The associative properties of hydrophobically modified water-soluble polymers (HMWSPs) are attractive for improved oil recovery (IOR) because of both their enhanced thickening capability, compared with classical water-soluble polymers (for mobility-control applications), and their permeability-reduction, or plugging, ability (for well-treatment applications). In previous works, we have studied the injectivity of HMWSP made of sulfonated polyacrylamide backbones and alkyl side chains in the dilute regime and have shown, in particular, that it was largely governed by adsorption. In this paper, we report new experimental data on the injectivity of the same class of HMWSP solutions in the semidilute regime.
From membrane filtration tests at imposed flow rate, we have first observed the formation of a filter cake made of HMWSP physical gel, which remained largely permeable to polymers. Our observations are compatible with the creation of channels within the gel. This leads to a gel-filtration process, entailing modifications of the solution's viscosimetric properties, which can be explained by a rearrangement of the intra- and interchain hydrophobic bonds in the solution. The second part of our work consisted of injectivity tests in model granular packs. We have performed comparative experiments in porous media with variable permeabilities, but at the same shear rate in the pore throats. Results show that, above a critical permeability kkC, or a critical pore-throat radius rpkC, HMWSP injection led to stable resistance factors, with values close to the solution?s viscosity, and that, at less than kkC or rpkC, the very high resistance factors observed suggest that flow-induced gelation of the HMWSP takes place. Furthermore, resistance factors measured over the core internal sections are compatible with an in-depth formation of the gel. These insights could be of use for designing HMWSP better suited to mobility-control operations and for tuning HMWSP injection conditions for profile/conformance-control operations.
Al-maamari, Rashid Salim (Sultan Qaboos University) | Sueyoshi, Mark (Institute of Technology, Shimizu Corporation) | Tasaki, Masaharu (Institute of Technology, Shimizu Corporation) | Okamura, Kazuo (Institute of Technology, Shimizu Corporation) | Al Lawati, Yasmeen Mohammed (Petroleum Development Oman) | Nabulsi, Randa Zaki (Petroleum Development Oman) | Battashi, Mundhir (Petroleum Development Oman)
As an oil field matures, it produces larger quantities of produced water. Appropriate treatment levels and technologies depend on a number of factors such as disposal methods or reutilization aims, environmental impacts, and economics.
In this study, a pilot plant of capacity 50 m3•day-1 was utilized to conduct flotation, filtration, and adsorption trials for produced water treatment at a crude oil gathering facility. The plant's flexible design allows for the testing of different combinations of these processes based on the requirements of the water to be treated. The subject water during this study was a complex and changing mixture of brine and oil from different oilfields.
Induced gas flotation trials were conducted, with different coagulant (poly-aluminum chloride or PAC) addition rates from 0-820 mg•L-1. Inlet oil-in-water (OIW) concentrations were quite varied during the trials, ranging from 39-279 mg•L-1 (fluorescence analysis method) and 12-340 mg•L-1 (infrared analysis method). Turbidity also varied, ranging from 85-279 FTU. Through flocculation/coagulation and flotation, dispersed oils were removed from the water. PAC addition ranging from 60-185 mg•L-1 resulted in reduction of dispersed oil concentration to below 50 mg•L-1 in treated water. PAC addition ranging from 101-200 mg•L-1 resulted in reduction of dispersed oil concentration below 15 mg•L-1 in treated water. Turbidity was also reduced through flotation, trial average reductions ranging from 57-78%. Filtration further reduced turbidity at rates above 80% through the removal of any suspended solids remaining from flotation. Activated carbon adsorption reduced OIW concentrations of flotation/filtration treated water to 5 mg•L-1 through the removal of dissolved oil remaining in the water. Results confirmed that such adsorption treatment would be more practical for water with lower COD concentration, due to high COD concentrations in water drastically reducing the lifetime of activated carbon.
Charnvit, Kerati (M-I Swaco) | Kongto, Abhijart (M-I Swaco) | Huadi, Fransiskus (M-I Swaco) | Sharma, Sunil (M-I Swaco) | Simon, Gerard A. (Chevron Corp.) | Estes, Brent Lamar (Chevron Corp.) | Trotter, Robert Neil (Chevron ETC)
Typical wells in the Gulf of Thailand are drilled using a slim-hole design that requires 6?-in. hole for their reservoir interval. The slim and highly deviated well geometry, potential of high acid gas contamination, and high-temperature environment requires a well-engineered non-aqueous drilling fluid (NAF) to meet the overall well objectives. These conditions always place severe limitations on the drilling fluids design and often lead to failures in openhole wireline logging operations, which is the most important well objective.
