Accuracy in hydrocarbon reserves estimates affects virtually every phase of the oil and gas business. Unfortunately, reserves estimates are uncertain, since perfect information is seldom available from the reservoir, and uncertainty can complicate the decision-making process. Managers have to make many important decisions early (e.g., facilities expansions, development drilling, etc.) without reliable knowledge of reserves. Thus, it is probably more important to quantify reserves uncertainty early than any other time in the life of a reservoir.
Reserves are closely related to original hydrocarbons in place (OHIP). Two methods for estimating OHIP are volumetric and material balance methods. The volumetric method is convenient to calculate OHIP during the early development period, while the material balance method can be used later, after some performance data, particularly pressure and production information, are available. Both methods may have substantial uncertainty.
In this paper, we present a methodology that uses a Bayesian approach to quantify the uncertainty of original gas in place (G), aquifer productivity index (J), and the volume of the aquifer (Wi) by combining volumetric and material balance analyses in a water-driven gas reservoir.
The results show that we potentially have large uncertainty in OGIP estimates when we consider only volumetric analyses or only material balance analyses. However, by combining the results from both analyses, the uncertainty can be reduced. This reduction in uncertainty should lead to better management decisions in many cases.
The volumetric method is useful in calculating hydrocarbon reserves prior to availability of representative pressure and production data. This method uses static reservoir properties such as area of accumulation, pay thickness, porosity, and initial saturation distribution. Given the often large uncertainty due to paucity of well data early in the reservoir life, it is common to quantify the uncertainty of volumetric estimates of OHIP using statistical methods such as Monte Carlo analysis.
The material balance method can be used later when sufficient amounts of pressure and production data are available. The material balance method is simply an inventory of all materials entering, leaving, and accumulating in the reservoir. Since it relies on different data from the volumetric method, the method can be used as an independent check of volumetric estimates of initial hydrocarbon volumes in place in a reservoir. If the material balance method is properly applied, it can be used to estimate initial hydrocarbon volumes in place, predict future reservoir performance, and predict ultimate hydrocarbon recovery under various types of primary-drive mechanisms. Although uncertainties in material balance methods have been long recognized, they are often considered more accurate than volumetric methods, since they are based on observed performance data. It is not common practice to formally quantify the uncertainty in material balance estimates of OHIP.
Bayes' theorem[2-4] provides a mathematical basis for revising preliminary estimates of reservoir characteristics and their uncertainties when additional information becomes available. Floris et al. applied Bayes' theorem to quantify uncertainty in production forecasts from reservoir models conditioned to both static and dynamic reservoir data. Glimm et al. showed that the Bayesian approach can reduce the uncertainty in the prediction of unknown geological parameters in the simulation of an oil field. Galli et al. used the Bayesian approach to evaluate new information for choosing between different exploitation scenarios for a gas field. Ogele et al. used the Bayesian approach to combine volumetric and material balance methods and quantify uncertainty of OHIP estimates in gas-cap driven oil reservoir. They quantified the uncertainty of two parameters, original oil in place and relative gas-cap size, estimated using the Havlena and Odeh form of the material balance equation.
Coalbed methane (CBM) reservoirs commonly exhibit two-phase flow (gas+water) characteristics, however commercial CBM production is also possible from single-phase (gas) coal reservoirs, as demonstrated by the recent development of the Horseshoe Canyon coals of western Canada. Commercial single-phase CBM production also occurs in some areas of the low-productivity Fruitland Coal, south-southwest of the high-productivity Fruitland Coal Fairway in the San Juan Basin, and in other CBM-producing basins of the continental United States. Production data of single-phase coal reservoirs may be analyzed using traditional techniques commonly used for conventional reservoirs. Complicating application, however, is the complex nature of coal reservoirs; coal gas storage and transport mechanisms differ substantially from conventional reservoirs. In addition, single-phase coal reservoirs may display multi-layer characteristics, dual porosity behavior, permeability anisotropy etc.
