It is evident that the oil and gas industry has moved from the adoption phase of intelligent fields and that the value added enabled developing and sustaining more production from complex wells. This observation is supported by various operators' experiences with intelligent fields that have been shared in many conferences and workshops.
Haradh Increment-III (HRDH-III) is Saudi Aramco's first full field development as an intelligent field. This development has provided great utility in maintaining production plateau, very low water cut and a better-than-expected field performance. During the first few years of HRDH-III operation, numerous examples have been highlighted on the company's experience with intelligent fields and the benefits realized. At that time, we were still at the early phase in the innovation stage where applications were mostly on individual wells creating value at an individual asset level.
In the pre-injection stage (6 months before the field production start up), real time data enabled identifying an area in HRDH-III field characterized by high permeability zones because of the presence of faults and fractures. This paper picks up where previous papers stopped, giving more details on production engineering experiences in optimizing the production from this area of the field and controlling water production. The paper presents the company's continued
success in utilizing intelligent fields to meet and sustain production targets and shows how we have been moving up the curve from individual assets to a regional level.
The lessons learned from this field case will help in developing best practices that boost the confidence in intelligent fields. Also, it will assure that we are on the right track for the transformation to the sustainability stage of our intelligent field applications.
Recently a new coiled tubing technology has been used to clean out horizontal wellbores with a low downhole pressure. This technique uses a dual coiled tubing string and a special vacuum tool designed to create a pressure drop across the formation sand face in order to clean out formation fines, unwanted fluids and solids. The work string, used for this application, has a rectangular matrix design; the two 1-1/2??coiled tubing strings are encapsulated into one uniform body using a high strength thermoplastic jacket. The power fluid is circulated down through one of the strings and the returns, including fines and solids, are transported to surface, up the second string. To operate the system, a custom coiled tubing reel, with two rotating joints was designed. The fluid goes through a jet pump (BHA), where it passes through a nozzle creating a "Venturi effect??. New software has been developed to simulate the torque and drag, given that the cross section area is similar to a rectangle and it has two contact points, instead of one. A hydraulic simulation has been performed to determine the jet pump performance, circulation rates and pressures. Real time data was used to calibrate the models.
The technology has been used for liner clean outs, in horizontal heavy oil (8 API) wells, with low pressure averaging 362 psi at 2625 ft (2.5 MPa; 800 m TVD; ) reservoirs.
In the first well, 656 feet (200 meters) of 5-1/2?? horizontal slotted liner was cleaned out down to 3008 feet (916 meters) and 4.7 barrels (745 liters) of sand were circulated out to surface (30% of the total internal volume). In the first well the production was recovered from an initial rate 6 bbls/day to 31 bbls/day (1 m3/day to 5 m3/day). In the second well, with 5% H2S, the dual coiled tubing was run in the 4-1/2?? production tubing and the 4-1/2?? horizontal slotted liner was cleaned out down to 3550 feet (1082 meters).
Based on the results, this technology is proven to be a viable solution for cleaning long horizontal wells with low bottom hole pressures.
The objective of this study was to conduct a modeling study to determine the production performance of multiply fractured horizontal well completed in Shale formations and to investigate the impact of hydraulic fractures on the production performance of horizontal wells in ultra-low permeability formations. A commercial reservoir simulator was utilized to model both single and a dual porosity reservoir since both hydraulic fractures and natural fractures play significant roles in well
performance of the low permeability reservoirs. The adsorbed gas component was also included in the models. The single and a dual porosity models were utilized to investigate the flow regimes for horizontal wells with multi-stages of hydraulic fracturing stimulation. History matching with actual production from Marcellus Shale wells was utilized to determine the basic model parameters. The results indicated the presence of number of different flow regimes. The hydraulic fractures appear to dominate the early production performance. The impact of reservoir and hydraulic fracture parameters on the flow regimes as well as the production performance and gas desorption were also investigated. The results can be utilized to investigate the feasibility horizontal wells with multiple hydraulic fractures and optimize the production from the shale formations.
