A New Comprehensive Approach for Predicting Injectivity Decline during Waterflooding

Produced water re-injection (PWRI) is an important economic and environmental-friendly option to convert waste to value with waterflooding operations. However, it often causes rapid injectivity decline. In the present study, a coreflood test on a low permeable core sample is carried out to investigate the injectivity decline behavior. An analytical model for well impedance (normalized reciprocal of injectivity) growth, along with probabilistic histograms of injectivity damage parameters, is applied to well injectivity decline prediction during produced water disposal in a thick low permeable formation (Völkersen field). An impedance curve with an unusual convex form is observed in both coreflood test and well behavior modeling; the impedance growth rate is lower during external filter cake build-up if compared with the deep bed filtration stage. Low reservoir rock permeability and, consequently, high values of filtration and formation damage coefficients lead to fast impedance growth during deep bed filtration; while external filter cake formation results in relatively slow impedance growth. A risk analysis employing probabilistic histograms of injectivity damage parameters is used to well behavior prediction under high uncertainty conditions.

Summary Long horizontal and multilateral oil and gas wells provide an attractive option for maximizing reservoir contact. Formate-based brines have been used in drilling and completion operations for more than 10 years. Advantages of these fluids include high density, solid-free brines, better compatibility with XC polymer, starches, and less potential for formation damage. These advantages were reported in several previous publications. Filter cakes that are generated by drilling fluids can act as a barrier to the fluid flow in both cased and openhole wells. Calcium carbonate particles are frequently used as weighting material to maintain the pressure that is required for well control and minimizing leakoff rate. These solid particles become consolidated and trapped in a polymeric material, and this makes the filter cake a very effective permeability barrier. The conventional method for cleaning filter cake is by using solids-free formate brines, either by soaking or circulating for many hours at high flow rates. This mechanical technique removes only external filter cake. Chemical means like acids, oxidizers, chelating agents, enzymes, or combinations of these chemicals are usually used as an alternative method for dissolving both the external and internal filter cake. Most of these fluids cannot give a full coverage to the wellbore because of the formation heterogeneity. A new precursor (ester of an organic acid) can generate an acid downhole at a low release rate, which results in uniform fluid distribution through the wellbore. Compatibility and thermal stability tests between the precursor solution and formation brine were studied in detail. Return permeability experiments were conducted by using high-pressure/high-temperature (HP/HT) dynamic fluid loss cells. The ester solution was effective in cleaning the filter cake in comparison to the formate brines. A field application, where formate brine was used to drill and complete a gas producer in a sandstone reservoir, is included in this paper. The gas well was drilled in a weakly consolidated reservoir and was completed with expandable sand screens (ESSs). The bottomhole temperature was 285°F. The produced gas contained 2–3 vol% carbon dioxide and no hydrogen sulfide. Full analysis of flowback samples indicated that most of the returned solids were calcium carbonate. Laboratory tests indicated that the ester solution can be used to restore well productivity by removing damage induced by the drilling mud filter cake.