The current work illustrates how traditional single-well analysis techniques, such as type-curve and pressure transient analysis, may be altered to analyze single-phase (un-stimulated and hydraulically-fractured) CBM wells. Examples of how reservoir inputs to the type-curves and subsequent calculations are modified to account for CBM reservoir behavior are given. This paper demonstrates, using simulated and field examples, that reasonable reservoir and stimulation estimates can be obtained from production data analysis of coal reservoirs only if appropriate reservoir inputs (i.e. desorption compressibility, fracture porosity) are used in the analysis. As the field examples demonstrate, type-curve and pressure-transient analysis methods for production data analysis are not used in isolation for reservoir property estimation, but rather as a starting point for single- and multi-well reservoir simulation, which is then used to history-match and forecast coal well production (ex. reserves assignment).
Coal reservoirs have the potential for permeability anisotropy because of their naturally-fractured nature, which may complicate production data analysis. To study the effects of permeability anisotropy upon production, a 2-D, single-phase, numerical CBM reservoir simulator was constructed to simulate single-well production assuming various permeability anisotropy ratios. Only large permeability ratios (>16:1) appear to have a significant effect upon single-well production characteristics.
Multi-layer reservoir characteristics may also be observed with coal reservoirs because of vertical heterogeneity, or in cases where the coals are commingled with conventional (sandstone) reservoirs. In these cases, the type-curve and pressure transient analysis techniques are difficult to apply with confidence. Methods and tools for analyzing multi-layer CBM (+sand) reservoirs are presented. Using simulated and field examples, it is demonstrated that unique reservoir properties may be assigned to individual layers from commingled (multi-layer) production in the simple 2-layer case.
Advances in technology, strong energy prices and declining reserves in conventional gas reservoirs are encouraging oil and gas companies to consider the feasibility of exploiting large reserves trapped in tight (low permeability) gas reservoirs.
Conventional well tests conducted on these low permeability gas formations, generally result in poor estimates of key reservoir parameters such as: initial reservoir pressure, permeability, effective fracture length, fracture conductivity, and deliverability potential.
The objective of this paper is to review the different types of tests that are particularly applicable to tight gas formations, discuss why the traditional methods of testing and analysis rarely succeed, and identify appropriate test and analysis procedures for tight gas reservoirs.
We will consider short-term tests where the primary objective is to obtain the initial reservoir pressure, with a secondary objective of determining permeability and skin. Perforation Inflow Tests, Fracture-Calibration Tests, and Formation Flow Tests will be considered. The applicability of these tests will be shown using synthetic and actual field cases.
Slug to annular flow pattern transition (SAT) taking place during the upward gas-liquid well transportation is a source of flow instabilities often experienced with conventional gas lifting as well as with unloading operations of water accumulated at the bottom level of gas wells in low-pressure gas or coalbed reservoirs. In order to minimize the pressure drop and gas compression work, gas lifting of relatively large volumes of fluid (oil and water) uses mainly a slug flow pattern while the production of gas with relatively small amounts of condensate or water (unloading operation) uses an annular flow pattern. In both situations, significant decreasing of tubing pressure from perforation to wellhead levels, is associated to significant increase of superficial gas velocity, may induce flow pattern transitions (usually from bubble to slugs and, further from slugs to annular).
This paper uses field data and laboratory measurements to suggest that SAT can be a source of flow instabilities and should be avoided.
Understanding and proper prediction of SAT is particularly essential for developing suitable production operations and for designing effective gas lifting or unloading strategies from low-pressure gas and oil reservoirs (including upward transportation of hot fluids resulting from steam-assisted heavy oil operations).
With depletion of existing gas reservoirs trend the need for effective gas well deliquification is in great demand. Transportation of water produced at the perforation level (usually between 10-60 m3/d) over a vertical depth of 200 to 2000 m under low (often variable) reservoir pressure (< 50 m of water) ask for finding un-conventional and effective artificial lifting strategies. Improving the understanding of gas-liquid upward transportation mechanisms including the avoidance of instabilities induced by flow pattern transitions is essential.
This paper addresses this problem through laboratory measurements of steady and oscillatory components of flow-pressure under a broad range of gas injected rate and simulated reservoir pressures. Comparison of laboratory data with existing STA models is performed first; selected models are then tested for field situations.
Effective field strategies for avoiding the SAT occurrence using either a slug or an annular flow pattern regime under low-pressure and standard (IPR) reservoir conditions are discussed in view of practical field applications and selection of a suitable gas lifting strategy.