Horizontal wells with multiple hydraulic fractures have been used widely in the oil and gas industry. In published literatures, hydraulic fractures are assumed to be fully penetrating the formations. Recent studies have shown that partially penetrating fractures are more likely to occur rather than fully penetrating fractures
The purpose of this study is to formulate an analytical model describing the pressure behavior of a horizontal well with partially penetrating hydraulic fractures. This model is used to develop a technique, based on pressure and pressure derivative concept, for interpreting pressure transient tests and forecasting productivity of the well. The fractures in this study were assumed to propagate in an infinite homogenous porous system. Further more, the fractures were assumed to be vertical and inclined. Six main flow regimes can be observed for hydraulic fractures: linear, early radial, second linear, intermediate radial, third linear or elliptical and pseudo-radial flow. Early radial flow represents the radial flow around each fracture may develop for the cases of small penetrating rate. Intermediate radial flow is expected to develop for the case of wide spacing between fractures. Third linear flow may develop for the case of high number of fracture with short spacing between them.
Tiab's Direct Synthesis (TDS) technique has been applied using the plots of the pressure and pressure derivative curves. Several unique features of the pressure and pressure derivative plots of partially penetrating fractures models were identified including the points of intersection of straight lines for different flow regimes. These points can be used to verify the results or to calculate unknown parameters. Equations associated with these features were derived and their usefulness was demonstrated. A step-by-step procedure for analyzing pressure tests is included in this paper and illustrated by several numerical examples.
This paper presents a new set of type curves for pressure transient analysis of composite dual-porosity systems. The composite, double-porosity system studied in this paper represents shale gas reservoirs with multistage hydraulically fractured horizontal wells. Upon hydraulic fracturing of horizontal wells, it is critically important to determine the permeability and extent of artificially induced fractures. In this study, it is shown that these properties can be calculated by using the type curves presented in this study. In addition to the permeability and extent of hydraulic fractures, dual-porosity dimensionless parameters of the hydraulically fractured region can also be calculated using these type curves. It is shown that type curves developed in this study provide accurate results via analysis of the pressure transient drawdown data. A case study is presented to validate and show the application of the type curves.
Proppants are essential to the success of most hydraulic fractures and often account for a significant portion of the cost of the treatment. Both the mass of proppant and the selection of the right type of proppant are critical elements in gaining the highest Net Present Value (NPV).
It has been generally believed that in a lower closure stress environment (below 6,000 psi, i.e., shallow reservoirs), natural sands such as Brady and Ottawa types are appropriate as proppants and, for the same mesh size, they provide essentially the same permeability. Commonly accepted notion is that manmade proppants (such as ceramics) should be applied at higher closure stress environment, invariably deeper reservoirs.
According to the characteristics of Eagle Ford shale, which include the rock stiffness, exemplified by Young's Modulus, stress anisotropy or isotropy and the existence of a natural fracture network, this study presents fracture designs based on three types of proppants for both shale formations: Brady sand, Ottawa sand and man-made ceramic. Permeability tests and crush tests under certain pressure ranges are done to determine experimentally the dimensioned fracture conductivity. Although natural proppants may exhibit lower permeability, a fracture optimization p-3D model is used to remedy the lower proppant permeability and maximize well performance by optimizing fracture geometry, including fracture half length, width and height. Reduced proppant pack permeability is compensated by larger width. Non-Darcy effects in the fracture are also considered for gas reservoirs. Post-treatment well performance is then estimated, using the optimized well geometry, leading to cumulative production estimates over the well life. Finally, a NPV analysis is employed as the criterion to select the best proppant for the job.
In this study, we show there is an optimum Proppant Number corresponding to maximum NPV for various reservoir permeabilities. Based on that notion, we propose a systematic way of choosing proppant type and mass to maximize NPV in oil reservoirs. For tight gas reservoirs, we correct the prejudice that natural sand proppants cannot be applied to deeper reservoirs by showing NPV study results that are superior to those of manmade proppants. By keeping stimulation costs down, natural sand proppants have a much larger range of applicability than previously thought.
Gas or steam gravity drainage is a very efficient recovery mechanism. Field observations, laboratory studies and pore network modeling have pointed towards very low residual oil saturations and high recovery with gravity drainage. While work during the last three decades has focused on understanding the physics of three??phase flow, literature on field scale gravity drainage production decline characteristics is somewhat limited. Understanding field level production decline characteristics is important as it enables better production forecasting, resource estimation and reservoir management.
In this paper production data from two fields under gravity drainage is evaluated and it shows strong exponential decline characteristics. After an initial period of rapid decline, there is a period of lower decline for a long period of time. The paper relates field scale observations of gravity drainage to laboratory observations of gravity drainage in long cores. The laboratory experiments show similar behaviors where a period of initial rapid decline is followed by a long period of lower
decline, resulting in very low remaining oil saturation in the gas invaded zone. The paper discusses physics of gravity drainage displacement and summarizes similarities and differences between field and laboratory observations.