The key fluid properties to ensure the success of wireline logging operations under this high temperature are high-temperature,high-pressure (HTHP) filtration control, filtercake quality, and thermal stability of the drilling fluid under
extreme static condition. Selected emulsifier and HTHP filtration control agents work synergistically in providing excellent hole condition which allows the hole to be fully logged and evaluated. Clear benchmarks were set and monitored in all the field applications: (1) Successful wireline logging operation; (2) Variation of mud weight after static condition; (3) Variation of mud weight compared to formation tester data point.
This paper details the design, development, and field applications of an ultra-high-temperature NAF used for drilling deep and hot wells in the Gulf of Thailand. In addition, the extensive laboratory work required to optimize the formulation for extreme high temperatures, the lessons learned, and the critical engineering guidelines for running a NAF in such harsh conditions will be described.
When bottomhole static temperature (BHST) exceeds 400°F, good engineering practices and extra attention are required during hole drilling operations for NAF to perform within expectations, especially when coupled with acid gas contamination and high solids content, specifically low-gravity solids (LGS). Emulsifiers can thermally degrade leading to gelation problems as well as contributing to increased high-temperature, high-pressure (HTHP) fluid loss. HTHP filtration control and filtercake quality can also deteriorate due to the degradation of HTHP filtration control agents. Therefore, the selection of appropriate additives and their concentration is critical to ensure the drilling fluid will withstand prolonged exposure to ultra-hightemperature openhole wireline logging operation (>48 hours).
Historically, conventional NAF systems have had a good performance track record in the Gulf of Thailand providing the necessary fluid and wellbore stability to achieve successful wireline logging operations. However, when BHST exceeds 400°F, problems have been reported during wireline logging operation, including difficulties in moving wireline logging tools up/down to reach the target depth or even getting stuck which led to non-productive time (NPT) and/or loss of tools in several wells. As a result, a more robust NAF, which could help minimize the NPT, was requested by the operator as numerous wells being planned would have BHST considerably above 400°F. The first approach to solve this issue was to review and modify field engineering practices in an attempt to extend the stability of the conventional NAF formulation; however, it was concluded from this initial study that a novel NAF was required for this ultra-high temperature condition.
Bolychev, E. A. (Rospan International) | Konstantinova, Natalia Vladimirovna (TNK-BP Management) | Muslimov, E. Ya. (TNK-BP Management) | Shayhutdinov, I. K. (TNK-BP Management) | Makarov, E. M. (TNK-BP Management)
The Russkoe gas and oil field was discovered in 1968. No attempts to begin its commercial operation in the former USSR were and have been successful till the present time. The issue of economically attractive development of the Russkoe field is very urgent for TNK-BP since the field is a strategic oil asset to replenish company reserves. The field is located in the Arctic zone, in the north of the Tyumen Oblast, Russian Federation. Russkoe reserves are hard to recover, and the expected oil recovery factor is 14-15%. The main pay zone, PK 1-7, consists of unconsolidated poorly cemented sandstones with a high pelite fraction content. The reservoir is saturated with highly viscous oil (19 API), and low reservoir temperature (23°?) is predominant. Horizontal well profiles (over 500 m) are currently considered to be the most feasible ones from the economic point of view. The field is located in a hard-to-reach region with difficult logistics. With these conditions in view, correct selection of completion systems for sand control or containment is critical for assuring profitable operation of this asset from the point of view of maintaining well productivity, artificial lift and surface equipment loading. This article describes the TNK-BP process and experience in selecting the lower completion systems intended to suppress reservoir sand production in the Russkoe field. Different lower completion systems were tested during the pilot operations in 2006 - 2010. To reduce uncertainty, a set of laboratory tests of completion systems produced by a number of Russian and foreign manufacturers were conducted using the Russkoe field well fluid and core samples. The experience of leading servicing companies as well as experience of developing similar fields in the world was also taken into account. The article discusses in detail the approach chosen, decisions taken, current results, and lessons learned.
