Most subterranean rocks contain natural fractures. Fluid loss severity in reservoir sections increases with increasing width of the fractures. Apart from the economics of lost drilling fluids, preventing formation damage in the reservoir section is of paramount importance. The application of non-damaging lost circulation material (LCM) has been the traditional solution to control losses in these scenarios. The performance of such LCM mixtures is usually determined with a Particle Plugging Apparatus (PPA), using aloxide discs for evaluating fluid loss. These discs more closely emulate a permeable sandstone, with varying pore throat sizes, than a natural fracture. The formation of an impermeable plug which can sustain higher wellbore pressure is desirable when treating a fracture, but in a producing formation the plug is removed by the produced fluid or by a remedial treatment.
To better emulate both natural and induced fracture geometry, slotted discs of constant width were introduced; however these slots represent only the face of the fracture where LCM forms the bridge. The bridge may become eroded due to shear stress of the drilling fluid, leading to reestablishment of lost circulation. To remove these limitations, a new tapered slot was designed in which the fracture opening size varies from its face to its endpoint over a certain length, more closely resembling a fracture.
Different combinations of ground marble (acid-soluble) were tested using the tapered slot. Many times it was observed that although the slot was completely filled with LCM, there was continued fluid loss. Considering this, components of high fluid loss pills for such application need to be redesigned. Cellulosic and polylactide (PLA) fibres (5-15% V/V of LCM) were used in combination with particulates resulting in significant improvement in fluid loss control. Other mechanical properties of particulate material were also studied and their importance in controlling lost circulation control established. This paper reviews the application of this testing equipment and methodology with non-damaging fibers for lost circulation control to minimize formation damage in reservoir sections.
The up-to-date requirements suggests that the design of a carbonate rock matrix treatment should be calculated based on the models of key physical and chemical processes by means of a specialized software. In wells with a heterogeneous vertical permeability, the problem of acid distribution across the reservoir zone cannot be addressed correctly without using a numerical simulation. Moreover, numerical simulators help find solutions for the feasibility assessment of acidizing operations by simulating scenarios with different injection volumes and rates, agent staging, and initial economic conditions. The paper describes the design optimization problem in carbonate reservoir acidizing using viscous diverter fluids. The mathematical model of acidizing process was created in the well scale. This model accounts for the flow of insoluble clay and silica particles in a porous medium and their deposition at the pore throats. Core laboratory tests showed that the treatment pressure is affected by a suffosion process. Numerical simulation allowed calculating acid concentration in the reservoir at different injection stages, as well as pressure; porosity and permeability dynamics; the treating agent distribution and flow in the layered heterogeneous reservoir; the skin factors in target zones; and the effect of the diverter fluids. These calculations help to determine the optimal parameters, which drive the acidizing efficiency. The incremental oil production rate and variance of post-treatment productivity for the heterogeneous reservoir are used as the target parameters for treatment optimization. The developed simulator of the heterogeneous laminated reservoir acidizing was applied for evaluating the real field operations, and the results were found consistent with actual historical data.
Sandface completions such as standalone screen completions have suffered from erosion problems for many years. A significant amount of catastrophic screen failures are considered to be the result of high velocities of solid's laden hydrocarbons creating hot spot areas in the interface between the sandface and the completion. Previous researchers investigated the change in permeability of failed rock into annular gaps generated in non-compliant sand control completions and identified that packed material in this space can result in severe distortion to flow patterns and restrictions. This paper describes the development and testing process for a new methodology that allows identification of the erosion prone areas in the annular space between the sandface and the screen. Detailed investigation, supported by laboratory testing, reviewed oil and gas well conditions at the startup, during a cleanout and after hydrocarbon's production have been stabilised. Radial flow, mode of sand collapse, compaction, voidage, sand quality and formation petro-physical properties were tested and analysed using high and low pressure flow cells in order to quantify the changes in pressure drops through the collapsed rock material. The results indicated that flow rate, viscosity, voidage, grain shape and volume are the main contributors to the variations in pressure drops across failed sand material in the annular space. On the basis of these tests, a continuous (foot-by-foot) analytical model was developed that allows identification of the specific location and variation in pressure drops across the annular packed material for oil and gas wells. The model is composed of five (5) main elements; a reservoir inflow module, a fluid drag module, a grain size and volume module, a pressure drop module and an erosion prediction module. The model was tested using data from a North Sea field and the results, algorithms and field samples will be discussed and presented in detail.