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 97169, "Multidimensional Velocity-Based Model of Formation Permeability Damage: Validation, Damage Characterization, and Field Application," by R.S. Mojarad, SPE, and A. Settari, SPE, U. of Calgary, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October. The loss of injectivity in produced-water and seawater injectors results from formation plugging. Reliable modeling of the permeability loss is key to analysis of field data and to the design and economics of projects. Standard formulation of damage mechanics uses the concentration-based, classical deep-bed filtration (DBF) model, which is not easily implemented in reservoir simulators. This alternative damage-modeling approach is based on the formulation proposed by Bachman et al.: "Coupled Simulation of Reservoir Flow, Geomechanics, and Formation Plugging With Application to High-Rate Produced-Water Reinjection," paper SPE 79695. The numerical implementation of this empirical, velocity-based damage model (VBDM) is extended to 2D flow and is validated by a comparison with the DBF model. The velocity model provides a remarkably accurate approximation of the more complex concentration model. Introduction Injectivity decline caused by particles in the injection water occurs to some extent in most injection wells. To understand and predict this decline, it is necessary to know about the water quality, formation characteristics, and deposition rate. In the classical DBF model, injectivity decline is characterized by two parameters: filtration coefficient, λ, and formation-damage coefficient, β. Methods to determine these parameters involve difficult measurements, scaling problems, and simplifying the assumptions of analytical solutions. Moreover, the model is not easily implemented in reservoir simulators. An empirical VBDM was developed previously that could be tuned to field or laboratory data and easily implemented in reservoir simulators. However, the model was formulated only in 1D, and its extension (and validity) in multidimensional flow was not shown. The full-length paper presents a 2D formulation and numerical implementation of permeability impairment that uses the VBDM. The results were compared with the classical DBF approach to validate the result against the DBF theory. A unique relation between the parameters of the two models was found that was key to developing a new method to determine the λ and β damage-characterization parameters on the basis of matching laboratory or field data with the velocity-based model. In this way, the number of parameters that need to be determined experimentally can be reduced. Mechanisms The injectivity decline caused by contaminated-water injection can be attributed to several primary mechanisms including internal filtration and external filter-cake buildup and its associated permeability reduction. Depending on details of the case studied (e.g., particle-size/pore-throat-size ratio, surface charge, or injection rate), either of the mentioned mechanisms could dominate. Large particles will be intercepted at the porous formation face, resulting in an external filter cake. Small particles can travel through the formation and initially plug the pore throats by bridging, thus creating internal pore restrictions. Continued buildup of internal plugging over time can also lead to an external filter cake. Once valid models have been obtained for each of these mechanisms, they can be coupled to describe the complete system of formation damage.

Deep bed and cake filtration of two-size particle suspension in porous media

Polymer flooding is one of the most widely used chemical enhanced oil recovery methods due to its simplicity and low cost. To achieve high oil recoveries, large quantities of polymer solution is often injected through a small wellbore. Sometimes, the economic success of the project is only feasible when injection rate is high for high viscosity solution. However, injection of viscous polymer solutions has been a concern for the field application of polymer flooding.The pressure increase in polymer injectors can be attributed to (1) formation of an oil bank, (2) polymer rheology (shear-thickening behavior at near well-bore), and (3) plugging of the reservoir pores by insoluble polymer molecules or suspended particles in the water.In this paper, we propose a new model to history match field injection rate/pressure data. The pertinent equations for deep-bed filtration and external cake build-up in radial coordinate were coupled to the viscoelastic polymer rheology to capture important mechanisms. We selected radial coordinate in order to minimize the velocity/shear rate errors due to gridblock size in Cartesian coordinate.We used filtration theory and successfully history matched the field data. We performed systematic simulations and studied the impact of adsorption (retention), shear thickening, deep bed filtration, and external cake formation to explain the well injectivity behavior of polymer. The simulation results indicate that the gradual increase in bottomhole pressure during early times is attributed to the shear thickening rheology at high velocities experienced by viscoelastic HPAM polymers around the wellbore and the permeability reduction due to polymer adsorption and internal filtration of undissolved polymer. However, the linear impedance during external cake growth is responsible for the sharper increase in injection pressure at the later times.The proposed model can be used to calculate the injectivity of the polymer injection wells, understand the contribution of different phenomena on the pressure rise in the wells, locate the plugging or damage that may be caused by polymer, and accordingly design the chemical stimulation if necessary.

