Field Demonstration of the Impact of Fractures on Hydrolyzed Polyacrylamide Injectivity, Propagation, and Degradation

Summary During a polymer flood, the field operator must be convinced that the large chemical investment is not compromised during polymer injection. Furthermore, injectivity associated with the viscous polymer solutions must not be reduced to where fluid throughput in the reservoir and oil production rates become uneconomic. Fractures with limited length and proper orientation have been theoretically argued to dramatically increase polymer injectivity and eliminate polymer mechanical degradation. This paper confirms these predictions through a combination of calculations, laboratory measurements, and field observations (including step-rate tests, pressure transient analysis, and analysis of fluid samples flowed back from injection wells and produced from offset production wells) associated with the Kalamkas oil field in Western Kazakhstan. A novel method was developed to collect samples of fluids that were back-produced from injection wells using the natural energy of a reservoir at the wellhead. This method included a special procedure and surface-equipment scheme to protect samples from oxidative degradation. Rheological measurements of back-produced polymer solutions revealed no polymer mechanical degradation for conditions at the Kalamkas oil field. An injection well pressure falloff test and a step-rate test confirmed that polymer injection occurred above the formation parting pressure. The open fracture area was high enough to ensure low flow velocity for the polymer solution (and consequently, the mechanical stability of the polymer). Compared to other laboratory and field procedures, this new method is quick, simple, cheap, and reliable. Tests also confirmed that contact with the formation rapidly depleted dissolved oxygen from the fluids—thereby promoting polymer chemical stability.

Risk decreasing of water waste through spontaneous fracturing in injectors by integrated well-testing and production logging

Background. When creating an effective reservoir pressure maintenance system, unstable spontaneous hydraulic fractures can be created in injection wells. This can both negatively and positively affect hydrocarbon production. First, fracture improves reservoir connectivity, which increases injection efficiency. On the other hand, unstable fractures can cause behind-the-casing flows and unproductive injection into off-target layers or fingering. Goal. The paper is devoted to the analysis of well testing (PTA) and production logging (PLT) improvement for the diagnosis of unstable fractures in injection wells. Materials and methods. The analysis is based on the results of modeling the pressure in the reservoir system, describing the penetration reservoirs by an unrestricted conductivity unstable fracture. It is taken into account that the fracture can cross both the perforated formation and the thickness not penetrated by the perforation, and can grow with increasing overbalance. The modeling results made it possible both to assess the potential informative capabilities of well testing and to substantiate recommendations for the practical use of the obtained results. Conclusions. The proposed approaches to the technology of well testing and production logging and the interpretation of their results make it possible to estimate the additional thicknesses of the reservoirs connected by the spontaneous hydraulic fracturing to injection, the proportion of nonproductive injection in the total volume of the well. The research technology used by the authors is based on continuous measurements of pressure and flow rate during cyclic change of pressure and assessment of the effective transmissibility of the formation system at different heights of unstable fractures. The role of the PLT is to determine the effective production thickness of the reservoirs. When assessing the injectivity profile when penetrating the injector with the spontaneous hydraulic fracturing, the key role belongs to non-stationary temperature logging. In this case, it is necessary to take into account the specific features of temperature relaxation in the wellbore after the injection cycle, related to hydraulic fracturing, primarily the increase in the relaxation rate with increasing fracture length.