The Oligocene Vicksburg formation in South Texas has been a prolific play for many years with targets of thick and stacked sand bodies. These thick sections have been primarily exploited and produced. Still existing are many previously considered uneconomical sequences. These marginal sections consist of highly laminated sand shale sequences along with disbursed clay in sand. Standard cutoffs from basic log evaluation work correctly for the disbursed clay sections. But the cutoffs are inadequate for the highly laminated sequences; many thin, high-quality sands have been overlooked. These sections can now be discerned using microresistivity measurements in oil-based mud systems and new high-resolution cutoffs can be employed.
A production prediction model is critical to enhance the chance of success. The model used here employs a petrophysically consistent high-resolution permeability estimate, fracture geometry prediction, and formation pressure. The methodology identified several sands as commercial that have been bypassed in offsets with the old cutoffs.
Over a two-year drilling program, data gathered from several field example wells were analyzed. These are presented here to illustrate how production data was utilized to continuously adjust and calibrate the high-resolution petrophysical model. The incremental revenue from the added pay exceeded the cost of this new methodology and enhanced the economic viability of the field.
This integrated process of measurement, analysis, prediction, evaluation, and model adjustment enables the operator in South Texas to make timely completion decisions as well as set-pipe decisions. This process is becoming a useful tool for further exploitation of the mature Oligocene Vicksburg formation of South Texas.
The Vicksburg formation in South Texas has been exploited since the 1920s and is still a prolific producer with over 20 Bcf per year average rate (Fig. 1). The play has seen both productivity increases and declines depending on gas prices and technology drivers. Since the mid-1990s, however, the trend has been ever-decreasing productivity and faster rate declines. At the same time, only 12% of the estimated 3,860 Bcf ultimate recoverable designated tight gas in Vicksburg has been produced, leaving much to be recovered. Some of this recovery can be enhanced with recently developed high-resolution technology.
The decision on whether to set pipe or complete a particular zone usually is made once the logging run is complete. During the standard logging run, the analyst will view the density porosity output and question the economics. "What is the porosity cutoff to make a well here??? The answer is found over years of experience and the school of hard knocks. Typically a "Rule of Thumb?? is used and a line is drawn (Fig. 2). Many South Texas partners make their decisions based on these cutoffs and individual experience. Worthington gives a comprehensive perspective on the use of these cutoffs. The cutoff number most often used in the Oligocene Vicksburg trend of South Texas is 15-16% porosity (Fig. 2). More recently there has been success at much lower porosity in the range of 8-10%. Obviously, if a 16% porosity cutoff was applied routinely, then somewhere in the thousands of wells drilled, some pay has been bypassed.
One solution that has been used primarily in water-based systems has been laminated sand analysis. This type of analysis has been applied since the early 1990s primarily in turbidite plays and not verified with production. The analysis used here verified with production data, provides a better answer for the less obvious and often bypassed pay sands.
A new fracture-injection/falloff type-curve analysis method is presented for reservoirs containing slightly compressible and compressible fluids. Type-curve analysis augments conventional before- and after-closure methods, which are also reformulated in terms of adjusted pseudopressure and adjusted pseudotime to account for compressible reservoir fluids. Unlike before- and after-closure methods which only apply to specific (i.e., small) portions of the falloff data, the new type-curve method allows for analyzing all falloff data from the end of the injection through fracture closure, pseudolinear flow, and pseudoradial flow. Similar to conventional well test analysis, a satisfactory interpretation requires comparable and consistent results between the special analysis methods, before- and after-closure, and type-curve analysis.
A new method of completing multiple-layer tight gas wells is being investigated. The main concept is to place sliding sleeve valves in the casing string and complete the well with normal cementing operations. The sliding sleeves would then be opened one at a time to fracture layers independently without perforating. The possibility of high fracture initiation pressures is identified as the main risk with this approach.
This paper will discuss the theoretical and experimental study that was conducted to assess the viability of the cemented sliding sleeve concept by attempting to minimize and predict fracture initiation pressures.
