Berry, Sandra L. (Baker Hughes, a GE Company) | Palm, Dustin C. (Baker Hughes, a GE Company) | Usie, Marty J. (Baker Hughes, a GE Company) | Schutz, Ronald W. (TiCorr LLC) | Walker, Heath W. (Arconic Energy Systems)
Matrix acidizing treatments containing hydrogen fluoride (HF) acid have been utilized in stimulation treatments of offshore wells to remove skin associated with fines migration for many years. In the last few years, operators have moved toward the use of organic acid - HF acid treatments due to corrosion concerns in the downhole tubular strings during the initial pumping of live acid and in the Titanium Stress Joints (TSJ) during the acid flow back through the production riser. A corrosion inhibitor to inhibit any unspent HF in the acid flowback returns would be beneficial to operators. Production of spent acid flowing back through the production riser is seriously being considered because significant cost savings may be realized over other acid flowback options. However, although most HF acid systems are mostly and/or highly spent during the reaction time with the formation mineralogy, even small concentrations of remaining free HF in the spent acid returns can result in severe bore surface corrosion (etching) and byproduct hydrogen absorption by the riser system TSJ. Lab studies were performed with several different inhibitor formulations added to two different spent organic - HF acid fluid systems to determine the ability for these candidate inhibitors to thwart corrosion (etching) and corresponding hydrogen uptake on ASTM Grade 29 titanium (Ti-29) test coupons. These candidate inhibitors were subjected to four-hour exposure tests conducted at 170 F under 3500 psi pressure with various inhibitor concentrations to determine if the package could meet screening criteria of corrosion/etch rate of less than 0.5 mils per day (0.5 thousandths of an inch) and hydrogen uptake limits consistent with ASTM product specification limits for the short term exposure (i.e., four hours). These lab test results are compared to those from recent published lab test studies on titanium in live and spent HF containing acid fluids, along with discussion on practical implications and considerations for their field use. Developing a corrosion inhibitor to inhibit the residual HF acid in the spent flowback returns and prevent etching and hydrogen uptake by the TSJ in the production risers not only yields effective protection of the TSJ, allowing flowback fluids to be returned thru the production riser, but also offers a significant operational cost savings.
Any reservoir simulator consists of n m equations for each of N active gridblocks comprising the reservoir. These equations represent conservation of mass of each of n components in each gridblock over a timestep Δt from tn to tn 1. The first n (primary) equations simply express conservation of mass for each of n components such as oil, gas, methane, CO2, and water, denoted by subscript I 1,2,…, n. In the thermal case, one of the "components" is energy and its equation expresses conservation of energy. An additional m (secondary or constraint) equations express constraints such as equal fugacities of each component in all phases where it is present, and the volume balance Sw So Sg Ssolid 1.0, where S solid represents any immobile phase such as precipitated solid salt or coke. There must be n m variables (unknowns) corresponding to these n m equations. There are m 2n 1 constraint equations consisting of the volume balance and the 2n equations expressing equal fugacities of each ...
The linear equation solver is an important component in a reservoir simulator. It is used in the Newton step to solve the discretized nonlinear partial differential equations. These equations describe mass balances on the individual components treated in the model. For nonisothermal problems, an energy balance is added to the system. The matrix problem involves solving Ax b, where A is typically a large sparse matrix, b is the right-side vector, and x is the vector of unknowns.
Streamline simulation provides an alternative to cell-based grid techniques in reservoir simulation. Streamlines represent a snapshot of the instantaneous flow field and thereby produce data such as drainage/irrigation regions associated with producing/injecting wells and flow rate allocation between injector/producer pairs that are not easily determined by other simulation techniques. Streamline-based flow simulation differentiates itself from cell-based simulation techniques such as finite-differences and finite-elements in that phase saturations and components are transported along a flow-based grid defined by streamlines (or streamtubes) rather than moved from cell-to-cell. This difference allows streamlines to be extremely efficient in solving large, heterogeneous models if key assumptions in the formulation are met by the physical system being simulated (see below). Specifically, large relates to the number of active grid cells.