MODELING OF PRODUCING PRESSURE IN HETEROGENEOUS OIL-BEARING RESERVOIRS

Numerical modeling of the distribution of the reservoir pressure drop in the vicinity of an operating well was carried out taking into account the inhomogeneous distribution of filtration characteristics (permeability and oil viscosity) in the near and distant zones of the well operation in order to study the practical aspects of filtration in heterogeneous oil-bearing formations based on a combined finite-element-difference method for non-stationary problem of piezoconductivity. The use of the combined finite-element-difference method enables to combine the advantages of the finite-element method and the finite difference method: to model geometrically complex areas, to find the value at any point of the object under study, while the implicit difference scheme. It is shown that the intensity of filtration processes in the vicinity of the operating well depends mainly on the permeability, and, to a lesser extent, on the viscosity of the oil. Moreover, the influence of the permeability of the oil phase in the remote zone (Rd < 5 m) is greater than the effect in the close zone (Rd > 5 m) of the operating well. In the case of low permeability of the oil phase in the vicinity of the existing well, to maintain stable oil production, it is necessary to place an injection well near the production well. Using the method suggested, it is possible to predict the effect of the injection well on the formation pressure distribution in the formation. The scientific novelty of the work lies in the study of the influence of the heterogeneous permeability and oil viscosity distribution on the reservoir pressures distribution around the wells by modeling filtration processes based on a combined finite-element-difference method. The practical significance of the research results comes down to confirming the close relationship between the heterogeneity of the porous medium and the reservoir pressures distribution around an operating producing well. The combined finite-element-difference method used in this work can be used to solve other filtration problems (for example, to calculate the gas saturation of a reservoir, create a method for calculating well flow rates, assess the effect of injection wells on filtration processes).

Successful Remediation of Sustained Casing Pressures in Gas Cap Injector Wells with the Use of Flexible and Self Healing System

Several injection wells in Prudhoe Bay, Alaska exhibit sustained casing pressure (SCP) between the production tubing and the inner casing. The diagnostics on these wells have shown communication due to issues with casing leaks. Conventional cement systems have historically been used in coiled-tubing-delivered squeeze jobs to repair the leaks. However, even when these squeeze jobs are executed successfully, there is no guarantee in the short or long term that the annular communication is repaired. Many of these injector wells develop SCP in the range of 300-400 psi post-repair. It has been observed that the SCP development can reoccur immediately after annulus communication repair, or months to years after an injector well is put back on injection. Once SCP is developed the well cannot be operated further. A new generation of cement system was used to overcome the remedial challenge presented in these injector wells. This document provides the successful application of a specialized adaptive cement system conveyed to the problematic zone with the advantage of using coiled tubing equipment for optimum delivery of the remedial treatment.

Identification and research of factors affecting the optimal distribution of well flow rates in space

The paper discusses and research the factors affecting the filtration rate to reduce stagnant zones in the domain and spreading outside the block under consideration. The main hydrodynamic factors in production by In-Situ Leaching are the distribution of permeability in the reservoir and well flow rates. The study of the factors was carried out on the basis of mathematical models using Darcy Law and Law of Conservation of Mass. Calculation was accomplished on a two-dimensional area with an isotropic and non-uniform permeability distribution to determine the effect of permeability on the leached area. The permeability coefficient was distributed respectively over three zones, in the southern part the permeability was low, in the central transition from low to high, respectively, in the northern part there was a highly permeable zone. Three wells were located in the domain, with the production well in the center of the domain. Injection wells are located symmetrically with respect to a horizontal line passing through the center of the area under consideration. The calculation was carried out for three modes of well flow rates with the ratio of the flow rates of the injection wells 0.5 / 0.5, 0.2 / 0.8, 0.8 / 0.2 relative to the flow rate of the production well. On the basis of comparative analyzes of the obtained results, it is concluded that: at the same flow rates, regardless of the permeability of the zones, the results obtained show that the leaching area in the low-permeability zone is larger in comparison with the high-permeability zone; with an increase in permeability, the shape of the leaching zone tends from round to drop-shaped; with an increase in the flow rate of wells in the radius of the leaching zone, it increases if the flow rate of solutions is much higher than the filtration rate.

Reservoir Management Optimization Model Employing Combination Deterministic and Probabilistic Approach for Carbon Sequestration Storage and Utilization: A Case Study from East Natuna