Finite Element Analysis (FEA) was conducted to estimate the stresses in the cement and formation near the wellbore with sliding sleeve. FEA was used to adjust valve parameters that increased tensile stress in the cement and formation. Unstressed cement tests were then conducted on a variety of sliding sleeve valve shapes to verify the FEA study and to select the best valve shape.
Openhole and perforated casing fracture initiation pressures were calculated as a function of rock properties and far field stresses on the rock. An openhole condition was considered the best approximation to the opened sliding sleeve valve in regards to fracture initiation.
Full-scale stress frame tests were conducted using sandstone blocks with far field stress applied. The base case was set up using 4-1/2-in diameter casing cemented in one block and then perforated in the preferred fracture plane. Another sandstone block had a sliding sleeve valve cemented in place. Water was used to fracture these blocks and the fracture initiation pressures were measured. Good agreement between predictions and measurements was obtained, and the results indicated that high fracture initiation pressure is unlikely to be an issue with this completion method.
Bedded salt formations are located throughout the United States, providing valuable storage capacity for natural gas and other hydrocarbons. In order to increase gas storage capabilities and provide operators with improved geotechnical design and operating guidelines for these caverns, stability analyses of single bedded salt cavern have been completed and are described in this paper. This work is a part of integrated efforts initiated and sponsored by the US Department of Energy, Gas Technology Institute, and Pipeline Research Council International, Inc.
Numerical geomechanical models have been developed to investigate single cavern deformation and bedding plane slip for a variety of cavern configurations. A viscoplastic salt model has been developed based on an empirical creep law developed for the Waste Isolation Pilot Plant (WIPP) Program and combined with a Drucker-Prager model for damage and failure. The non-salt materials are described with either a traditional Mohr-Coulomb model, or an elastic model, depending on layer properties.
A baseline model with specified geometric dimensions is first selected and subjected to one year cyclic pressure operations. The amount of damage around the cavern wall and roof is evaluated and used as a comparison in the study. Then the operations are extended to 15 years to study cavern stability for long term gas storage and operations. In addition to the baseline model, parametric studies have been performed to investigate cavern damage as a function of salt roof thickness, overburden stiffness, interface properties, and cavern geometries. Each cavern simulation includes one year of pressure cycling with a minimum, mean, and maximum cavern pressure of 6.1 MPa (884.5 psi), 8.8 MPa (1276 psi) and 14.9 MPa (2160.5 psi), respectively. Different operation conditions, e.g. hydrostatic, cyclic, and a direct pressure drawdown, are compared and evaluated in terms of cavern stability.
These analyses can serve as a basis to select the best salt cavern candidate for gas storage and operations. They can also help to assess critical cavern design parameters for thin bedded salt formations.
Hernandez, Gonzalo (Texas A&M University) | Bello, Rasheed Olusehun (Texas A&M University) | McVay, Duane Allen (Anadarko Petroleum Corp.) | Ayers, Walter Barton (Anadarko Petroleum Corp.) | Rushing, Jay Alan (Anadarko Petroleum Corp.) | Ruhl, Stephen K. (Texas A&M University) | Hoffmann, Michael F. | Ramazanova, Rahila I.
Carbon dioxide (CO2) from energy consumption is a primary source of anthropogenic greenhouse gas. Injection of CO2 in coalbeds is a plausible method of reducing atmospheric emissions, and it can have the additional benefit of enhancing methane recovery from coal. Most previous studies have evaluated the merits of CO2 disposal in high-rank coals. The objective of this research is to determine the technical and economic feasibility of CO2 sequestration in, and enhanced coalbed methane (ECBM) recovery from, low-rank coals in the Texas Gulf Coast area. Our research included an extensive coal characterization program, deterministic and probabilistic simulation studies, and economic evaluations. We evaluated both CO2 and flue gas injection scenarios.
In this study coal core samples and well transient test data were obtained for characterization of Texas low-rank coals. Simulation studies evaluated the effects of well spacing, injectant fluid composition, injection rate, and dewatering on CO2 sequestration and ECBM recovery.