The Provost Dina 'X' Pool is a turbidite sand with a pay zone of up to 20 m at a depth of 200 mSS. The field contains approximately 1.2 million m3 of oil and there is a bottom water aquifer with partial pressure support in parts of the field. Most of the vertical wells in the field shut-in due to high water cuts after a relatively short period of production. Therefore, a numerical simulation study of the whole field was undertaken in order to improve recovery by infill drilling as well as by investigating different operating strategies. This paper describes the integrated team approach taken with input from the geological, production and reservoir engineering specialists to construct a reservoir model. The model has been successfully history matched and used, in turn, for predicting the performance of the field under existing conditions as well as a variety of infill drilling and operating scenarios. Results indicate that significant water coning, which would be observed with new vertical wells in certain areas of the pool, can be reduced through horizontal infill wells. Despite the potential technical success of horizontal infill wells, they were not economically feasible in this particular reservoir and vertical infill wells were the preferred choice. It is shown that a combination of carefully planned vertical infill wells and a pressure maintenance program is able to boost the ultimate recovery by 34% while keeping the development costs to a minimum. Results of various operating strategies are presented and the optimum field development scenario implemented in the field is outlined. The initial actual reservoir behaviour is discussed in the light of the results from the simulation study. Introduction The Provost Dina 'X' pool was discovered in 1988 at an initial pressure of 6450 kPa. The reservoir is located in east central Alberta, south of the town of Consort. The formation is a turbidite sand with a limited bottom water aquifer support. The production from the pool began with the discovery well 05-15-35-06 W4M and, to date, a total of 11 wells have delineated a reservoir area of slightly more than 32 ha. (see Figure 1). Historically, most of the vertical wells in the field experience high water cuts after a relatively short period of production. Thus, a significant portion of the reserves cannot be produced because of water coning. Infill drilling can compete favourably with BOR processes for the recovery of the bypassed oil for much less investment and operating cost. As the existing vertical wells have to be operated above the critical water coning rates to be economic, horizontal wells become another option for infill drilling. The field experience indicates that horizontal wells can reduce the water coning tendency while increasing the oil production. However, further improvement to oil production rate of horizontal wells is still limited by the encroachment of the water cone when the bottom water exists. Therefore a simulation study was undertaken to investigate the feasibility of increasing reserves by infill drilling with horizontal and vertical wells. Model Construction The black oil simulation module (SimBest II) of The Petroleum WorkBench reservoir management package of Scientific Software-Intercomp was used to conduct this simulation study. SimBest II is a three-dimensional, fully implicit reservoir simulator which is capable of handling as many as three fluid phases and five components in a dual and/or single porosity mode. P. 555

The purpose of this paper is to report on the field test results of the Texaco Canada Petroleum Inc. (TEXCAN) and the Alberta Department of Energy (ADOE, formally AOSTRA), Electrical Horizontal Well Project in the Lloydminster heavy oil area. Two vertical wells (15D-25-56-2W4 and 13C-30-56-1W4) and one horizontal well (16D-25-56-2W4) were connected electrically and heated. This paper presents an overview of electrically heating a horizontal well with vertical wells, the design of the electrical heating system, operational experience, test data, and a discussion on the successes and problems of the project. Three wells were electrically heated; two deviated vertical wells and one horizontal well. The pilot project experienced premature equipment failure and sand production problems. Although a significant production response was achieved at the vertical wells, ongoing operations were not achieved because of sanding problems. The sand problem required daily workovers on the wells to maintain operations. As a result of these problems, and the limited current that can be supplied from just two vertical wells, the thermal response at the horizontal well was 3 - 5 °C and no production response was observed. The project was a technical success in that electrical current from two vertical wells was returned to the power conditioning units via the horizontal well and a thermal response was observed at all the wells. At the vertical wells, there was at times a greater than three times productivity response during electrical heating operations. Introduction Horizontal Wells and Heavy Oil Horizontal wells, typically 500 m in length and longer, are common in the exploitation of heavy oil reservoirs around the world. Horizontal wells offer prospects of improved performance over vertical wells, primarily due to the larger contact area between the formation and the wellbore. Also, the technology for drilling a horizontal well is as advanced as for drilling a vertical well. The cost of drilling a horizontal well is about the same as the cost to drill two to three vertical wells. There are production disadvantages and problems that are unique to a horizontal well application in heavy oil reservoirs. The production rate declines very rapidly during the first several months of production. It is also possible that the entire length of the horizontal well may not be productive. In some production systems, the limiting factor in producing the oil is the mechanical limitation of the pumping equipment, which is exceeded because of the very high viscosity of the oil. Finally, there may be skin effects, such as the visco-skin(1) that may further reduce the productivity of the well. This skin effect and other thermally alterable skin effects (for example, asphaltene precipitation) can block flow into the well, thereby decreasing the effective length and productivity of the well. Increasing the effective length of the well and removing any skin effects can improve the productivity of the well. Electrical Heating Electrical heating of vertical wells has been attempted on several occasions with encouraging results(2-10). Until now, there have been no electrical heating tests that use horizontal wells.