Al-Anazi, M. (Saudi Aramco) | Al-Mutairi, Saleh Haif (Saudi Aramco) | Alkhaldi, Mohammed (Saudi Aramco) | Al-zahrani, Ali Abdulrahman (Saudi Aramco) | Al-Yami, Ibrahim Saleh (Schlumberger) | Gurmen, Mehmet Nihat
Water production can reduce or block oil and gas production rates. In addition, the lifting, handling, and disposal of produced water negatively impact the hydrocarbon production economics. Among several techniques for water control, crosslinked polymer systems are the most effective for certain water shut-off projects. The objective of this paper is to assess the effectiveness of crosslinked polymer system for water control applications in carbonate formations and present its optimal formulation.
This paper presents a detailed lab testing of a cross-linked polymer system. The system includes a gelling agent, primary and secondary crosslinkers and an acidic activator. The evaluation covered extreme concentrations of all components, temperatures up to 212°F, differential pressures up to 1,500 psi, actual field water salinity, wide range of permeability, and extended testing time up to three months. Core-flood experiments along with Computerized Tomography Scanning and Environmental Scanning Electron Microscopy were used to assess the sweep efficiency and the strength of the gel inside the core plugs. Losses of active ingredients from effluent samples were measured using Thermal Gravimetric Analyzer. Results of carbonate core plugs were compared with that of Berea sandstone. Strength of the gel at different cross-linker and polymer concentrations was monitored using sealed glass ampoules. Gelation times were measured using bottle tests and rotational viscometers.
Extreme vertices design was used to optimize the experimental work and mixture triangle was used to represent the final results. An optimal gelling system with controlled gelation time and maximum performance was attained for the targeted formation at 212°F. It was found that the gelation time was affected by the three main components of the gelling system. The acetic acid-based activator was found to have the highest effect on the gelation time. However, this activator was not effective when the gelling system was tested in carbonate core plugs. A major effort of this work was to develop alternative strategies for the ineffectiveness of acidic activator in carbonaceous formations.
Typical water flooding project involves injecting deoxygenated and filtered seawater at strategic points along the periphery of the oil field, displacing the oil and pushing it toward oil producing wells in the center of the field. The technique increases crude oil recovery substantially and allows for greater returns from the field. The practice of water flooding is usually done at the early development of the field to maintain reservoir pressure, and thus oil production.
However, water breakthrough via the high permeability zones of the reservoir can cause high water cuts and result in obscure operational problems in both injection and producing wells. For water injection wells, most of the injected water will flow through the high permeability streaks leaving large amounts of oil in place. In producing wells, the high permeability zones will result in earlier water breakthrough and high water cuts with unbalanced drainage from the low permeability zones. Water production is a longstanding problem that is becoming critical as more and more oil is being displaced by waterflooding. Lifting, processing, treating, and reinjection and/or disposal of the produced water add to the overall cost of oil production. An approach to determining the economical value of a water shutoff treatment is given by Botermans et al. (2001). Typical water shutoff treatment reduces water production by 75 to 90 % and can increase oil production by 1000 times (Portwood 1999).