The Merriam-Webster Dictionary defines simulate as assuming the appearance of without the reality. Simulation of petroleum reservoir performance refers to the construction and operation of a model whose behavior assumes the appearance of actual reservoir behavior. A model itself is either physical (for example, a laboratory sandpack) or mathematical. A mathematical model is a set of equations that, subject to certain assumptions, describes the physical processes active in the reservoir. Although the model itself obviously lacks the reality of the reservoir, the behavior of a valid model simulates--assumes the appearance of--the actual reservoir. The purpose of simulation is estimation of field performance (e.g., oil recovery) under one or more producing schemes. Whereas the field can be produced only once, at considerable expense, a model can be produced or run many times at low expense over a short period of time. Observation of model results that represent different producing conditions aids selection of an optimal set of producing conditions for the reservoir.
Bidhendi, Mehrnoosh Moradi (Nalco Champion, An Ecolab Company) | Kazempour, Mahdi (Nalco Champion, An Ecolab Company) | Ibanga, Uwana (Nalco Champion, An Ecolab Company) | Nguyen, Duy (Nalco Champion, An Ecolab Company) | Arruda, Justin (Nalco Champion, An Ecolab Company) | Lantz, Mike (Nalco Champion, An Ecolab Company) | Mazon, Cooper (Nalco Champion, An Ecolab Company)
Unconventional liquid reservoirs are currently one of the most important sources of oil in North America. Oil production experiences a rapid decline in these reservoirs and this has been a major issue faced by many operators. Low oil recovery has been attributed to ultralow permeability, low porosity and oil-wet nature of the reservoir rock. Hence, wettability alteration using chemicals could provide a viable chemical enhanced oil recovery method (cEOR) to increase oil production from these reservoirs.
In this study a set of customized surfactant based chemical formulations have been developed to increase oil recovery from unconventional oil reservoirs in the Permian basin: Wolfcamp A, Wolfcamp B and Spraberry. Comprehensive laboratory experiments have been conducted to study the effect of the chemistry on wettability alteration, along with the result of intensity of micro-fractures on chemical performance has been explored through lab analysis and numerical simulation. Lab results showed that application of a specific chemical formulation leads to persistent wettability alteration and significant oil recovery compared to injection brine, without causing any emulsion issues. It also has been observed that, among other factors, salinity and hardness of the formation brine, oil characteristics, mineralogy of the reservoir, and the intensity of natural fractures play an important role on the chemistry's performance. In addition to the lab findings, a review of the design and execution of a recently completed CEOR huff-n-puff (HnP) trial and results from a two well fracture completion using the chemistry will be provided. The completions trial showed a 39% increase in the 180 cumulative recovery and increased oil cut versus the county type curve. The results for the HnP trial will be communicated in a future publication.
These results combined with previously published material further confirm the efficacy of this chemistry to persistently alter wettability and enhance oil recovery from tight oil reservoirs. The concepts and information here can also be translated to other unconventional basins either liquids or wet/dry gas reservoirs.
The rapid development of a surfactant blend using statistical software tools to drastically reduce the number of laboratory experiments associated with more traditional Edisonian-type approaches is discussed. The study evaluates performance of various surfactant blends for fracturing applications in most major North American shale formation materials and crude oils.
The study entailed identifying key surfactant characteristics, such as hydrophilic-lipophilic balance (HLB), relative solubility number (RSN), and solvency. The parameters were used to create a design of experiments (DoE) with statistical software. Formulating experiments were performed as recommended by the DoE, and selected blends were subjected to tensiometer and petroleum industry application testing. Critical micelle concentration (CMC) and interfacial tension (IFT) values were captured to better understand blend physical properties. Additionally, sand pack column flow (SCF) and emulsion break time (EBT) experiments were conducted to assess blend efficacy when exposed to Niobrara, Bakken, Permian, Mid-Conn, Eagle Ford, and Gulf of Mexico (GOM) reservoir materials and crude oils. Spontaneous imbibition experiments were performed on outcrop cores.