Stable cones created by a horizontal well drilled with maximum clearance from the unwanted fluid are studied (Muskat9 type approach, using pertinent viscous flow potential), yielding practical values for the critical rate per unit length of a horizontal well, and for the critical cone elevation, depending on both vertical and horizontal permeabilities, oil thickness, both fluid gravities, and oil viscosity. Critical rate weakly decreases when vertical permeability decreases. The same type of analysis is repeated for a vertical well completed over a very short interval (modelized as a point source) also with maximum clearance from the gas cap or water table, yielding values of critical rate and cone height for the vertical well. In this case the critical rate slightly increases when vertical permeability decreases. The outcome of a comparison between both types of wells shows that a critical cone comes closer to the horizontal well than to the vertical well. Also horizontal wells generally allow higher critical rates than vertical wells, however this advantage lessens with increased anisotropy. Very simple formulas are provided to evaluate what gain in critical rate may be obtained from a horizontal well.

The largest component of operating costs in most matured assets utilizing 3rd party evacuation infrastructure is crude handling charges. In mature fields with significant water production, water volumes could easily account for over half of crude handling costs. Produced water re-injection for disposal has become a popular strategy for optimizing liquid handling cost as well as supporting environmental responsibility. Injectivity for water disposal wells have been demonstrated to decline with time, the most common factor being permeability reduction arising mostly from fines migration, suspended and dissolved solids in injected water, microbial activities, oil in water and cation concentrations, etc. Thus, Injection wells typically require intermittent stimulation to restore or improve injectivity. Fracturing has been demonstrated to prolong injectivity. However, sustainability is greatly affected by ability to keep fractures open after shut-ins and limited by environmental regulations. Understanding the key mechanisms that lead to injectivity decline will help optimize produced water reinjection systems, enable proactive intervention planning, thus improve injectivity and well availability. In this work we present the development of an injectivity modelling and simulation tool called IDS based on relatively recent injectivity models. Testing and validation of the tool using standard data and an active onshore Niger-Delta Produced Water Reinjection Project as a case study are presented. An outstanding feature of this simulator is its ability to estimate missing parameters or those whose values are not known to high fidelity via history matching. The resulting nonlinear regression problem is solved using a trust-region reflective approach. Decline mechanism regression parameters were similar for a well that had multiple injection periods. Transition time from deep bed to external cake is very sensitive to Total Suspended Solids (TSS) in injected water. Injectivity half-life could increase by as much as 100% for about a 100% drop in mean TSS concentration. The IDS tool was used to predict the injectivity half-life of Well A in the water disposal project.

A compositional equation-of-state simulator has been used to make comparisons of CO2 process performance with several combinations of horizontal and vertical wells and various alternative reservoir descriptions. This is the first time that the performance of CO2 flooding using horizontal wells has been reported. We have used the reservoir and fluid properties of an actual West Texas carbonate reservoir that is currently being waterflooded. The phase behavior and properties of the CO2 used in these simulations are typical of those of multiple-contact- miscible field conditions of West Texas. A layered-type reservoir description was initially used to investigate the effect of water- altemating-gas (WAG) ratio with various combinations of well types. We then investigated the effect of vertical permeability, length, and position of the horizontal injector using the same reservoir description and a horizontal injector-vertical producer combination. Similar investigations using an unconditioned stochastic permeability field having a Dykstra Parsons coefficient (VDP) of 0.81 were made. Our final three-phase flow simulation was performed using a stochastic permeability field conditioned with core data. Since three nonaqueous phases can occur at low temperatures typical of West Texas floods resulting in up to four-phase flow with mobile water, we investigated the impact of four-phase flow in one of these simulations. This is the first time that three-dimensional, four-phase flow reservoir simulations have been reported with either vertical or horizontal wells.