Reinicke, Andreas (Helmholtz Centre Potsdam GFZ) | Bloecher, Guido (Helmholtz Centre Potsdam GFZ) | Zimmermann, Gunter (GFZ German Research Centre for Geoscience) | Huenges, Ernst (Helmholtz Centre Potsdam GFZ) | Dresen, Georg (TerraTek a Schlumberger Company) | Stanchits, Sergei (Shell E&P Europe) | Legarth, Bjoern Alexander (Shell E&P) | Makurat, Axel
In context of this work, a new formation damage mechanism is proposed: the mechanically induced fracture face skin (FFS). This new mechanism results from mechanical interactions between the proppants and the reservoir rock, due to the increasing stress on the rock-proppant system during production. Proppant embedment into the fracture face and proppant crushing leads to fines production and may impair the fracture performance. In order to achieve sustainable, long-term productivity from a reservoir, it is indispensable to understand the hydraulic and mechanical interactions in rock-proppant systems. Permeability measurements on sandstones with propped fractures under stress using different flow cells were performed, allowing localizing and quantifying the mechanical damage at the fracture face. The laboratory experiments identified a permeability reduction at the fracture face up to 90 %. The mechanical damage at the rock-proppant interface begins immediately with loading the rock-proppant system and for fracture closure stresses below 35 MPa; the damage is localized at the fracture face. Microstructure analysis identified quartz grain crushing, fines production and pore space blocking at the fracture face causing the observed mechanically induced FFS. At higher stresses, damage and embedment of the ceramic proppants further reduces the fracture permeability. Numerical modeling of the rock-proppant system identified highly inhomogeneous stress distributions in the granular system of grains and proppants. High tensile stress concentrations beneath the area of contact between quartz grains and proppants are observed even at small differential stress applied to the rock-proppant system. These high stress concentrations are responsible for the early onset of damage at the fracture face. Therefore, even low differential stresses, which are expected under in-situ conditions, may affect the productivity of a hydraulically fractured well.
Design of an appropriate fracture geometry as well as placement of a sufficient proppant pack of the right proppant type is a key parameter to maintain long-term productivity. Proppant selection must consider appropriate hydraulic conductivity at in-situ stress conditions. Hydraulic conductivity is influenced by mechanical stress on proppant pack and rock-proppant interface, leading to proppant crushing and embedment as well as to a reduction of fracture width and fines production (Anderson et al., 1989). The production analysis often indicates a post-fracture well productivity that is significantly lower than expected from fracture characteristics simulations (Cramer, 2005, Romero et al., 2003). Hence, there is still a need for better understanding and investigating the complex mechanisms influencing the permeability alteration of rock-proppant systems.
Treatment failure can be commonly attributed to fracture damage processes, such as: poor clean-up after the treatment, alterations due to infiltration processes and precipitation, and mechanical damages like proppant pack failure (Economides, and Nolte, 2000). A wide range of laboratory, field, and theoretical studies cover the aspects of fracture damage mechanisms (Fredd et al., 2000; Wen et al., 2006; Behr et al., 2002; Nasr-El-Din, 2003; Moghadasi et al., 2002; Lynn et al., 1998). Cinco-Ley & Samaniego V. (1977) introduced a potential fracture damage mechanism, the so-called fracture face skin (FFS), which describes a fluid flow impairment along the fracture face. The FFS is a function of fracture length, reduced permeability and extent of damaged zone adjacent to the fracture face (Fig. 1). A FFS can be caused by a variety of effects like fluid-loss damage (Cinco-Ley and Samamiego-V., 1981), filter cake build-up at the fracture face (Romero et al., 2003), water blockage (Holditch, 1979) as well as liquid condensate (Wang et al., 2000).
Although there exists the mentioned fracture face skin models, mechanical effects have yet not been taken into account. We expect that the mechanically induced fracture face skin results from interaction between proppants and rock grains.
Flow laboratories have been used for six decades to evaluate and optimize perforating systems for downhole environments. A key experimental variable is the pressure/flow boundary condition on the target core. Two standard configurations are axial flow, and radial flow. The implications of each configuration have been addressed somewhat in the literature in the context of steady flow with identical but prescribed tunnels. There has never been a careful comparison of the influence of boundary conditions on the actual tunnels.
In this paper we summarize the state of understanding regarding these two flow regimes by primarily focusing on the sensitivity of each to perforation damage and cleanup. In addition to addressing the differences under steady flow conditions, we also experimentally investigated the influence of target boundary conditions on the transient flow regime (i.e. during dynamic underbalance perforation cleanup). This was primarily an experimental investigation, supported by numerical simulations to determine baseline flow performance.
We find that radial flow provides the most meaningful measure of perforation damage (as indicated by post-shot steady flow). Indeed, radial flow is indispensable to parameterize skin and productivity models as they are currently formulated. Axial flow yields steady production flow which is most sensitive to penetration depth, and relatively insensitive to perforation damage.
Finally, and perhaps most significantly, the transient perforation cleanup process is different for radial vs. axial boundaries.