East Natuna is well known for its huge natural gas reserves with a very high CO2 content. The appearance of CO2 content in an oil and gas field is always considered as waste material and will severely affect the economic value of the field. The higher the content, the more costly the process, both technically and environmentally. In this research, the newly proposed reservoir management approach called CSSU (Carbon Sequestration Storage and Utilization) method is trying to change the paradigm of CO2 from waste material into economic materials. The novelty of this research is the combined optimization of deterministic and stochastic methods with the Particle Swarm Optimization (PSO) algorithm to answer complex and non-linear problems in the CSSU (Carbon Sequestration Storage and Utilization) method. The CSSU method is an integration of geological, geophysical, reservoir engineering and engineering economics with the determination of technical and economic optimization of the use of CO2 produced as working fluid in a power generation system that has been conditioned through an injection-production system in geological formations. The CSSU research area is located in a sedimentary basin that has a giant gas field with 70% CO2 content. The Volumetric Storage Capacity for CO2 injection process in research area is 1,749.14 BCF or 94.01 MMTon which being calculated based on static modeling considering geological, geophysical and petrophysical aspects. A combination of Compositional, Geomechanics and Thermal reservoir simulation model had been conducted to determines the Storage Injection capacity and later to prove the CSSU method in which CO2 fluids will be utilized as working fluid, 1 case was built using 2 Injection Wells and 1 CO2 fluid Production Well. The simulation results show with 1 production well the total of CO2 fluid injected from 2 Injection wells can almost double the injection total capacity up to 1,150 BCF. The utilization of supercritical CO2 fluid as working fluid can produce 55 – 133.5 MMBTU/Day or 0.67 - 1.63 MW from 1 production well for 25 years timeframe. The CSSU method is optimized by deterministic and stochastic methods using the Particle Swarm Optimization (PSO) algorithm by looking the technical and economical aspects. The technical optimization aspect is being analyzed by electricity production versus well counts. The economical optimization is being analyzed by operational expenditure saving versus well counts and electricity produced versus NPV 10%. From both aspects the 4 injector wells case and NPV 200.00 MM US$ gives the most optimum result within technically and economically. The CSSU economic model proved with CSSU scheme the economical value is being increased by 57 MMUS$ after operating cost efficiency due to the electricity savings, 92 MMUS$ due to Carbon Trading which resulting the NPV 10% is 172.77 MMUS$.

Safeguarding CO2 Storage in a Depleted Offshore Gas Field with Adaptive Approach of Monitoring, Measurement and Verification MMV

CO2 sequestration is a process for eternity with a possibility of zero-degree failure. One of the key components of the CO2 Sequestration Project is to have a site-specific, risk-based and adaptive Monitoring, Measurement and Verification (MMV) plan. The storage site has been studied thoroughly and is understood to be inherently safe for CO2 sequestration. However, it is incumbent on operator to manage and minimize storage risks. MMV planning is critical along with geological site selection, transportation and storage process. Geological evaluation study of the storage site suggests the containment capacity of identified large depleted gas reservoirs as well as long term conformance due to thick interval. The fault-seal analysis and reservoir integrity study contemplate long-term security of the CO2 storage. An integrated 3D reservoir dynamic simulation model coupled with geomechanical and geochemical models were performed. This helps in understanding storage capacity, trapping mechanisms, reservoir integrity, plume migration path, and injectivity. To demonstrate that CO2 plume migration can be mapped from the seismic, a 4D Seismic feasibility study was carried out using well and fluid data. Gassmann fluid substitution was performed in carbonate reservoir at well, and seismic response of several combination of fluid saturation scenarios on synthetic gathers were analyzed. The CO2 dispersion study, which incorporate integration of subsurface, geomatic and metocean & environment data along with leakage character information, was carried out to understand the potential leakage pathway along existing wells and faults which enable to design a monitoring plan accordingly. The monitoring of wells & reservoir integrity, overburden integrity will be carried out by Fiber Optic System to be installed in injection wells. Significant difference in seismic amplitude observed at the reservoir top during 4D seismic feasibility study for varying CO2 saturation suggests that monitoring of CO2 plume migration from seismic is possible. CO2 plume front with as low as 25% saturation can be discriminated provided seismic data has high signal noise ratio (SNR). 3D DAS-VSP acquisition modeling results show that a subsurface coverage of approximately 3 km2 per well is achievable. Laboratory injectivity studies and three-way coupled modelling simulations established that three injection wells will be required to achieve the target injection rate. As planned injection wells are field centric and storage site area is large, DAS-VSP find limited coverage to monitor the CO2 plume front. Hence, surface seismic acquisition will be an integral component of full field monitoring and time-lapsed evaluations for integrated MMV planning to monitor CO2 plume migration. The integrated MMV planning is designed to ensure that injected CO2 in the reservoir is intact and safely stored for hundreds of years after injection. Field specific MMV technologies for CO2 plume migration with proactive approach were identified after exercising pre-defined screening criteria.