Using a custom DoE optimized for interactions and mixtures, the formulation design space was covered with 162 formulations compared to 576 necessary for a full factorial evaluation. Analysis of the surfactant formulation with the regional specific materials revealed primary components for treatment optimization within each area. With respect to SCF experiments, incorporating proppant, fracturing fluid, and regional specific formation cuttings-to-crude oil combinations revealed that the nature of the crude oil dominated the effects of the surfactant formulations. Data analysis revealed blends that lowered the hydrocarbon/water IFT below 2 mN/M outperformed formulations that resulted in higher IFTs. With respect to EBT, progressing from Bakken to Eagle Ford crude oils, API gravities varied significantly, and these changes in chemical properties greatly impacted the testing results. Formulations with higher concentrations of demulsifier-type components performed better as crude oil API gravities decrease because of increased amounts of asphaltenes, resins, paraffins, and naphthenic acid content. When using the DoE results for ranking of surfactants, experiments in porous media revealed all surfactants formulated through the DoE outperformed the standard offerings by greater than 30% when evaluating the efficacy of the blends to displace oil from cores. However, the addition of some demulsifier-type components to the blends adversely impacted the magnitude of improved hydrocarbon recovery, which was attributed to premature adsorption onto the rock surface.
In an industry where the effect of stimulation chemicals on complex downhole environments remains uncertain, processes to identify the most import factors that impact the performance of chemical additives are of utmost importance. This exercise used statistical software to evaluate multiple complex variables associated with surfactant formulation and suggested blends that improve hydrocarbon recovery.
Kiani, Mojtaba (Nalco Champion, An Ecolab Company) | Hsu, Tzu-Ping (Nalco Champion, An Ecolab Company) | Roostapour, Alireza (Nalco Champion, An Ecolab Company) | Kazempour, Mahdi (Nalco Champion, An Ecolab Company) | Tudor, Eric (Nalco Champion, An Ecolab Company)
Fast production decline in Saskatchewan's tight oil assets has left behind billions of barrels of oil. In the past few years, waterflooding has been utilized to reduce the production decline rate to some extent, however, further optimization in waterflood performance is desired by operators. In this paper, we present our methodology to enhance waterflooding in Saskatchewan's Bakken field, reducing the rate of production decline. This methodology relies upon surfactant-based production enhancement formulations specifically designed to boost waterflood performance. Laboratory experiments and field design are presented to support the assertion that waterflood performance can be enhanced. This approach is one of the earliest of its kind that systematically utilizes the surfactant to enhance water floods in Saskatchewan's assets.
In this paper, we cover the laboratory formulations, fluid-fluid and rock-fluid tests, and the pilot design process. Laboratory work includes formulation development and screening through stability, interfacial tension (IFT) measurement, emulsion tendency and imbibition tests to evaluate the rate of oil recovery against current waterflood. A correlation between IFT and oil recovery was observed and is also discussed. Using a spontaneous imbibition test and our optimized formulations resulted in an additional 35% of original oil in place (OOIP) recovery at 1000 ppm concentration compared to the 20% OOIP oil recovery when placed in brine only. As a result, wettability alteration and IFT reduction were identified as mechanisms that are effective at enhancing incremental oil recovery beyond the secondary brine mode.
After promising laboratory observations, a pilot design area was selected in Saskatchewan. Through a detailed analysis of well communications, breakthroughs, cumulative injection and production volumes, numerical simulation, and economics, a slug size of surfactant solution was proposed. It was identified that our designed treatment could be ineffective to some well patterns with strong frac communications and very short breakthrough times; however, a conformance treatment has been designed for these specific areas. The preliminary laboratory work and design work support the requirements to proceed to the next step of a pilot.
Successful results using this approach demonstrate the potential to increase the amount of recoverable resources in tight oil plays under waterflood.