Probabilistic simulation of 100% CO2 injection in an 80-acre 5-spot pattern indicate that these coals can store 1.27 to 2.25 Bcf of CO2 with an ECBM recovery of 0.48 to 0.85 Bcf. Simulation results of 50% CO2 - 50% N2 injection in the same 80-acre 5-spot pattern indicate that these coals can store 0.86 to 1.52 Bcf of CO2, with an ECBM recovery of 0.62 to 1.10 Bcf. Simulation results of flue gas injection (87% N2 - 13% CO2) indicate that these same coals can store 0.34 to 0.59 Bcf of CO2 at depths of 6,200 ft, with an ECBM recovery of 0.68 to 1.20 Bcf.
Economic modeling of CO2 sequestration and ECBM recovery for 100% CO2 injection indicates predominately negative economic indicators for the reservoir depths and well spacings investigated, using natural gas prices ranging from $2 to $12 per Mscf and CO2 credits based on carbon market prices ranging from $0.05 to $1.58 per Mscf CO2 ($1.00 to $30.00 per ton CO2). Injection of flue gas (87% N2 - 13% CO2) results in better economic performance than injection of 100% CO2.
Moderate increases in either gas prices or carbon credits could generate attractive economic conditions that, combined with the close proximity of many CO2 point sources near unmineable coalbeds, could generate significant CO2 sequestration and ECBM potential in Texas low-rank coals.
Gas production and transportation pose challenges for operators. Unprocessed gas streams in production and flow lines containing brine and hydrogen sulfide are particularly corrosive and susceptible to forming hydrates and scale deposits. Methanol is often added to such streams for hydrate prevention; however, methanol increases the corrosion tendencies of pipes and equipment because it can deactivate some Corrosion Inhibitors (CI) and adds oxygen to the system. As a result, if hydrates are controlled with methanol, the system requires extra amounts of properly selected corrosion inhibitors to counteract the oxygen induced accelerated corrosion.
Corrosion rates of tubular steel exposed to sweet and sour brines were investigated. The sweet conditions contained carbon dioxide saturated brine, methanol, corrosion and gas hydrate inhibitors. Hydrogen sulfide was added to the system to create a sour environment. Methanol and hydrogen sulfide present in wet gas streams create an environment difficult for corrosion control; they accelerate corrosion rates to the point of rendering some commercial corrosion inhibitors unsuitable for corrosion protection. It was discovered that some gas hydrate inhibitors offer both, hydrates and corrosion protection. In addition it was found that the corrosion inhibiting properties of these gas hydrate inhibitors were enhanced in the presence of hydrogen sulfide.
The dual action of the Low Dosage Hydrate Inhibitor (LDHI) described here can limit or even eliminate Corrosion Inhibitors in highly corrosive methanol containing sour gas/water streams; thus, LDHI application improves production and transportation economy by replacing high volumes of methanol with less costly volumes of LDHI and providing additional operational savings on CI.
Gas hydrates form when water molecules crystallize around guest molecules. The water/guest crystallization process has been recognized since its discovery by Sir Humphrey Davy in 1810 it is well characterized and occurs with sufficient combination of pressure and temperature. Light hydrocarbons, methane-to-heptanes, nitrogen, carbon dioxide and hydrogen sulfide are the guest molecules of interest to the natural gas industry. Depending on the pressure and gas composition, gas hydrates may build up at any place where water coexists with natural gas at temperatures as high as 30°C (~85ºF).
Formation of undesired gas hydrates can be eliminated or hindered by several methods. The thermodynamic prevention methods control or eliminate elements necessary for hydrate formation: the presence of hydrate forming gas, the presence of water, high pressure and low temperature. The elimination of any one of these four elements from the system would preclude the formation of hydrates. Heating and insulating transmission lines is a common mechanical solution to the hydrate problem often encountered in long subsea pipelines. Gas dehydration is another method of removing a hydrate component. However, in a practical oil and gas operation, water can be economically removed to a certain minimum vapor pressure only and residual water vapors are always present in a dry gas. Hydrate plugs in "dry" gas lines have been reported in the past.
Tubular failures due to corrosion and pipelines plugging with solid hydrates are major concerns for gas production and transport operators. Hydrate plugs can form in a short time, often within a few hours at hydrate formation pressure and temperature (p/T) conditions. Corrosion is a significantly slower process taking months or years to manifest itself with hardware failing. Nevertheless, both processes can result in catastrophic consequences if left unchecked.