Classical models for deep bed filtration (DBF) and external cake formation predict a linear growth of the pressure drop with time along the core, and its abrupt increase after the transition time. In such models, there is a delay of the external cake formation if compared with particle filtration into porous media, under the assumptions of mono-sized particle injection or particle sizes smaller than all the pore sizes. However, significant deviation of well and laboratory data from the mono-sized model has been widely reported and explained by particle size variation. In the present work, the mathematical model for injection of bi-sized particle suspension into porous media has been developed accounting for deep bed filtration of small particles, formation of cake by large particles, filling of the cake by small particles and formation of a new cake by small and large particles mixture at the late stage. Analytical solution has been derived. The laboratory injections of bi-sized particle suspension into reservoir cores have been performed with monitoring the pressure drop across the core and the breakthrough particle concentration. The impedance profile from experiment matches well with the model prediction, which validates the proposed model. Application of this model would contribute to proper design of drilling fluid and prediction of leak-off into the reservoir during drilling.

Abstract. Conventional models of pumping tests in unconfined aquifers often neglect the unsaturated flow process. This study concerns the coupled unsaturated–saturated flow process induced by vertical, horizontal, and slant wells positioned in an unconfined aquifer. A mathematical model is established with special consideration of the coupled unsaturated–saturated flow process and the well orientation. Groundwater flow in the saturated zone is described by a three-dimensional governing equation and a linearized three-dimensional Richards' equation in the unsaturated zone. A solution in the Laplace domain is derived by the Laplace–finite-Fourier-transform and the method of separation of variables, and the semi-analytical solutions are obtained using a numerical inverse Laplace method. The solution is verified by a finite-element numerical model. It is found that the effects of the unsaturated zone on the drawdown of a pumping test exist at any angle of inclination of the pumping well, and this impact is more significant in the case of a horizontal well. The effects of the unsaturated zone on the drawdown are independent of the length of the horizontal well screen. The vertical well leads to the largest water volume drained from the unsaturated zone (W) during the early pumping time, and the effects of the well orientation on W values become insignificant at the later time. The screen length of the horizontal well does not affect W for the whole pumping period. The proposed solutions are useful for the parameter identification of pumping tests with a general well orientation (vertical, horizontal, and slant) in unconfined aquifers affected from above by the unsaturated flow process.

Properties of gas condensate reservoirs are particularly difficult to study due to the composition and phase changes of light components that occur during the reservoir depletion. At the first stage of their discovery, these reservoirs behave like gas reservoirs during depletion. Once the dew point pressure is reached at reservoir conditions of pressure and temperature a retrograde condensation phase develops in the reservoir. Liquid condensation in the formation can result in severe loss of well deliverability and therefore of gas and condensate recovery, which will certainly lead to a loss of income. In this study, the performance of horizontal wells and vertical wells in Gas condensate reservoirs is investigated under various depletion schemes. The expected low horizontal well drawdown pressure, compared to vertical well for the same flow rate, considerably reduces retrograde condensation. A reservoir simulator is used to compare liquid saturation profiles in the case of horizontal and vertical wells in Gas condensate reservoirs. The influence of the horizontal well length section and reservoir thickness on horizontal well productivity, and condensate recovery were also simulated. Another factor investigated in this study is the effect of drilling a horizontal well in a Gas condensate reservoir that has already been developed by vertical wells. To illustrate the productivity increase due to the use of horizontal wells in gas condensate reservoirs, Djebel Bissa field data are presented and discussed using a compositional single well model (VIP simulator). The main results of this investigation are: Because pressure drawdown is smaller for a horizontal well than that for a vertical well, the problems related to the liquid deposit can be reduced by the use of horizontal wells. Layers of value of kh contains the most liquid accumulations.