This work presents a laboratory investigation of miscible ethane foam for gas EOR conformance in low permeability, heterogeneous, harsh environments (<15md, 136,000ppm total dissolved solids with divalent ions, 165°F). The use of ethane as an alternative to CO2 presents several operational and availability strengths which may expand gas EOR applications to depleted or shallower wells. Coupling gas conformance also helps improve displacement efficiencies and maximize overall recovery. Minimum miscibility pressure displacement tests were performed for dead crude oil from the Wolfcamp Spraberry trend area using ethane and carbon dioxide. Aqueous stability, salinity scan, and static foam tests were performed to identify a formulation. Subsequent foam quality and coreflood displacement tests in heterogeneous carbonate outcrop cores were conducted to compare the recovery efficiencies of three processes: a) gravity–unstable, miscible ethane foam; b) gravity–stable, miscible ethane, and; c) gravity– unstable, miscible ethane processes. Slimtube tests comparing ethane to CO2 resulted in a lower MMP value for ethane. We identified a stable surfactant blend capable of Type I microemulsion and persistent foams in the presence of oil. Core floods conducted with gravity-unstable miscible ethane foam, gravity stable miscible ethane, and gravity-unstable miscible ethane recovered 98.4%, 61.9%, and 42.6% OOIP respectively. Our work shows that miscible ethane injection processes result in significant recoveries even under gravity-unstable conditions. The addition of foam further enhances overall recovery at laboratory scale, showing promise for field applications. Unconventional plays present a challenging set of operational conditions which include high temperature, high salinity, low permeability, and fracture networks. Aggressive development of plays and low primary recovery values reveal a potential for enhanced oil recovery methods. Our work demonstrates that miscible ethane foam has the advantage of better conformance control availability that can satisfy these requirements.
Enhanced oil recovery methods have been instrumental in recovering additional oil from reservoirs after primary recovery cycles. Gas injection EOR, in particular, has contributed to the profitable recovery of oil from deep fields with low permeabilities and light to medium oils (Taber et al., 1997). Gas injection processes employ the use of nitrogen, hydrocarbon, or carbon dioxide gases to increase incremental oil recovery; they can be classified as miscible where the important mechanisms of oil displacement are miscibility and interfacial tension (IFT) reduction or immiscible where viscosity reduction and oil swelling play notable roles (Lake et al., 2014). A recent worldwide biennial survey of EOR projects shows carbon dioxide (CO2) and steam EOR as dominant production processes (Moritis, 2010). Miscible CO2 processes in the United States recently eclipsed steam EOR processes at 308,564 b/d compared to steam EOR's 300,762 b/d (Oil & Gas Journal, 2012). Apart from general gas injection issues such as viscous fingering and stability, CO2 flooding has several specific operational drawbacks. Poor selection of metals in production tubing for wells producing from CO2 flooded fields can result in corrosion, delays, and increased capital expenditures due to the presence of carbonic acid in upstream and midstream operations (Kermani and Morshed, 2003). Additionally, the formation of carbonic acid near injectors can cause dissolution and subsequent precipitation of rock minerals and asphaltene precipitation (Marques and Pimentel, 2016). Commercially profitable CO2 EOR projects also require sufficient transport infrastructure as well as vast quantities of naturally available injectant gas (Martin and Taber, 1992).
Integration of time-lapse seismic data into dynamic reservoir model is an efficient process in calibrating reservoir parameters update. The choice of the metric which will measure the misfit between observed data and simulated model has a considerable effect on the history matching process, and then on the optimal ensemble model acquired. History matching using 4D seismic and production data simultaneously is still a challenge due to the nature of the two different type of data (time-series and maps or volumes based).
Conventionally, the formulation used for the misfit is least square, which is widely used for production data matching. Distance measurement based objective functions designed for 4D image comparison have been explored in recent years and has been proven to be reliable. This study explores history matching process by introducing a merged objective function, between the production and the 4D seismic data. The proposed approach in this paper is to make comparable this two type of data (well and seismic) in a unique objective function, which will be optimised, avoiding by then the question of weights. An adaptive evolutionary optimisation algorithm has been used for the history matching loop. Local and global reservoir parameters are perturbed in this process, which include porosity, permeability, net-to-gross, and fault transmissibility.
This production and seismic history matching has been applied on a UKCS field, it shows that a acceptalbe production data matching is achieved while honouring saturation information obtained from 4D seismic surveys.