An invaded zone forms when mud filters into a permeable formation during and after drilling. The mud filtration process is affected by mudcake buildup, well pressure overbalance, and mud properties. Mud invasion changes the spatial distribution of resistivity in the near-wellbore zone - data that could be estimated from inverting the results of resistivity logging data. Invasion simulation can be used to predict invasion depth, mudcake thickness, distribution of resistivity, and formation permeability.
This paper presents an invasion simulation algorithm developed from the Buckley-Leverett filtration model, which takes into account mudcake buildup. This algorithm is used to calculate the near-wellbore water saturation and salinity distributions. These characteristics are used for resistivity profile calculations by an Archie-type equation.
The main goal of this paper is to propose a method of mudcake data interpretation based on a mud filtrate invasion simulation algorithm. This method yields the mud filtrate volume, water saturation and salinity distribution. To verify the results, the values obtained were compared with the results of the induction log and laterolog inversion from several vertical wells. This approach increases the significance of the mudcake thickness data and illustrates the practicality of the joint interpretation of resistivity log data and the mudcake thickness (the former being highly sensitive to resistivity changes within the invaded zone).
In addition, this paper suggests a technique for evaluating formation permeability from mudcake thickness. This technique is applicable if the mudcake was not damaged during the drilling operation. The algorithm was tested and verified by the log and core data obtained at several vertical wells.
Kadet, Valery (Gubkin Russian State University of Oil and Gas) | Dmitriev, N. M. (Gubkin Russian State University of Oil and Gas) | Kuzmichev, A. N. (Gubkin Russian State University of Oil and Gas) | Tsybulskiy, S. P. (Gubkin Russian State University of Oil and Gas)
In recent years the fields with hard recoverable reserves of hydrocarbons are increasingly involved in the process of developing. Problems of hydrocarbons extraction are often associated with a complex structure of the reservoir which tending to exhibit anisotropy of the filtration properties. Therefore, while researching filtration flows consideration of the anisotropy has both practical and scientific interest. The main source of information about the structure formation and properties is a core material extracted from drilling wells.
In this paper a laboratory technique for determining the absolute permeability tensor in the core has been presented for different types of anisotropy. Technique for determining the lateral anisotropy and further permeability tensors from core is based on propagation of ultrasonic waves velocities being measured through the lateral surface of the core. While using this method at first the existence of the lateral anisotropy is established, and then the type of anisotropy in core is determined. Further according to type of anisotropy established the required number of cores for the hydrodynamic and possibly other researches is sawed from the sample rock.
In this paper the results for determination of the absolute permeability tensor and capillary pressure obtained with the technique proposed have been presented. These results confirm the tensor nature of the absolute permeability, effective diameter and luminal. Determination of phase permeability tensors, limiting gradients and non-linear filtration laws are also possibly within the frames of technique described.
Allowance of the anisotropy of reservoir properties gives more adequate picture of the distribution filtration flow in the reservoir. It allows you to optimize the direction of horizontal drilling, to rationalize development system (placement of wells) and eventually to increase oil recovery.
While drilling through pressure-depleted formations, drilling-induced fracturing often occurs. Fracturing results when the drilling fluid overburden pressure exceeds the fracture pressure of the rock, initiating fractures that may further propagate as overburden pressure is increased. The growth in the aperture of these fractures results in lost circulation incidents. The consequences pose a major economic and safety risk when drilling. Numerous papers have been published on the concept of maximizing the fracture width to preserve the resulting hoop stress around the wellbore and effectively decrease drilling fluid losses. Using these techniques to control lost circulation with bridging materials can be extremely difficult when drilling with non-aqueous, oil-based fluid. The reduced permeability of an oil-wet filter cake prevents carrier fluid leak-off and necessary solids concentration. The resulting lower-strength plug in the fracture prevents effective support. The fracture then closes, preventing maximum hoop compression of the wellbore.
Altering the oil-wet solids in the fracture to water-wet conditions increases the ability for pressure to leak-off in fractures when placing bridging agents. This capability is paramount to improving bridging agent placement and increasing the effective strength of the wellbore. A lost circulation pill system has been developed that alters the wettability of the fracture from oil-wet to water-wet. This pill system penetrates and water-wets oil-containing fractures and enables fast pressure leak-off and fracture support, effectively increasing pressure required for fracture growth. Laboratory and chemical methods are presented that show the system is effective over a broad range of temperatures and differential pressures.
From the point-of-view of a solutions provider the wastewater treatment should be straight forward: once given the composition of the feed and the required composition of the effluent, today's technology allows formulating a set of solutions which best meets the operator's and the regulatory criteria.