The intrinsic inflow characteristic of the tunnel is itself a function of the boundary conditions at shot time.
Proper selection of laboratory flow geometry is essential to yield meaningful measurements of perforation damage. In addition to this diagnostic purpose, target boundary conditions play a critical role in the removal of perforation damage, evolution of open tunnel length and diameter, and the resulting perforation flow efficiency.
Stavland, Arne (Intl Research Inst of Stavanger) | Jonsbraten, Hilde Carlsen (International Research Institute of Stavanger) | Vikane, Olav (International Research Institute of Stavanger) | Skrettingland, Kjetil (Statoil ASA) | Fischer, Herbert (Statoil ASA)
The waterflood sweep efficiency can be increased considerably by in-depth placement of a blocking agent. Sodium silicate is one of the few PLONOR chemicals applicable for water control. This paper highlights key results obtained from a research program on qualifying sodium silicate for offshore applications. The main findings of this work can be summarized as follows:
It is concluded that large volumes of sodium silicate can be injected into offshore oil reservoirs. Prior to the injection, a preflush is needed and the silicate is to be diluted in desalinated water. The permeability reduction can be obtained either during dynamic injection or shut-in period. The design parameters involve temperature, velocity and concentration gradients.
Sodium silicate was one of the first chemical systems applied for water control in oil reservoirs. It has been used occasionally, mainly for near wellbore treatments. Lakatos (1999) reports on the recent use of silicate in Hungarian oil fields. In the North Sea, sodium silicate has been applied for deeper treatments as in the field tests on Gullfaks (Lund and Kristensen (1993); and Rolfsvåg et al., 1996). The increasing water production from oil reservoirs and the fact that sodium silicate is a PLONOR chemical, has revitalized its potential use for fluid diversion.
Commercial sodium silicate, (SiO2)n:Na2O is delivered as a clear and stable fluid with a pH in the range of 11-13, depending on the SiO2:Na2O molar ratio, n. The alkalinity increases by decreasing the SiO2:Na2O molar ratio. The sodium silicate chemistry is rather complex and not fully understood. According to Iler (1979) there is equilibrium between different silicate species as shown in Stavland et al. (2011). At high pH the dimer silicate species dominate. It is well known that if the pH is reduced, the liquid silicate can react to gel through a polymerization of the silicate species. The gel reaction rate depends on pH and a minimum gelation time is found just below neutral pH. The controlling parameter for placement of a silicate gel is therefore the pH. The simplest method to adjust pH is to add acid to the injected silicate. Vinot et al. (1985) suggested the use of a diester for controlling the gelation kinetic. A good overview of possible gelation agents is given by Krumrine and Boyce (1985).
Fig. 1 suggests the sequential steps in polymerization from monomer to large particles and gel, Iler (1979). By injection of nano-size particles into a porous media, plugging and permeability reduction is obtained either by the formation of in-situ sol or the in-depth filtration of aggregates of size comparable with the pore size.
Lakatos, Istvan Janos (U. of Miskolc) | Lakatos-Szabo, Julianna (Research Institute of Appllied Earth Sciences, UM) | Kosztin, Bela (Petroleum Development of Oman) | Al-Sharji, Hamed Hamoud (Petroleum Development of Oman) | Ali, Ehtesham (Petroleum Development of Oman) | Al-Mujaini, Rahima Abdul Rauf (Petroleum Development of Oman) | Al-Alawi, Nasser (Petroleum Development of Oman)
In frame of the project, one injector and two oil producers operating in different reservoirs having extremely high permeability were treated using the silicate/polymer method. The well selection based on analysis of production history, reservoir structure, and tracer test and production characteristics. The water cut in producers was close to or well above 90%. The chemical system was individually tailored to each well. The gel-forming solutions were sequentially injected into the wells using bullhead technique. The producers operating with sucker rod pumping were treated through the producing tubing or the annulus. In the latter case, a new "virtual" reactor concept was elaborated to mix the solution on the fly. Evaluating the results, it can be concluded that the project was successful. The cumulative daily oil production increased by 68 m3/d; meanwhile the water production decreased by 285 m3/d. Thus, on yearly basis, the incremental oil production might be as high as ~25,000 m3/y with water production less than 105,000 m3/y. The project clearly proved that the silicate/polymer technology could meet the requirements of the unique reservoir conditions (extreme permeability, faulted structure, and low formation temperature). In addition, great advantage of the composite methods is that easily available, cheap, and environmental friendly chemicals were used.