New Online Shunt Acidification for Water Injection Increasing Technology and Its Application in Huanjiang Oilfield

The poor physical property and strong heterogeneity of Triassic Yanchang formation in Huanjiang oilfield of Ordos Basin are the main reasons for uneven water absorption, partial injection wells underinjection at high pressure, and decline of production. Previously, large numbers of conventional acidifications were used for plugging removal in the reservoir, but the effect was not so good and effective period was short. Aiming at the geological characteristics of Huanjiang oilfield, an online shunt acidification and augmented injection technology which does not stop water injection, pull original production strings out, and continuously inject acid and diverting agent has been proposed. A chelating acid COA-1S with low corrosion rate (0.3675 g/(m2·h)), good retardation capacity (hydrolysis constant = 1.2 × 10−6), and effective chelating ability (precipitation inhibition rate >95%) has been developed, as well as a diverting agent COA-1P with good dispersion in acid solution, diversion effect, and particle size (10–100 μm), which behaves well in COA-1S acid. It has been proved that the online acid system has a good diversion acidizing ability and plugging removal performance in a deep area in the laboratory core physical simulation test. The field test results show that the online shunt acidizing and augmented injection technology could reduce the injection pressure significantly (4.2 MPa) and increase water injection by 10 m3/d for the measured well (H5) and improve the water injection profile prominently. The online shunting acidification and augmented injection technology have the following advantages: simple procedures, fewer equipment needed, high efficiency of depressurization, and increasing water injection, which could effectively improve the profile of water wells, and there is a bright future of the technology.

Field Implementation of In-Depth Conformance Gel Treatment Prior to Starting an ASP Flooding Pilot

Mature carbonate reservoirs under waterflood in Kuwait suffer from relatively low oil recovery due to poor volumetric sweep efficiency, both areal, vertically, and microscopically. An Alkaline-Surfactant-Polymer (ASP) pilot using a regular five-spot well pattern is in progress targeting the Sabriyah Mauddud (SAMA) reservoir in pursuit of reserves growth and production sustainability. SAMA suffers from reservoir heterogeneities mainly associated with permeability contrast which may be improved with a conformance treatment to de-risk pre-mature breakthrough of water and chemical EOR agents in preparation for subsequent ASP injection and to improve reservoir contact by the injected fluids. Each of the four injection wells in the SAMA ASP pilot was treated with a chemical conformance improvement formulation. A high viscosity polymer solution (HVPS) of 200 cP was injected prior to a gelant formulation consisting of P300 polymer and X1050 crosslinker. After a shut-in period, wells were then returned to water injection. Injection of high viscosity polymer solution (HVPS) at the four injection wells showed no increase in injection pressure and occurred higher than expected injection rates. Early breakthrough of polymer was observed at SA-0561 production well from three of the four injection wells. No appreciable change in oil cut was observed. HVPS did not improve volumetric sweep efficiency based on the injection and production data. Gel treatment to improve the volumetric conformance of the four injection wells resulted in all the injection wells showing increased of injection pressure from approximately 3000 psi to 3600 psi while injecting at a constant rate of approximately 2,000 bb/day/well. Injection profiles from each of the injection well ILTs showed increased injection into lower-capacity zones and decreased injection into high-capacity zones. Inter-well tracer testing showed delayed tracer breakthrough at the center SA-0561 production well from each of the four injection wells after gel placement. SA-0561 produced average daily produced temperature increased from approximately 40°C to over 50°C. SA-0561 oil cuts increased up to almost 12% from negligible oil sheen prior to gel treatments. Gel treatment improved volumetric sweep efficiency in the SAMA SAP pilot area.