enables treatments to reduce water cut without workover equipment. The new RPM can be bullheaded into open intervals without the need for isolating water zones from hydrocarbon zones. This treatment was applied to several wells in the Pemex southern region. As a result of the treatment, the productive life of the wells has been extended, with a gradual decrease in water cut. These results indicate high potential profitability values for mature fields with high water cut requiring a simple, low-cost treatment without the need for workover equipment or shut-in times. The new treatment can increase the hydrocarbon recovery percentage in sands that in all probability otherwise would be destined for abandonment.
This paper describes the treatment methodology, which begins with problem identification and an understanding of the origin of the water breakthrough. Next, the paper describes the new technology, which uses hydrophobically modified water-soluble polymers and explains how applying such polymers can control water selectively. In addition, the detailed execution of the treatment is described, followed by the very positive production results of the treatment. The results of this low-investment, high-profit technology are very promising for other wells under similar conditions in which workovers with conventional technologies would be cost prohibitive.
The effective placement of chemical squeeze treatments in heterogeneous wells and long reach horizontal wells has proved a significant challenge, with various factors including heterogeneity, crossflow and pressure gradients between otherwise non-communicating zones within the well, all contributing to an uneven placement of the scale squeeze treatment into the reservoir. Work recently presented by the authors has however illustrated the potential benefits of using modified injection fluids (in particular, lightly viscosified shear-thinning fluids) to aid uniform scale inhibitor placement in such wells to effect more even placement. This paper describes the various options available for achieving self diversion and describes the potential drawbacks associated with the viscous placement fluids commonly used for acid simulation techniques. In addition, the paper presents the results of laboratory and computer simulation investigations into the application of such fluids using novel laboratory core flood techniques, and discusses the implications of these results for field treatments. The work describes the importance of obtaining accurate in situ viscosity properties under realistic flow conditions to provide appropriate input data for computer simultaion studies and describes novel laboratory test methods for the determination of such properties. This work also illustrates the effectiveness of the use of dual core testing to provide experimental data to validate model algorithms prior to field applications.