Background of arising problems in Omani hydrocarbon production can be traced back to unfavorable types of reservoirs and properties of oils. Most of the oil bearing formations are faulted, highly heterogeneous with extremely high average permeability. In addition, the formation temperature is often low and the crude oils have high viscosity. Hence, the early water breakthrough and high water cut are often characterizing the production. Under these circumstances, the recovery factor is low, and poor well performance usually jeopardizes the optimal oil rate. Recognizing and understanding the production problems and forecasting their detrimental effects on deliverability, substantial efforts had been made recently to avoid production decline and mitigate the damaging processes. Among others, IOR/EOR methods addressing the whole reservoir space and well stimulation technologies were tested and routinely applied at different fields. In the frame of these endeavors, ambitious pilot tests were carried out to restrict water production in oil wells and simultaneously, to improve sweep efficiency in injectors through flow profile control. Earlier, diverse techniques including cementing, perforation relocation, polymer, and gel treatment were tested with partial success. The basic goal of the extensive field programs was to select the most efficient methods, which are flexible enough to meet the requirements at different oil fields. That strategy made the field tests of the silicate/polymer methods possible treating two producers and one injector. The company's idea also determined the target wells operating in different oil fields, hence under different, sometimes harsh formation conditions.
The successful application of sand-consolidation treatments is, for a major portion, dependent on correct fluid placement of the consolidation material. It is crucial to achieve a uniform placement of the material and, therefore, techniques are needed to overcome natural or artificially created heterogeneities. Diversion methods such as foams are being used frequently. However, fluid-placement verification of these treatments is rare.
This paper discusses the placement of a novel sand-consolidation material using a foam diverter and the verification of the placement by using distributed temperature sensing (DTS). Two case histories are analyzed in detail and used for illustration. In both case histories, foam was used to place the sand-consolidation material in multilayer reservoirs, and DTS was used to verify the placement in real-time. Qualitative and quantitative fluid placement information was derived in both cases.
From the DTS data, the parts of the formation that were treated could be identified in both case histories. In one case history, recently placed hydraulic fractures were identified and were treated. In the other case, reservoir-pressure variations were determined and identified to be the reason for preferential fluid placement and diversion over time. The lessons learned from the case histories will lead to further improvement of fluid placement.
Viscoelastic surfactant (VES) based self-diverting acid system has been developed for better matrix treatment of carbonate formations. Literature survey indicates that the highly viscous fluid acts as a temporary barrier to reduce further fluid loss into the wormholes and allows complete stimulation of all treating zones. After acid treatment, the viscous fluid is broken by either formation hydrocarbons or pre-flush fluids. However, recent lab work confirmed that a significant amount of surfactant was retained inside the core even when mutual solvent was used. The present study was conducted to better understand these acid systems and determine factors that impact their viscosity build-up and performance inside the carbonate formations.
A series of coreflood tests were conducted using carbonate cores at different injection rates. Propagation of the acid, surfactant, and reaction products inside the cores was examined in detail. Samples of the core effluent were collected and the concentrations of calcium, surfactant, and acid were measured. Permeability enhancement and location of any precipitation was detected using CT scanner to the core before and after the acid injection. Material balance was conducted to determine the amount of surfactant that retained in the core.
Experimental results show that VES acid was not able to buildup pressure drop across the core when it was injected inside 70 md permeability cores at various acid concentrations and injection rates when only one fourth pore volumes was injected. At high concentration of HCl, Calcium and the surfactant propagated with the same velocity. When low concentration of HCl was employed, Calcium propagated faster. Surfactant retention is higher when the acid concentration and the injection rate were lower. This number could be up to 100%. CT scan confirmed only small and short wormhole branches at the area near the inlet and one wormhole dominated till the end with a decreasing diameter. Reaction rate and extension of wormhole decreased when lower concentration HCl was used and injected at a higher rate.