Accurate modeling of multi-fracture horizontal shale gas wells is the holy grail of shale gas reservoirs. Modeling shale gas wells is difficult because of the lack of subsurface data and inability to model correct physics. Some of the biggest uncertainties in shale gas reservoirs are the length of fractures, existing natural fracture network, matrix permeability, adsorption, and size of stimulated rock volume (SRV). Numerous techniques are used to reduce these uncertainties, such as Diagnostic Fracture Injection Test (DFIT), micro-seismic monitoring and Special Core Analysis (SCAL).
In this paper we present a new numerical approach to model multi-fracture shale gas wells. The problem is simplified in terms of modeling the natural fracture network intersected by the induced fractures by creating a SRV around the well with size and permeability of the SRV used as uncertainty parameters. Individual fracture stages are modeled explicitly by utilizing logarithmic local grid refinement (LGR).
We apply this methodology to two field cases. First case corresponds to a multi-fracture shale gas well in Oklahoma. A detailed design of experiment study is also performed to identify main uncertainties and generate a probabilistic production forecast. Numerical simulation model, coupled with an in-house probabilistic tool, is used for this study. Second case corresponds to shale gas horizontal well in east Texas. Daily production and pressure data is history matched using a numerical model. History matching provided us with great insight and better understanding of different uncertainty parameters and how they affect early to late production of horizontal shale gas wells.
The industry's approach on SAGD injector well completion design is evolving in complexity by increasing the amount of steam-outflow distribution points along the horizontal wellbore. The main drivers in this evolution process are improved steam conformance and uniform chamber growth. Despite this trend, there are not many technical papers covering the criteria for selecting steam outflow locations, quantity and steam flow rate ratio at each distribution point.
This paper describes a case study of a SAGD injector well completion design comprised of two parallel strings and multiple outflow control devices placed along the well's long string. We modeled the steam outflow profile into the reservoir with a commercial thermal wellbore simulator, which is coupled to a series of reservoir cells along the horizontal wellbore.
We based the preliminary completion design on the subsurface parameters that control steam flow into the reservoir (i.e. permeability, thickness, bitumen saturation, etc.). We derived these parameters from an up-to-date geological model based on core data, open-hole logs and cuttings analysis. At the end of the well's circulation phase, we ran a series of temperature falloff logs from planned shut-in periods. We used fiber optic and thermocouple temperature data sets to perform thermal transient analysis, which allowed identifying the location of local/preliminary steam chambers and fingering phenomena. This diagnostic analysis generated a revision on the well's preliminary completion design and steam outflow reservoir parameters.
We carried out a final design using real SAGD performance data obtained from thermal transient analysis. The design objective was to negate the uncharacteristic steam chamber growth features, developed during the circulation phase, to promote uniform development along the wellbore. This paper provides a methodology and criteria for SAGD injector completion design that can be broadly applied across the industry, integrating wellbore hydraulics, reservoir properties and thermal transient analysis into the design process.
This paper summarizes experimental results of air injection process using dual horizontal well pattern. Experiments were conducted using a three dimensional laboratory model. Canadian heavy oil sample was used to conduct the experiments at 180 psia. The combustion cell was fitted with 48 thermocouples to measure the temperatures in the model and to monitor the combustion front propagation. Laboratory results were analyzed to study the feasibility of combustion assisted gravity drainage (CAGD) process and determine the key parameters. In this technique, horizontal injector was placed at the top Layer of sand pack and used for injection of enriched air. Mobilized oil and flue gases were produced through horizontal production well at the bottom of the cell.
An important feature of CAGD process is the properly oriented dual horizontal wells that assist in development of combustion chamber and stabilized growth of the combustion front in the reservoir. Temperature profile showed that combustion chamber first developed near injection side of the model and then propagated in forward direction during the experiment. Peak temperature of about 530 ºC was recorded. Post experiment sand pack analysis confirmed that coke deposition resulted in formation of gas seal barrier between injector and producer which enhances the circulation of the injected air in the combustion chamber. Ultimate oil recovery estimated about 72% OOIP and thermal upgrading was near 3 ºAPI enhancement in produced oil density.