The problem with wastewater in the unconventional gas exploration and production operations is that there are large volumes to be handled and treated. To add complexity, composition varies for the same well in time and varies even more from area to area of development. Also, the requirements for the cleaned fluid vary from operator to operator and by region. Moreover, management of the water based fluids is under the pressure and scrutiny of various regulating agencies: public, privately, or governmentally run. All these constraints make the vetting of treatment methods and technologies to be a very dynamic and intensive process.
Our findings during the process of formulating a set of solutions shows that a deep understanding of the problems, combined with close collaboration with the operators and regulators along with solid basic engineering practices are the key to success.
Our experience would benefit the new developments in other unconventional exploration and production area in Asia by showing the steps that were undertaken to insure solutions are up to the highest standards.
The process of finding and testing various waste water treatment technologies to formulate a flexible comprehensive set of methods will be described. Laboratory results of various samples of water will be presented as well as the challenges that were overcome for obtaining consistent, reliable analytical data. The oilfield tough requirement presented to new technologies translates as: rugged, flexible, mobile, and low cost.
Water is a precious commodity that is needed in all human activity and for life in general. The Oil & Gas industry uses and generates large quantities of this commodity (Produced Water Volume Report). On average, for every barrel of oil produced there are eight barrels of associated wastewater. Increasing the efficiency of water usage and improving its management is both a high priority among E&P companies and a subject of intense scrutiny for the communities in which they operate.
Water Necessity in Developing Areas
The availability of suitable water for hydraulic fracturing and the means for environmentally responsible water recycling and disposal are critical for sustainable unconventional development. Produced water that comes to the surface during oil and gas recovery presents a challenge for Marcellus drillers because of the scarcity of injection wells in the Appalachian region. Other areas, like West Texas (Permian Basin or Eagle Ford Shale) do not lack for disposal options but do suffer due to the arid climate and depletion of ground water resources.
A new solution for determining the amount of mud loss during drilling operation in a fractured reservoir having a regular two- or three-dimensional radial fractured network with the novel inclusion of a convective transport of filtrate in the matrix is presented. Convective-dispersive filtrate transport along the network is modeled in which drilling mud can be filtered in existing matrix. The filter cake effect at the fracture-matrix interface in the network is simulated by means of an empirically decaying filter rate equation. The numerical solution is used in this study. The consistency of numerical solution is checked and the best situation is considered. The sensitivity analysis on all parameters in the model has been done and the effect of each parameters such as wellbore loss rate, reservoir thickness, fracture opening size, matrix porosity, matrix permeability and dispersivity, on the amount of filtration are inversitaged. By means of developed model, the amount of mud filtration can be plotted against position in different fractured network configurations for different wellbore conditions, reservoir properties and reservoir geometries at different times. The position in the fracture network at which the curve of concentration reaches zero can be considered to represent skin radius caused by drilling operation. This radius can be used for determining the acid volume which is needed for acidizing operation and accurate well-log interpretation.
With the growing interest in low-permeability gas plays, foam fracturing fluids are now well established as a viable alternative to traditional fracturing fluids. Present practices in energized fracturing treatments remain, nonetheless, rudimentary in comparison to other fracturing-fluid technologies because of our limited understanding of multiphase fluid-loss and phase behavior occurring in these complex fluids. This paper assesses the fluid-loss benefits introduced by energizing the fracturing fluid.
A new laboratory apparatus has been specifically designed and built for measuring the leakoff rates for both gas and liquid phases under dynamic fluid-loss conditions. This paper provides experimental leakoff results for linear guar gels and for N2/guar foam-based fracturing fluids under a wide range of fracturing conditions. In particular, the effects of the rock permeability, the foam quality, and the pressure drop are investigated. Analysis of dynamic leakoff data provides an understanding of the complex mechanisms of viscous invasion and filter-cake formation occurring at the pore scale.
This study presents data supporting the superior fluid-loss behavior of foams, which exhibit minor liquid invasion and limited damage. It also shows direct measurements of the ability of the gas component to leakoff into the invaded zone, thereby increasing the gas saturation around the fracture and enhancing the gas productivity during flowback. Our conclusions not only confirm but add to the findings of McGowen and Vitthal (1996a, b) for linear gels and the findings of Harris (1985) for nitrogen foams.