A computer model has been developed to investigate the potential effects of water injection in an offshore oilfield on H2S biogeneration and its subsequent production from the reservoir. The model is based on mechanistic algorithms employed in previous reservoir souring models developed for the Prudhoe Bay and Kuparuk River Fields (Alaska) and the Ekofisk Field (Norway). These mechanisms include the biogeneration of H2S, the partitioning of H2S between oil and water in the waterflooded portions of the reservoir, the reaction of dissolved H2S with siderite to form immobile iron sulfides, and the transport of H2S, oil, water, and gas to producing wells. The reservoir is currently being seawater flooded although produced water reinjection (PWRI) will soon be initiated. In mid-2006, after less than three years of waterflood at relatively low injection rates, H2S was detected in the gas of several producing wells located close to injectors. It is known that PWRI will result in increased H2S production. The model was initially calibrated via history match to determine algorithm coefficients associated with siderite scavenging and microbial nutrient availability within the reservoir during seawater flooding. This calibration required historical produced water sulfate concentrations and H2S mass production rates in order to ascertain actual biogenic sulfate reduction levels and the remaining amount of H2S scavenged by the siderite following its partitioning to reservoir fluids. Results indicate that while scavenging by the siderite is likely occurring at a relatively high level, the H2S production rate will increase significantly once water injection rates are increased and PWRI begins. This paper presents insight as to the importance of water geochemistry in the reservoir souring process and the potential for siderite reactivity, distribution and availability to affect H2S production.

The Gulf of Thailand (GoT) is south of Bangkok. The pay interval typically covers 3000 to 5000 vertical feet. It is composed of a series of stacked fluvial point bars sands that have limited areal extent. In addition, normal faulting breaks them up further. Because all 40 acre wells will be drilled at some point, the justification for drilling a horizontal well is based on incremental recovery over vertical wells. In 2010, a team was assembled to look at establishing a common method to evaluate horizontal wells. Production results from horizontal wells were compared to vertical wells. Concept models were used to evaluate different factors in horizontal well recovery. Where available, history matched simulation models were used to compare horizontal to vertical wells. In addition, the team looked at factors in horizontal well performance. The team collected information on all wells drilled. The team looked for relationships to EUR and recovery factor. Then, the team took a more in depth study of the best horizontals and the worst horizontals. The overall recovery factor averages 20% for horizontal wells and 12.5% for an equivalent vertical well. The average incremental is 7.5%. There are three sources for this difference. The first is improved areal sweep efficiency of a horizontal well. The second is lower abandonment pressure with deep gas lift valves than with a vertical well. In looking at the best and worst performing horizontal wells, the poorer wells were in small reservoirs, often drilled very close to contacts and some were drilled into depleted reservoirs. The best wells were drilled in large very continuous reservoirs and often had strong reservoir drive (either water drive or gas cap expansion). Description The Gulf of Thailand (GoT) is south of Bangkok. Figure 1 is a map of the Gulf of Thailand. The pay interval typically covers 3000 to5000 vertical feet. It is composed of a series of stacked fluvial point bars sands that have limited areal extent. In addition, normal faulting breaks them up further. The overall development strategy is to drill wells on equal spacing (40 acres) on the high side of the faults to encounter as many sands as possible. Figure 2 illustrates the stratagraphic and structural complexity. Chevron has drilled over 80 horizontal wells in the GoT with an average of about 5–10 every year. The targets are oil reservoirs that are at least 25 feet thick. By nature of the depositional and structural setting, these are relatively small reservoirs, usually with OOIP between 0.7 to 6.0 MMBO. The sands can have both a GOC and an OWC. Because all 40 acre wells will be drilled at some point, the justification for drilling a horizontal well is based on incremental recovery over vertical wells. Because the horizontal well design and execution plans are typically developed during the same drilling programs of vertical wells, a quick and reliable method of horizontal well evaluation is needed. In 2010, as part of the Reservoir Management Framework, a team was assembled to look at establishing a common method to evaluate horizontal wells. As part of this initiative, the team looked at factors in horizontal well performance. The study also included a comparison to vertical wells. The team used a multi faceted approach. Production results from horizontal wells were compared to vertical wells. Concept models were used to evaluate different factors in horizontal well recovery. Where available, history matched simulation models were used to compare horizontal to vertical wells.